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

OR

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

For the transition period from ________________ to ___________________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-3016	WISCONSIN PUBLIC SERVICE CORPORATION	39-0715160
	(A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 800-450-7260

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

None

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 [ ]    No [X]

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

Yes [ ]    No [X]

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

Yes [X]    No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X]    No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

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

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

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

Yes [ ]    No [X]

As of June 30, 2015 (and currently), all of the common stock of Wisconsin Public Service Corporation is held by Integrys Holding, Inc., a wholly owned subsidiary of WEC Energy Group, Inc.

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

None.

Number of shares outstanding of each class of common stock, as of

January 31, 2016

Common Stock, $4 par value, 23,896,962 shares outstanding

The Registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format.

WISCONSIN PUBLIC SERVICE CORPORATION

ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2015

TABLE OF CONTENTS

					Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION					1
PART I					3
ITEM 1.	BUSINESS				3
	A.	INTRODUCTION			3
	B.	UTILITY OPERATIONS			3
	C.	NON-UTILITY OPERATIONS			11
	D.	REGULATION			11
	E.	ENVIRONMENTAL COMPLIANCE			13
	F.	EMPLOYEES			14
ITEM 1A.	RISK FACTORS				15
ITEM 1B.	UNRESOLVED STAFF COMMENTS				23
ITEM 2.	PROPERTIES				24
ITEM 3.	LEGAL PROCEEDINGS				25
ITEM 4.	MINE SAFETY DISCLOSURE				25
PART II					26
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				26
ITEM 6.	SELECTED FINANCIAL DATA				26
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				27
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				46
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				47
	A.	Report of Independent Registered Public Accounting Firm			47
	B.	Consolidated Income Statements			48
	C.	Consolidated Balance Sheets			49
	D.	Consolidated Statements of Cash Flows			50
	E.	Consolidated Statements of Equity			51
	F.	Consolidated Statements of Capitalization			52
	G.	Notes to Consolidated Financial Statements			53
		Note 1	Summary of Significant Accounting Policies	53
		Note 2	Merger	58
		Note 3	Acquisition	58
		Note 4	Related Parties	59
		Note 5	Supplemental Cash Flow Information	61
		Note 6	Regulatory Assets and Liabilities	62
		Note 7	Property, Plant, and Equipment	63
		Note 8	Jointly Owned Utility Facilities	64
		Note 9	Asset Retirement Obligations	64
		Note 10	Goodwill and Other Intangible Assets	64
		Note 11	Common Equity	65
		Note 12	Preferred Stock	66
		Note 13	Short-Term Debt and Lines of Credit	66
		Note 14	Long-Term Debt	67
		Note 15	Income Taxes	68
		Note 16	Guarantees	69

2015 Form 10-K i Wisconsin Public Service Corporation

		Note 17	Employee Benefits	69
		Note 18	Commitments and Contingencies	74
		Note 19	Fair Value Measurements	80
		Note 20	Derivative Instruments	81
		Note 21	Regulatory Environment	82
		Note 22	Segment Information	84
		Note 23	Quarterly Financial Information (Unaudited)	85
		Note 24	New Accounting Pronouncements	85
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				86
ITEM 9A.	CONTROLS AND PROCEDURES				86
ITEM 9B.	OTHER INFORMATION				86
PART III					87
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE				87
ITEM 11.	EXECUTIVE COMPENSATION				87
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				87
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				87
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES				87
PART IV					89
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				89
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS					90
SIGNATURES					91
EXHIBIT INDEX					92

2015 Form 10-K ii Wisconsin Public Service Corporation

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
IES	Integrys Energy Services, Inc.
Integrys	Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
ITF	Integrys Transportation Fuels, LLC
UPPCO	Upper Peninsula Power Company
WBS	WEC Business Services LLC
WEC Energy Group	WEC Energy Group, Inc. (previously known as Wisconsin Energy Corporation)
Wisconsin Electric	Wisconsin Electric Power Company
WPS	Wisconsin Public Service Corporation
WRPC	Wisconsin River Power Company
Federal and State Regulatory Agencies
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	United States Internal Revenue Service
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Accounting Terms
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

2015 Form 10-K iii Wisconsin Public Service Corporation

Measurements
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
CPCN	Certificate of Public Convenience and Necessity
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
GCRM	Gas Cost Recovery Mechanism
LMP	Locational Marginal Price
Merger Agreement	Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Market
N/A	Not Applicable
NYMEX	New York Mercantile Exchange
ROE	Return on Equity
RTO	Regional Transmission Organization
SSR	System Support Resource

2015 Form 10-K iv Wisconsin Public Service Corporation

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, liquidity and capital resources, and other matters.

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

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

• Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

• The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated businesses;

• The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

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

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

• Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

• The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

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

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

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

2015 Form 10-K 1 Wisconsin Public Service Corporation

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

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

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

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

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

2015 Form 10-K 2 Wisconsin Public Service Corporation

PART I

ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "us," "we," "our," or "ours," we are referring to WPS. The term "utility" refers to our regulated activities, while the term "non-utility" refers to our activities that are not regulated, as well as the activities of our subsidiary, WPS Leasing. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 

10-K.

We are a Wisconsin corporation and an indirect wholly owned subsidiary of WEC Energy Group. We began operations in 1883. We are an electric and natural gas utility company serving an approximate 12,000-square-mile service territory in northeastern Wisconsin and Michigan's Upper Peninsula. Our three reportable segments are electric utility, natural gas utility, and other. In 2015, electric revenues accounted for 80% of our total utility revenues, while natural gas revenues accounted for 20% of our total utility revenues.

For more information about our electric and natural gas utility operations, including financial and geographic information, see Note 22, Segment Information, and Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Merger

On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of our parent company, Integrys, and changed its name to WEC Energy Group, Inc. In this report, when we refer to the "WEC Merger," we are referring to this acquisition. For additional information on this merger, see Note 2, Merger.

Available Information

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

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

B. UTILITY OPERATIONS

ELECTRIC UTILITY SEGMENT

Our electric utility generates and distributes electric energy to customers located in northeastern Wisconsin and Michigan's Upper Peninsula.

2015 Form 10-K 3 Wisconsin Public Service Corporation

Electric Utility Operating Statistics

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

	Year Ended December 31
	2015			2014		2013
Operating revenues (in millions)
Residential	$	372.0		$	366.4	$	371.2
Small commercial and industrial	382.2			366.5		364.2
Large commercial and industrial	251.9			241.6		245.1
Other	9.5			9.5		9.5
Total retail revenues	1,015.6			984.0		990.0
Wholesale	155.8			163.5		159.3
Resale	37.7			37.0		85.9
Other operating revenues (1)	(21.6		)	38.9		7.7
Total	1,187.5			1,223.4		1,242.9
Electric customer choice (2)	0.3			0.3		0.1
Total operating revenues	$	1,187.8		$	1,223.7	$	1,243.0
Customers – end of year (in thousands)
Residential	393.3			391.2		389.6
Small commercial and industrial	55.1			55.1		54.9
Large commercial and industrial	0.3			0.3		0.3
Other	0.5			0.6		0.6
Total customers	449.2			447.2		445.4
Customers – average (in thousands)	447.9			445.8		443.9

⁽¹⁾  Includes amounts (refunded to) collected from customers for certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.

⁽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 85.5% of total electric operating revenues, while wholesale (including resale) electric revenues accounted for 16.3% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Electric Utility Segment Contribution to Operating Income for information on MWh sales by customer class.

We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.

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

Large Electric Retail Customers

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

2015 Form 10-K 4 Wisconsin Public Service Corporation

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 18.2%, 19.3%, and 17.7% of total electric energy sales during 2015, 2014, and 2013, respectively. Wholesale revenues accounted for 13.1%, 13.4%, and 12.8% 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 6.4%, 4.2%, and 12.8% of total electric energy sales during 2015, 2014, and 2013, respectively. Resale revenues accounted for 3.2%, 3.0%, and 6.9% 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 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 to grow at a compound annual rate of between flat to 0.5% over the next five years, also assuming normal weather.

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 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	1,366	1,596	1,596
Natural gas:
Combined cycle	554	551	556
Steam turbine (2)	65	—	—
Natural gas/oil peaking units (3)	450	430	464
Renewables (4)	82	83	82
Total rated capacity by fuel type	2,517	2,660	2,698

⁽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 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 and wind generation.

2015 Form 10-K 5 Wisconsin Public Service Corporation

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	42.6	%	40.1	%	48.8	%	54.2	%
Natural gas:
Combined cycle	27.4	%	23.9	%	10.8	%	11.0	%
Steam turbine	—	%	1.1	%	0.3	%	0.3	%
Natural gas/oil peaking units	—	%	0.2	%	0.5	%	1.0	%
Renewables	4.7	%	4.0	%	5.2	%	3.3	%
Total company-owned generation units	74.7	%	69.3	%	65.6	%	69.8	%
Power purchase contracts:
Nuclear	—	%	—	%	—	%	17.5	%
Renewables	4.5	%	3.2	%	3.6	%	3.9	%
Other *	9.0	%	17.1	%	10.6	%	7.2	%
Total power purchase contracts	13.5	%	20.3	%	14.2	%	28.6	%
Purchased power from MISO	11.8	%	10.4	%	20.2	%	1.6	%
Total purchased power	25.3	%	30.7	%	34.4	%	30.2	%
Total electric utility supply	100.0	%	100.0	%	100.0	%	100.0	%

* Represents system energy and capacity purchases used to meet customer requirements and certain FERC regulations.

Coal-Fired Generation

Our coal-fired generation consists of four operating plants with a rated capacity of 1,366 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 five operating plants, including peaking units, with a rated capacity of 1,069 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 a combustion turbine at one of our natural gas-fired plants, a WRPC jointly-owned unit, which did not have a rated capacity at December 31, 2015. We also have natural gas-fired peaking units with a rated capacity of 435 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 17 operating plants with a total installed capacity of 82 MW and a rated capacity of 60 MW as of December 31, 2015. All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have two wind sites, consisting of 80 turbines, with an installed capacity of 108 MW and a rated capacity of 22 MW as of December 31, 2015.

2015 Form 10-K 6 Wisconsin Public Service Corporation

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 year ended December 31:

	2015		2014		2013
Coal	$	28.28	$	26.34	$	26.58
Natural gas combined cycle	21.10		38.36		32.84
Natural gas/oil peaking units	160.86		296.83		411.06
Purchased power	42.30		40.05		43.99

We purchase coal under long-term contracts, which helps with price stability. Coal and associated transportation services have continued to see volatility in pricing due to changing domestic and world-wide demand for coal and the impacts of diesel costs, which are incorporated into fuel surcharges on rail transportation. Certain of our coal transportation contracts contain fuel cost adjustments that are tied to changes in diesel fuel and crude oil prices. Currently, diesel fuel contracts are not actively traded. Therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices.

We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage.

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

Coal Supply

We diversify the coal supply for our electric generating facilities and jointly-owned plants by purchasing coal from several mines in Wyoming, as well as from various other states. For 2016, approximately 57% of our total projected coal requirements of approximately 4 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.

2015 Form 10-K 7 Wisconsin Public Service Corporation

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

(in thousands)	Annual Tonnage
2016	3,303
2017	2,337
2018	1,569

Coal Deliveries

All of our 2016 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facilities. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.

Midcontinent Independent System Operator Costs

In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy markets and ancillary services market. We are a participant in the MISO Energy Markets. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas, and Missouri, a region referred to as MISO South. These changes have not had a material impact on our allocation of transmission costs, and we do not expect them to have a material impact in the future. For more information on MISO, see Item 1. Business – 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 165 MW per year.

Other Matters

Seasonality

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

Competition

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

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

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

2015 Form 10-K 8 Wisconsin Public Service Corporation

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 SEGMENT

We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We also transport customer-owned natural gas. Our natural gas utility provides service to customers located in northeastern Wisconsin and Michigan's Upper Peninsula.

Natural Gas Utility Operating Statistics

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

	Year Ended December 31
	2015		2014		2013
Operating revenues (in millions)
Residential	$	182.6	$	289.2	$	213.7
Commercial and industrial	92.3		155.7		109.1
Total retail revenues	274.9		444.9		322.8
Transport	16.7		17.0		16.1
Other operating revenues	14.6		10.4		9.5
Total	$	306.2	$	472.3	$	348.4
Customers – end of year (in thousands)
Residential	297.9		295.8		293.5
Commercial and industrial	29.5		29.2		29.0
Transport	0.7		0.7		0.7
Total customers	328.1		325.7		323.2
Customers – average (in thousands)	326.6		323.8		321.6

Natural Gas Deliveries

Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately 46.3% of the total volumes delivered during 2015, 43.0% during 2014, and 43.8% during 2013. Our peak daily send-out during 2015 was 5.6 million therms on January 7, 2015.

Large Natural Gas Customers

We provide natural gas utility service to a diversified base of customers in such industries as paper, food products, educational, governmental, and health services.

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 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.

2015 Form 10-K 9 Wisconsin Public Service Corporation

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

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our natural gas utilities' forecasted design peak-day throughput is 6.9 million therms for the 2015 through 2016 heating season.

The sources of our deliveries to customers (including transportation customers) were as follows:

(in million therms)	2015		2014		2013
Natural gas purchases	450.4		514.3		450.7
Customer-owned natural gas received	358.5		358.0		353.0
Underground storage, net	(18.8	)	(19.4	)	16.3
Contracted pipeline and storage compressor fuel, franchise requirements, and      unaccounted-for natural gas	(1.8	)	2.3		2.6
Total	788.3		855.2		822.6

Secondary Market Transactions

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

Spot Market Natural Gas Supply

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

Hedging Natural Gas Supply Prices

We have PSCW approval to hedge up to 67% of planned winter demand using a combination of planned withdrawals from storage and NYMEX financial instruments. This approval allows us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through our GCRM. Hedge targets (volumes) are provided annually to the PSCW as part of our three-year natural gas supply plan and risk management filing.

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

2015 Form 10-K 10 Wisconsin Public Service Corporation

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 heavily 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.

C. NON-UTILITY OPERATIONS

OTHER SEGMENT

The other segment includes our non-utility activities as well as equity earnings from our investments in WRPC and WPS Investments, LLC. WPS Investments is an indirect wholly owned subsidiary of WEC Energy Group that is owned by Integrys and us. WPS Investments invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015, we had a 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC.

WRPC owns two hydroelectric plants and an oil-fired combustion turbine. We own 50% of the stock of WRPC. Half of the energy output of the hydroelectric plants is sold to us, and half is sold to Wisconsin Power and Light Company, an unaffiliated public utility. The electric power from the combustion turbine is also sold in equal parts to Wisconsin Power and Light Company and us.

D. REGULATION

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

2015 Form 10-K 11 Wisconsin Public Service Corporation

Rates

Our retail electric and natural gas rates are regulated by the PSCW and the MPSC. The FERC regulates our wholesale electric rates. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.

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

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

For information on how our rates are set, see Note 21, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:

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

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

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

	2015				2014				2013
(in millions)	Amount		Percent		Amount		Percent		Amount		Percent
Electric
Wisconsin	$	975.9	82.1	%	$	1,001.2	81.8	%	$	977.6	78.7	%
Michigan	19.8		1.7	%	19.9		1.6	%	20.5		1.6	%
FERC – Wholesale	192.1		16.2	%	202.6		16.6	%	244.9		19.7	%
Total	1,187.8		100.0	%	1,223.7		100.0	%	1,243.0		100.0	%
Natural Gas
Wisconsin	302.1		98.7	%	465.6		98.6	%	343.6		98.6	%
Michigan	4.1		1.3	%	6.7		1.4	%	4.8		1.4	%
Total	306.2		100.0	%	472.3		100.0	%	348.4		100.0	%
Total utility operating revenues	$	1,494.0			$	1,696.0			$	1,591.4

Electric Transmission, Capacity, and Energy Markets

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

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.

2015 Form 10-K 12 Wisconsin Public Service Corporation

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and 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.

Other Electric Regulations

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

We are subject to Act 141 in Wisconsin and Public Act 295 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 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 are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service 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 our low-income customers.

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.

2015 Form 10-K 13 Wisconsin Public Service Corporation

F. EMPLOYEES

As of December 31, 2015, we had 1,329 employees, of which 1,267 were full-time. Approximately 917 of our total employees were represented by Local 420 of the International Union of Operating Engineers, AFL-CIO. The current Local 420 collective bargaining agreement expires on October 15, 2016.

2015 Form 10-K 14 Wisconsin Public Service Corporation

ITEM 1A. RISK FACTORS

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental regulation.

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

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

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

If we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, or if we are unable to recover any increased costs of complying with additional requirements or any other associated costs in customer rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.

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

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

The EPA has adopted and has implemented (or is in the process of implementing) regulations governing the emission of NOx, SO₂, fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, the MATS rule, the Clean Power Plan, the CSAPR, and other air quality regulations. In addition, the EPA has finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA

2015 Form 10-K 15 Wisconsin Public Service Corporation

has also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters; however, this rule has been stayed. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. Several environmental regulations were either finalized or implemented during 2015, and there is still uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with these regulations.

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

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

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

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

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

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

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

2015 Form 10-K 16 Wisconsin Public Service Corporation

(including Wisconsin), 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, all of which could have a material adverse impact on our operating costs.

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

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

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

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

Risks Related to the Operation of Our Business

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

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

Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.

Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.

2015 Form 10-K 17 Wisconsin Public Service Corporation

Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.

Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:

• Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including job losses, decreases in income, and business closings. We are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn or disruption of financial markets could adversely affect the financial condition of our customers and demand for their products. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

• Weather conditions. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.

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

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

We are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, natural gas storage, and other projects, including projects for environmental compliance.

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

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

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

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

2015 Form 10-K 18 Wisconsin Public Service Corporation

reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

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

We face the risk of terrorist and cyber intrusions, both threatened and actual, against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, any of which could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows.

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

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

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

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

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

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

2015 Form 10-K 19 Wisconsin Public Service Corporation

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

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

Failure of our counterparties to meet their obligations, including obligations under power purchase agreements, could have an adverse impact on our results of operations.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.

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

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

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

Risks Related to Economic and Market Volatility

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

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

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

• A rating downgrade;

• An economic downturn or uncertainty;

2015 Form 10-K 20 Wisconsin Public Service Corporation

• Prevailing market conditions;

• Concerns over foreign economic conditions;

• Changes in tax policy;

• War or the threat of war; and

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

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

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

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

Any downgrade by the rating agencies could:

• Increase borrowing costs under our existing credit facility;

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

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

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

• Trigger collateral requirements in various contracts.

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

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

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

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

Changes in commodity prices could result in:

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

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

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

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

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

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

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

2015 Form 10-K 21 Wisconsin Public Service Corporation

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

Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO Energy Markets. If we are unable to run our lower cost units, we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.

The use of derivative contracts could result in financial losses.

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

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

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

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

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

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

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

We have significant obligations related to pension and OPEB plans. If 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

2015 Form 10-K 22 Wisconsin Public Service Corporation

in the market value of plan assets, changes in interest rates, changes in demographics, including the number of retirements, or changes in life expectancy assumptions.

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.

Risks Related to the WEC Merger

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

2015 Form 10-K 23 Wisconsin Public Service Corporation

ITEM 2. PROPERTIES

We own our principal properties outright, except that the major portion of our electric utility distribution lines 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.

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      MW (1)
Coal-fired plants
Columbia	Portage, WI	Coal	2	353	(2)
Edgewater	Sheboygan, WI	Coal	1	96	(2)
Pulliam	Green Bay, WI	Coal	2	212
Weston Units 3 and 4	Rothschild, WI	Coal	2	705	(2)
Total coal-fired plants			7	1,366
Natural gas-fired plants
De Pere Energy Center	De Pere, WI	Natural Gas/Oil	1	158
Fox Energy Center	Wrightstown, WI	Natural Gas	3	554
Juneau	Adams, WI	Distillate Fuel Oil	1	—	(3)
Pulliam	Green Bay, WI	Natural Gas/Oil	1	78
West Marinette	Marinette, WI	Natural Gas/Oil	3	153
Weston	Rothschild, WI	Natural Gas/Oil	3	126
Total natural gas-fired plants			12	1,069
Renewables
Hydro Plants (17 in number)	WI and MI	Hydro	51	60	(4)
Crane Creek	Howard County, IA	Wind	66	21
Lincoln	Kewaunee County, WI	Wind	14	1
Total renewables			131	82
Total system			150	2,517

⁽¹⁾  Based on expected capacity ratings for summer 2016, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

⁽²⁾  We jointly own these facilities with various other utilities. The capacity indicated for each of these units is equal to our portion of total plant capacity based on our percent of ownership.

• Wisconsin Power and Light Company operates the Columbia and Edgewater units. We hold a 31.8% ownership interest in these facilities.

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

⁽³⁾   WRPC owns and operates the Juneau unit. We hold a 50% ownership interest in WRPC and are entitled to 50% of the total capacity from the Juneau unit.

⁽⁴⁾  WRPC owns and operates the Castle Rock and Petenwell units. We hold a 50% ownership interest in WRPC and are entitled to 50% of the total capacity at Castle Rock and Petenwell. Our share of capacity for Castle Rock is 8.1 MWs and our share of capacity for Petenwell is 10.2 MWs.

As of December 31, 2015, we operated approximately 18,700 miles of overhead distribution lines and 6,700 miles of underground distribution cable, located in Michigan and Wisconsin, as well as approximately 124 electric distribution substations and 190,500 line transformers.

2015 Form 10-K 24 Wisconsin Public Service Corporation

Natural Gas Facilities

At December 31, 2015, our natural gas properties were located in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula and consisted of the following:

• Approximately 8,000 miles of natural gas distribution mains,

• Approximately 250 miles of natural gas transmission mains,

• Approximately 305,000 natural gas lateral services, and

• 85 natural gas distribution and transmission gate stations.

ITEM 3. LEGAL PROCEEDINGS

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

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

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.    

2015 Form 10-K 25 Wisconsin Public Service Corporation

PART II

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

EQUITY SECURITIES

Dividends

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

Quarter
(in millions)	2015		2014
First	$	28.8	$	28.0
Second	28.8		27.9
Third	28.7		28.0
Fourth	28.8		27.9
Total	$	115.1	$	111.8

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

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Integrys in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Integrys. See Note 11, Common Equity, for more information regarding restrictions on our ability to pay dividends.

ITEM 6. SELECTED FINANCIAL DATA

Omitted pursuant to General Instruction I(2)a.

2015 Form 10-K 26 Wisconsin Public Service Corporation

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

CORPORATE DEVELOPMENTS

Introduction

We are an electric and natural gas utility and an indirect wholly owned subsidiary of WEC Energy Group. We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers. We also provide wholesale electric service to numerous utilities and cooperatives for resale. We conduct our business primarily in three reportable segments, an electric utility segment, a natural gas utility segment, and an other segment. See Note 22, Segment Information, for more information on our reportable business segments.

Corporate Strategy

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

Reliability

We have made significant reliability related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution network. We continue work on our System Modernization Reliability Project, which involves modernizing parts of our electric distribution system by burying or upgrading lines. The project focuses on electric lines that currently have the lowest reliability in our system, primarily in rural areas that are heavily forested.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company.

Financial Discipline

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

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

Exceptional Customer Care

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

2015 Form 10-K 27 Wisconsin Public Service Corporation

RESULTS OF OPERATIONS

Consolidated Earnings

The following table compares our consolidated results:

	Year Ended December 31
(in millions)	2015		2014		2013
Electric utility segment	$	194.0	$	204.8	$	189.5
Natural gas utility segment	34.0		52.4		50.0
Other segment	0.1		0.4		0.5
Total operating income	228.1		257.6		240.0
Other income, net	25.6		25.2		23.5
Interest expense	53.5		57.4		43.7
Income before income taxes	200.2		225.4		219.8
Income tax expense	75.0		84.7		81.9
Preferred stock dividend requirements	2.7		3.1		3.1
Net income attributed to common shareholder	$	122.5	$	137.6	$	134.8

Electric Utility Segment Contribution to Operating Income

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

	Year Ended December 31
(in millions)	2015		2014		2013
Revenues	$	1,187.8	$	1,223.7	$	1,243.0
Fuel and purchased power costs	429.3		457.5		518.8
Total electric margins	758.5		766.2		724.2
Other operation and maintenance	424.3		425.8		405.0
Depreciation and amortization	103.7		100.5		93.7
Property and revenue taxes	36.5		35.1		36.0
Operating income	$	194.0	$	204.8	$	189.5

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

	Year Ended December 31
	MWh (in thousands)
Electric Sales Volumes	2015	2014	2013
Customer class
Residential	2,780.2	2,862.3	2,862.3
Small commercial and industrial	3,984.0	3,941.6	3,918.6
Large commercial and industrial	4,034.1	3,962.8	4,003.3
Other	32.0	32.2	32.6
Total retail	10,830.3	10,798.9	10,816.8
Wholesale	2,618.7	2,733.4	2,762.5
Resale	925.5	590.6	1,999.2
Total sales in MWh	14,374.5	14,122.9	15,578.5
Electric customer choice *	23.3	21.7	9.0

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

2015 Form 10-K 28 Wisconsin Public Service Corporation

	Year Ended December 31
	Degree Days
Weather *	2015	2014	2013
Heating (7,506 normal)	7,001	8,564	8,051
Cooling (501 normal)	494	333	529

* Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from the Green Bay Weather Station.

2015 Compared with 2014

Operating Income

Operating income at the electric utility segment decreased $10.8 million, driven by:

• A $9.8 million decrease from electric margins as a result of the PSCW rate order, effective January 1, 2015. Although the PSCW approved an electric rate increase, the majority of the increase related to the higher cost of fuel for electric generation, which does not impact margins unless costs differ by 2% or less from the amounts included in rates. See Note 21, Regulatory Environment, for more information.

• A $9.6 million increase in electric transmission expenses from MISO and ATC. This increase was driven by higher costs from MISO related to transmission providers' continued investment in equipment and facilities for improved reliability as well as increased costs to meet ATC's revenue requirements. Transmission expenses in 2015 reflect the PSCW's approval of escrow accounting treatment. We expect to recover the amounts deferred in a future rate case. See Note 21, Regulatory Environment, for more information.

• A $5.6 million net decrease in electric margins related to retail sales volume variances. Margins from residential customers decreased, primarily due to warmer weather during the 2015 heating season and lower weather-normalized use per customer.

• Severance expense of $3.6 million was recorded in 2015 related to the WEC Merger. See Note 2, Merger, for more information.

• A $3.4 million decrease in wholesale margins driven by lower sales volumes in 2015. Certain wholesale customers have provisions in their contracts which allow them to reduce the amount of energy we provide to them.

• A $3.2 million increase in depreciation and amortization expense, primarily due to the installation of scrubbers at the Columbia plant in April and July of 2014.

These decreases in operating income were partially offset by:

• A $13.8 million decrease in maintenance expense, primarily due to planned major outages at Pulliam Unit 8 and Weston Unit 3 in 2014. Planned outages at our jointly-owned facilities were also less significant in 2015.

• A $9.9 million increase in electric margins resulting from positive collections of actual fuel and purchased power costs in 2015, compared with 2014 collections which were less than actual costs incurred. Under the fuel rule, we defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins.

• A $1.7 million net decrease in employee benefits costs and administrative and general salaries and compensation. The decrease was driven by the year-over-year impact of the 2014 amortization of a prior year deferral of certain employee benefit costs, partially offset by an increase in pension expense driven by lower discount rates in 2015.

2015 Form 10-K 29 Wisconsin Public Service Corporation

2014 Compared with 2013

Operating Income

Operating income at the electric utility segment increased$15.3 million, driven by:

• An approximate $35.0 million net increase in margins related to our PSCW rate order, effective January 1, 2014. Although the PSCW approved an electric rate decrease, the rate decrease was driven by 2013 positive fuel cost collections and 2012 positive decoupling collections that were being refunded to customers in 2014 and had no impact on margins. See Note 21, Regulatory Environment, for more information.

◦ Margins increased approximately $41.0 million as a result of the PSCW rate order, primarily driven by an increase in electric rate base from owning and operating the Fox Energy Center, which was included in rates beginning in 2014. In 2013, customer rates only included recovery of estimated purchased power costs from the Fox Energy Center.

◦ Margins were positively impacted by approximately $5.0 million mainly due to lower fly ash disposal costs in 2014. These costs are not included in the fuel rule recovery mechanism.

◦ Margins decreased by approximately $11.0 million due to fuel and purchased power cost collections in 2014 being less than actual costs incurred, compared with positive collections in 2013. Under the fuel rule, we can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.

• An approximate $9.0 million increase in wholesale margins driven by higher prices. Wholesale prices increased due to higher generation costs as well as an increase in electric rate base, resulting from the purchase of the Fox Energy Center in 2013 and the installation of environmental projects at the Columbia plant in 2014. Wholesale customers proportionally shared in these price increases through formula rates.

• A $6.6 million decrease in operating expenses due to the year-over-year impact of the 2013 deferral of the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center. The 2013 PSCW rate order did not reflect this purchase or the related termination of a power purchase agreement. However, we did receive PSCW approval to defer ownership costs above or below our power purchase agreement expenses in 2013.

• A $5.2 million net decrease in employee benefit costs, including the impact of the prior year deferral of some of these costs. Employee benefit costs other than stock-based compensation (discussed below) decreased $24.0 million in 2014. This decrease was driven by the continued funding of our pension plan and higher discount rates assumed in 2014 for both our pension and postretirement plans. The remeasurement of certain other postretirement benefit plans also contributed to the overall decrease in employee benefit costs. See Note 17, Employee Benefits, for more information. This decrease was partially offset by:

◦ Higher stock-based compensation expense of $4.3 million, which was primarily driven by an increase in the fair value of awards accounted for as liabilities. The increase in fair value resulted from an increase in Integrys's stock price.

◦ The year-over-year impact of a deferral of certain increases in employee benefit costs in 2013, recorded in accordance with our PSCW rate order, and the related amortization in 2014. Together, these changes increased employee benefit costs by $14.5 million.

These increases in operating income were partially offset by:

• A $15.1 million increase in maintenance expense, primarily due to planned major outages in 2014 at the Pulliam plant, Fox Energy Center, and Weston 4, as well as maintenance at certain other generation plants. These increases were partially offset by the year-over-year impact of maintenance expenses associated with the Weston 3 planned major outage in 2013.

• A $6.8 million increase in depreciation and amortization expense, mainly due to the acquisition of the Fox Energy Center at the end of the first quarter of 2013. In addition, we completed the installation of scrubbers at the Columbia plant in 2014.

• A $6.0 million increase in costs associated with the acquisition and operation of the Fox Energy Center. The majority of this increase relates to the amortization of a regulatory asset related to the fee paid for the early termination of the Fox Energy Center power purchase agreement. Recovery of the amortization was included in the new rates.

2015 Form 10-K 30 Wisconsin Public Service Corporation

• A $5.4 million increase in electric transmission expense.

• A decrease in margins of approximately $3.0 million related to sales volume variances. The decrease in margins was primarily driven by lower sales volumes from both our large commercial and industrial customers as well as our residential customers. The decrease in these sales volumes was driven by lower use per customer in 2014. This decrease was partially offset by the impact of the termination of our decoupling mechanism, effective January 1, 2014. See Note 21, Regulatory Environment, for more information. Our decoupling mechanism did not cover large commercial and industrial customers.

• A $2.8 million increase in amortization of previously deferred production tax credits related to the Crane Creek wind project.

Natural Gas Utility Segment Contribution to Operating Income

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 36.2% in 2015 and increased 44.0% in 2014, which had no impact on margins.

	Year Ended December 31
(in millions)	2015		2014		2013
Revenues	$	306.2	$	472.3	$	348.4
Cost of natural gas sold	181.2		326.9		214.5
Total natural gas margins	125.0		145.4		133.9
Other operation and maintenance	69.6		73.5		65.1
Depreciation and amortization	17.0		16.2		15.6
Property and revenue taxes	4.4		3.3		3.2
Operating income	$	34.0	$	52.4	$	50.0

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

	Year Ended December 31
	Therms (in millions)
Natural Gas Sales Volumes	2015	2014	2013
Customer class
Residential	240.6	284.7	264.3
Commercial and industrial	144.6	175.8	165.3
Other	38.4	27.3	32.6
Total retail	423.6	487.8	462.2
Transport	364.8	367.4	360.4
Total sales in therms	788.4	855.2	822.6

	Year Ended December 31
	Degree Days
Weather *	2015	2014	2013
Heating (7,506 normal)	7,001	8,564	8,051

* Normal heating degree days are based on a 20-year moving average of monthly temperatures from the Green Bay Weather Station.

2015 Form 10-K 31 Wisconsin Public Service Corporation

2015 Compared with 2014

Operating Income

Operating income at the natural gas utility segment decreased $18.4 million, driven by:

• A $13.9 million decrease in natural gas margins related to sales volume variances, primarily due to warmer weather in 2015.

• A $6.5 million decrease in natural gas margins related to the PSCW rate order, effective January 1, 2015. Although the PSCW approved a much larger rate decrease in 2015, the majority of the decrease related to decoupling refunds to customers, which have no impact on margins. See Note 21, Regulatory Environment, for more information.

These decreases in operating income were partially offset by:

• A $1.8 million net decrease in employee benefits costs and administrative and general salaries and compensation. The decrease was driven by the year-over-year impact of the 2014 amortization of a prior year deferral of certain employee benefit costs.

• A $1.2 million decrease in operating expenses related to asset usage charges from WBS. See Note 4, Related Parties, for more information on WBS.

2014 Compared with 2013

Operating Income

Operating income at the natural gas utility segment increased $2.4 million, driven by:

• The combined effect of the change in weather year over year, the impact of higher weather-normalized volumes, and the impact of our decoupling mechanism increased margins approximately $17.0 million. In 2014, our margins were positively impacted by colder than normal weather as we no longer had a decoupling mechanism in place, effective January 1, 2014. Higher use per customer and an increase in customers also contributed to the increase in margins in 2014.

• A $2.1 million decrease in customer assistance expense, primarily driven by a reduction in costs for energy efficiency programs.

These increases in operating income were partially offset by:

• Margins were negatively impacted by approximately $5.0 million related to our rate order, effective January 1, 2014. Although the PSCW approved a net rate increase, it was driven by the recovery of the 2012 decoupling under-collections to be recovered from customers in 2014, which has no impact on margins. See Note 21, Regulatory Environment, for more information.

• A $3.1 million increase in natural gas distribution costs, driven in part by safety inspections performed during 2014. Additional meter maintenance and higher labor costs related to wage increases also contributed to the increase in costs.

• A $1.4 million increase in bad debt expense, driven by higher natural gas costs in 2014 and an increase in sales volumes.

• A $1.4 million increase in operating expenses driven by higher information technology costs. New servers and software for natural gas management and work asset management systems were placed in service during the third quarter of 2013, resulting in higher asset usage charges from WBS. Also, in 2014, several information technology projects and upgrades were performed, and additional information technology services were provided by WBS.

• A $1.3 million increase in operating expenses driven by higher amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites.

2015 Form 10-K 32 Wisconsin Public Service Corporation

• A $0.7 million net increase in employee benefit costs, driven by:

◦ A $4.3 million increase related to the negative year-over-year impact of the deferral of employee benefit costs in 2013 and the related amortization in 2014. In 2013, we deferred certain increases in pension and other employee benefit costs as a result of our 2013 rate order from the PSCW. We began amortizing this regulatory asset in 2014.

◦ A $1.8 million increase in stock-based compensation expense, primarily due to the year-over-year increase in the fair value of awards accounted for as liabilities. The increase in fair value resulted from an increase in Integrys's stock price.

◦ These increases were partially offset by a $5.3 million decrease in other employee benefit costs, driven in part by higher discount rates assumed in 2014. The remeasurement of certain postretirement benefit plans in the first quarter of 2014 also contributed to the decrease. See Note 17, Employee Benefits, for more information on this remeasurement.

• A $0.6 million increase in depreciation and amortization expense, driven in part by additional investment in natural gas mains.

Other Segment Contribution to Operating Income

	Year Ended December 31
(in millions)	2015		2014		2013
Operating income	$	0.1	$	0.4	$	0.5

There were no significant changes in operating income related to the other segment for the periods presented.

Consolidated Other Income, Net

	Year Ended December 31
(in millions)	2015		2014		2013
AFUDC – Equity	$	15.1	$	11.0	$	9.9
Earnings from equity method investments	8.5		10.3		11.3
Other, net	2.0		3.9		2.3
Other income, net	$	25.6	$	25.2	$	23.5

2015 Compared with 2014

Other income, net increased by $0.4 million when compared to 2014. This increase was primarily due to higher AFUDC as a result of the construction of the ReACT^TM emission control technology at the Weston 3 plant, partially offset by environmental compliance projects at the Columbia plant completed in 2014 and a reduction in earnings from ATC related to the ROE complaint. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – ATC Allowed ROE Complaint, for more information.

2014 Compared with 2013

Other income, net increased by $1.7 million when compared to 2013. This increase was primarily due to higher AFUDC as a result of the construction of the ReACT^TM emission control technology at the Weston 3 plant, environmental projects at the Columbia plant, and the System Modernization and Reliability Project.

Consolidated Interest Expense

	Year Ended December 31
(in millions)	2015		2014		2013
Interest expense	$	53.5	$	57.4	$	43.7

2015 Compared with 2014

Interest expense decreased by $3.9 million when compared to 2014, primarily due to a lower average outstanding intercompany long-term debt balance, and an increase in AFUDC. AFUDC was higher largely due to the construction on the ReACT^TM emission

2015 Form 10-K 33 Wisconsin Public Service Corporation

control technology at Weston Unit 3 plant, partially offset by environmental compliance projects at the Columbia plant completed earlier in 2014.

2014 Compared with 2013

Interest expense increased by $13.7 million when compared to 2013, primarily driven by higher average outstanding long-term debt in 2014. An increase in AFUDC partially offset this increase. AFUDC was higher largely due to the construction on the ReACT^TM emission control technology at Weston Unit 3 plant and the System Modernization and Reliability Project, partially offset by environmental compliance projects at the Columbia plant completed earlier in 2014.

Consolidated Income Tax Expense

	Year Ended December 31
	2015		2014		2013
Effective tax rate	37.5	%	37.6	%	37.3	%

There were no significant changes in the effective tax rate for the periods presented.

For information on our effective tax rate and changes in the deferred income tax balances, see Note 15, Income Taxes.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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

(in millions)	2015			2014			2013			Change in 2015 Over 2014			Change in 2014 Over 2013
Cash provided by (used in):
Operating activities	$	304.7		$	263.5		$	273.1		$	41.2		$	(9.6	)
Investing activities	(373.3		)	(321.1		)	(556.6		)	(52.2		)	235.5
Financing activities	69.3			57.3			282.7			12.0			(225.4		)

Operating Activities

2015 Compared with 2014

Net cash provided by operating activities increased $41.2 million in 2015, driven by:

• A $47.1 million decrease in contributions to pension and OPEB plans in 2015.

• A $19.0 million increase in cash related to lower payments for operating and maintenance costs in 2015. The lower payments were partially driven bya decrease in electric utility maintenance.

• A $14.6 million net increase in cash related to lower payments for natural gas, fuel, and purchased power, partially offset by a decrease in cash driven by lower overall collections from customers in 2015. This net increase was primarily due to the impact of lower commodity prices in 2015.

• An $8.8 million increase in cash from customer prepayments and credit balances in 2015. In 2015, customer prepayments grew during the warmer winter.

These increases in cash were partially offset by:

• A $20.7 million increase in cash paid for income taxes in 2015. The increase in cash paid was primarily related to a federal income tax refund received in 2014, partially offset by lower estimated tax payments in 2015.

2015 Form 10-K 34 Wisconsin Public Service Corporation

• A $13.6 milliondecrease in cash driven by higher collateral requirements in 2015. Additional collateral was required by MISO as a result of the WEC Merger.

• A $5.0 million decrease in cash due to an increase in payments for environmental remediation activities in 2015.

2014 Compared with 2013

Net cash provided by operating activities decreased $9.6 million in 2014, driven by:

• A $79.4 million decrease in cash due to higher costs of natural gas, fuel, and purchased power in 2014. Additional cash was used in 2014 due to higher energy prices and the colder weather.

• A $21.1 million decrease in cash received from income taxes in 2014. The decrease in cash received was primarily related to quarterly income tax estimated payments, a federal income tax extension payment made in 2014, and an additional payment upon filing the 2013 tax return. A federal income tax refund received in the first quarter of 2014 for an amended return partially offset these income tax payments.

• A $13.3 million decrease in cash due to increased operating and maintenance costs in 2014. The increase in operating and maintenance costs was driven by higher electric utility maintenance from planned major outages and other higher costs associated with owning and operating the Fox Energy Center beginning in March 2013.

• A $12.9 million increase in cash paid for interest in 2014, primarily driven by higher average outstanding long-term debt in 2014.

• A $9.0 million decrease in cash from various deferrals in 2014, primarily for SSR costs, precertification costs for a potential new natural gas combined cycle generating unit, and the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center.

• A $6.0 million increase in contributions to pension and other postretirement benefit plans in 2014.

• A $5.0 million decrease in cash driven by higher collateral requirements in 2014. Collateral requirements are based on forward natural gas and electricity prices and forward positions with counterparties.

• A $3.9 million decrease in cash from insurance recoveries received related to environmental remediation of manufactured gas plant sites in 2014.

• A $3.4 million increase in cash used for environmental remediation activities in 2014.

These decreases in cash were partially offset by:

• A $91.6 million increase in cash collections from customers, mainly due to rate increases, higher commodity prices, an increase in electric wholesale revenues, and the colder weather in 2014. Included in the electric rate increase was the impact of the increase in rate base related to owning and operating the Fox Energy Center.

• The positive year-over-year impact of a $50.0 million payment in 2013 for the early termination of a tolling agreement in connection with the purchase of Fox Energy Company LLC.

• A $5.9 million increase in cash from customer prepayments and credit balances in 2014. In 2013, cash received in relation to amounts billed was lower because customer prepayments had grown during an unusually warm 2012.

Investing Activities

2015 Compared with 2014

Net cash used for investing activities increased $52.2 million in 2015, primarily due to a $49.0 million increase in cash used for capital expenditures (discussed below).

2015 Form 10-K 35 Wisconsin Public Service Corporation

2014 Compared with 2013

Net cash used for investing activities decreased $235.5 million in 2014, primarily due to $391.6 million of cash used in 2013 to purchase Fox Energy Company LLC. See Note 3, Acquisition, for more information regarding this purchase. Partially offsetting the decrease in net cash used was the year-over-year negative impact of the receipt of a $69.0 million Section 1603 Grant for the Crane Creek wind project in 2013 and an $85.9 million increase in cash used for other capital expenditures (discussed below).

Capital Expenditures

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

Reportable Segment (in millions)	2015		2014		2013		Change in 2015 Over 2014		Change in 2014 Over 2013
Electric utility	$	319.4	$	272.7	$	590.3	$	46.7	$	(317.6	)
Natural gas utility	51.6		49.3		37.4		2.3		11.9
WPS consolidated	$	371.0	$	322.0	$	627.7	$	49.0	$	(305.7	)

2015 Compared with 2014

The increase in capital expenditures at the electric utility segment in 2015 was primarily due to the construction of the ReACT^TM emission control technology at Weston 3, the System Modernization and Reliability Project, and an expansion of our Legner landfill site. These increases were partially offset by lower capital expenditures related to environmental compliance projects at the Columbia plant in 2015.

2014 Compared with 2013

The decrease in capital expenditures at the electric utility segment was primarily due to our purchase of Fox Energy Company LLC in 2013. Capital expenditures related to environmental compliance projects at the Columbia plant also decreased in 2014. Increased expenditures in 2014 related to the ReACT^TM project at Weston 3 and the System Modernization and Reliability Project partially offset the decrease.

The increase in capital expenditures at the natural gas utility segment was primarily related to reinforcements of transmission and distribution systems and the expansion of natural gas services to rural areas.

Financing Activities

2015 Compared with 2014

Net cash provided by financing activities increased $12.0 million in 2015, driven by:

• A $180.0 million increase in equity contributions from Integrys in 2015.

• A $124.9 million net increase in cash due to the issuance of $250.0 million of long-term debt in 2015, partially offset by the repayment of $125.1 million of long-term debt in 2015.

These increases in cash were partially offset by:

• A $150.0 million return of capital to Integrys in 2015.

• An $81.8 million decrease in cash due to a decrease in net borrowings of commercial paper in 2015.

• A $52.7 million decrease in cash due to a redemption of preferred stock in 2015. See Note 12, Preferred Stock, for more information.

• A $3.3 million decrease in cash due to an increase in dividends paid to Integrys in 2015.

2015 Form 10-K 36 Wisconsin Public Service Corporation

2014 Compared with 2013

Net cash provided by financing activities decreased $225.4 million in 2014, driven by:

• A $303.0 million net decrease in cash due to a $450.0 million decrease in the issuance of long-term debt, which was partially offset by a $147.0 million decrease in the repayment of long-term debt. The issuance of long-term debt in 2013 was partially used to finance the acquisition of Fox Energy Company LLC.

• A $145.0 million decrease in equity contributions from Integrys, which were used to support the acquisition of Fox Energy Company LLC in 2013.

These decreases in cash were partially offset by:

• A $189.3 million year-over-year increase in net cash provided by financing activities due to $119.5 million of net borrowings of commercial paper in 2014, compared with $69.8 million of net repayments of commercial paper in 2013.

• A $35.0 million return of capital to our parent in 2013.

Significant Financing Activities

For information on our short-term debt, see Note 13, Short-Term Debt and Lines of Credit.

For information on our long-term debt, see Note 14, Long-Term Debt.

Capital Resources and Requirements

We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include cash balances, liquid assets, operating cash flows, access to debt capital markets, and available borrowing capacity under our existing credit facility. Our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent credit rating agencies, as well as the market rates for interest. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control.

Liquidity

Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management strategies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage our liquidity and capital resource needs. We plan to meet our capital requirements for the period 2016 through 2018 primarily through internally generated funds (net of forecasted dividend payments to our parent), debt financings, and equity infusions from Integrys. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 13, Short-Term Debt and Lines of Credit, for more information about our credit facility and other short-term credit agreements.

At December 31, 2015, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, for more information on our credit facility and other short-term credit agreements. See Note 14, Long-Term Debt, for more information on our long-term debt.

Working Capital

As of December 31, 2015, our current liabilities exceeded our current assets by $60.0 million. We do not expect this to have any impact on our liquidity because we believe we have an adequate back-up line of credit in place for ongoing operations. We also have access to the capital markets to finance our construction programs and to refinance current maturities of long-term debt if necessary.

2015 Form 10-K 37 Wisconsin Public Service Corporation

Capital Requirements

Contractual Obligations

The following table shows our contractual obligations as of December 31, 2015, including those of our subsidiary:

			Payments Due By Period (1)
(in millions)	Total Amounts Committed		2016		2017 to 2018		2019 to 2020		Later Years
Long-term debt obligations (2)	$	2,422.4	$	53.6	$	473.6	$	84.7	$	1,810.5
Operating lease obligations (3)	15.0		0.4		1.4		0.9		12.3
Energy and transportation purchase obligations (4)	1,129.1		226.6		285.0		170.1		447.4
Purchase orders (5)	183.0		154.8		28.2		—		—
Pension and OPEB funding obligations (6)	8.8		3.5		5.3		—		—
Total contractual obligations	$	3,758.3	$	438.9	$	793.5	$	255.7	$	2,270.2

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

⁽²⁾  Principal and interest payments on long-term debt.

⁽³⁾  Operating lease obligations for power purchase commitments and rail car leases.

⁽⁴⁾  Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations.

⁽⁵⁾  Purchase obligations related to normal business operations, information technology, and other services.

⁽⁶⁾  Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2018.

The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $83.5 million at December 31, 2015, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 18, Commitments and Contingencies, for more information about environmental liabilities.

The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 15, Income Taxes.

AROs in the amount of $32.7 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled beyond 2020.

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

Capital Expenditures and Significant Capital Projects

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

(in millions)
2016	$	288.9
2017	312.8
2018	293.0
Total	$	894.7

2015 Form 10-K 38 Wisconsin Public Service Corporation

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

Common Stock Matters

For information related to our common stock matters, see Note 11, Common Equity.

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $943.5 million as of December 31, 2015. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $2.4 million, $49.5 million, and $43.5 million to our pension and OPEB plans in 2015, 2014, and 2013, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 17, Employee Benefits.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 16, Guarantees.

Factors Affecting Results, Liquidity, and Capital Resources

Market Risks and Other Significant Risks

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

Regulatory Recovery

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

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. In general, regulatory assets are recovered in a period between one to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2015, our regulatory assets totaled $462.7 million and our regulatory liabilities totaled $293.6 million.

Regarding our ReACT™ project, the PSCW approved deferral of costs above the originally authorized $275.0 million level through 2016. We will be required to obtain a separate approval for collection of these deferred costs. Also, prior to the WEC Merger (for a discussion of the merger see Note 2, Merger), Integrys initiated an IT project with the goal of improving the customer experience at its subsidiaries, including us. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of December 31, 2015, none of the costs have been disallowed in rate proceedings. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

See Note 21, Regulatory Environment, for additional information regarding recent rate proceedings, orders, and investigations.

2015 Form 10-K 39 Wisconsin Public Service Corporation

Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

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

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.

Weather

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

Interest Rates

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

Based on our variable rate debt outstanding at December 31, 2015, and December 31, 2014, a hypothetical increase in market interest rates of one-percentage point would have increased annual interest expense by $1.8 million and $1.5 million, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Marketable Securities Return

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

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

(in millions)	As of December 31, 2015		Expected Return on Assets in 2016
Pension trust funds	$	719.0	7.25	%
OPEB trust funds	$	224.5	7.25	%

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

2015 Form 10-K 40 Wisconsin Public Service Corporation

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

Economic Conditions

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

Inflation

We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Risk Factors in Item 1A.

Industry Restructuring

Electric Utility Industry

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

Restructuring in Wisconsin

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

Restructuring in Michigan

Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. Some of our small retail customers have switched to an alternative electric supplier. The law limits customer choice to 10% of our Michigan retail load. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

Natural Gas Utility Industry

Restructuring in Wisconsin

The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer classes with workably competitive market choices and has adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from a third party supplier. However, work on deregulation of the natural gas distribution

2015 Form 10-K 41 Wisconsin Public Service Corporation

industry by the PSCW continues to be on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.

Restructuring in Michigan

The option to choose an alternative retail natural gas supplier has been provided to our Michigan customers since the late 1990s. We are not required by the MPSC or state law to make this option available to customers, but since this option is currently provided to customers, we would need MPSC approval to eliminate it.

We offer natural gas transportation service to customers that select an alternative retail natural gas supplier. Transportation customers purchase natural gas directly from an alternative retail natural gas supplier and use our distribution system to transport the natural gas to their facilities. We still earn a distribution charge when we transport natural gas for these customers. As such, the loss of revenue associated with the natural gas that transportation customers purchase from an alternative retail natural gas supplier has little impact on our net income, since it is offset by an equal reduction to natural gas costs.

Environmental Matters

Cross-State Air Pollution Rule

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

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

See Note 18, Commitments and Contingencies, for a discussion of additional environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, renewable energy requirements, and climate change.

Other Matters

American Transmission Company Allowed Return On Equity Complaint

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

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

2015 Form 10-K 42 Wisconsin Public Service Corporation

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

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

Presque Isle System Support Resource Costs

In August 2013, Wisconsin Electric notified MISO of its intention to suspend the operation of Units 5 through 9 of its Presque Isle generating facility for 16 months, starting February 1, 2014. MISO notified Wisconsin Electric in October 2013 that the Presque Isle facilities are required for reliability and would be SSR-designated. Under the terms of the SSR Tariff, in exchange for keeping the units in service, MISO initially planned to compensate Wisconsin Electric by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load-serving entities, including us, based on load ratio share within the ATC footprint. In February 2015, Wisconsin Electric notified MISO of its intent to rescind its decision to retire the Presque Isle Facility and requested termination of the SSR agreement, effective February 1, 2015. This intent to rescind was driven by a settlement agreement related to the WEC Merger. In April 2015, the FERC approved the termination of the SSR agreement effective February 1, 2015.

In May 2015, MISO made a compliance filing regarding the allocation of Presque Isle SSR costs incurred while the SSR was in effect, which did not allocate any of these SSR costs to us. In September 2015, the FERC approved MISO's new cost allocation method. Subsequently, several parties sought a rehearing of this FERC order, which is still pending.

A potential reallocation of the Presque Isle SSR costs based on the rehearing requests may result in a change in SSR costs allocated to us. SSR costs for our retail customers will be deferred until December 31, 2016, based on a December 2015 order from the PSCW. See Note 21, Regulatory Environment, for more information. We expect that costs for our Michigan customers would be recovered through the Power Supply Cost Recovery mechanism, and costs for our wholesale customers would be recovered through formula rates.

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

In April 2015, WP&L filed a CPCN application with the PSCW for approval to construct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Recent construction proposals received by WP&L indicate that the unit could generate up to 700 MWs. In the third quarter of 2015, we, along with our affiliated utility, Wisconsin Electric, requested and received intervention in this proceeding. As intervenors, we and Wisconsin Electric proposed purchased power agreement alternatives to the new generating unit. In December 2015, we entered into a settlement agreement with Wisconsin Electric and WP&L that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. We will have the option to purchase an undivided ownership interest of up to 100 MWs of generating capacity from the unit during the first two years of operation and up to an aggregate 200 MWs of generating capacity during the third and fourth years of operation. Other major terms of the settlement included agreement on ownership of future natural gas units, negotiation of a renewable generation joint development plan, and ownership terms of the jointly-owned Columbia plant.

Bonus Depreciation Provisions

The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an additional amount of deductible depreciation that is awarded above and beyond what would normally be available.

2015 Form 10-K 43 Wisconsin Public Service Corporation

Critical Accounting Policies and Estimates

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

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

Goodwill Impairment

We completed our annual goodwill impairment test for our natural gas utility reporting unit as of April 1, 2015. No impairment was recorded as a result of this test. The fair value calculated in step one of the test exceeded the carrying value by a substantial amount. The fair value was calculated using an equal weighting of the income approach and the market approach.

For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the fair value of the reporting unit. A fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair value to decrease.

Key assumptions used in the income approach included ROE, the long-term growth rate used to determine the terminal value at the end of the discrete forecast period, and the discount rate. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair value will decrease. The discount rate is determined based on the weighted-average cost of capital, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE is based on our current allowed ROE adjusted for forecasted disallowed costs and expectations regarding the direction and magnitude of movements in interest rates. The terminal growth rate is based on a combination of historical and forecasted statistics for real gross domestic product and personal income.

We used the guideline company method for the market approach. This method uses metrics from similar publicly traded companies in the same industry to determine how much a knowledgeable investor in the marketplace would be willing to pay for an investment in a similar company. We applied multiples derived from these guideline companies to the appropriate operating metric to determine an indication of fair value.

The underlying assumptions and estimates used in the impairment test are made as of a point in time. While our annual goodwill impairment test indicated an impairment is unlikely, subsequent changes in these assumptions and estimates could change the results of the test.

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined benefit pension benefits and OPEB, described in Note 17, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded through the ratemaking process.

2015 Form 10-K 44 Wisconsin Public Service Corporation

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

Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Projected Benefit Obligation			Impact on 2015 Pension Cost
Discount rate	(0.5)	$	43.4		$	4.3
Discount rate	0.5	(36.6		)	(3.3		)
Rate of return on plan assets	(0.5)	N/A			4.2
Rate of return on plan assets	0.5	N/A			(4.2		)

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

Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Postretirement Benefit Obligation			Impact on 2015 Postretirement Benefit Cost
Discount rate	(0.5)	$	18.1		$	2.3
Discount rate	0.5	(15.5		)	(1.9		)
Health care cost trend rate	(0.5)	(13.3		)	(2.8		)
Health care cost trend rate	0.5	15.4			3.3
Rate of return on plan assets	(0.5)	N/A			1.0
Rate of return on plan assets	0.5	N/A			(1.0		)

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

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

We establish our expected return on asset assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.75% in 2015 and 8.00% in both 2014 and 2013, respectively. The actual rate of return on pension plan assets, net of fees, was (3.3)%, 6.2%, and 15.2%, in 2015, 2014, and 2013, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 17, Employee Benefits.

Regulatory Accounting

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

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

2015 Form 10-K 45 Wisconsin Public Service Corporation

written off as a charge to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As ofDecember 31, 2015, we had $462.7 million in regulatory assets and $293.6 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.

Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total operating revenues during 2015 of approximately $1.5 billion included accrued revenues of $54.3 million as of December 31, 2015.

Income Tax Expense

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

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

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(m), Income Taxes, and Note 15, Income Taxes, for a discussion of accounting for income taxes.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 7. of this report, as well as Note 1(q), Derivative Instruments, Note 1(p), Fair Value Measurements, and Note 16, Guarantees, for information concerning potential market risks to which we are exposed.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Public Service Corporation:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Public Service Corporation and subsidiary (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of income, equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

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

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

/s/ DELOITTE & TOUCHE LLP

February 26, 2016

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B. CONSOLIDATED INCOME STATEMENTS

Year Ended December 31
(in millions)	2015			2014			2013
Operating revenues	$	1,483.3		$	1,683.6		$	1,580.5
Operating expenses
Cost of sales	599.8			771.1			721.5
Other operation and maintenance	493.4			499.7			470.4
Depreciation and amortization	121.0			116.8			109.4
Property and revenue taxes	41.0			38.4			39.2
Total operating expenses	1,255.2			1,426.0			1,340.5
Operating income	228.1			257.6			240.0
Other income, net	25.6			25.2			23.5
Interest expense	53.5			57.4			43.7
Other expense	(27.9		)	(32.2		)	(20.2		)
Income before income taxes	200.2			225.4			219.8
Income tax expense	75.0			84.7			81.9
Net income	125.2			140.7			137.9
Preferred stock dividend requirements	2.7			3.1			3.1
Net income attributed to common shareholder	$	122.5		$	137.6		$	134.8

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

2015 Form 10-K 48 Wisconsin Public Service Corporation

C. CONSOLIDATED BALANCE SHEETS

At December 31
(in millions, except share and per share data)	2015		2014
Assets
Current assets
Cash and cash equivalents	$	6.1	$	5.4
Accounts receivable and unbilled revenues, net of reserves of $2.5 and $3.2, respectively	164.0		203.1
Receivables from related parties	3.1		1.3
Materials, supplies and inventories
Fuel and gas	104.5		85.0
Materials and supplies, at average cost	40.5		39.2
Prepaid taxes	48.1		65.7
Other current assets	27.0		17.7
Current assets	393.3		417.4
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $1,565.7 and $1,542.5, respectively	3,418.6		3,131.0
Regulatory assets	462.5		457.1
Goodwill	36.4		36.4
Pension and other postretirement benefit assets	102.4		128.9
Other long-term assets	91.9		98.5
Long-term assets	4,111.8		3,851.9
Total assets	$	4,505.1	$	4,269.3
Liabilities and Shareholder's Equity
Current liabilities
Short-term debt	$	182.8	$	145.1
Current portion of long-term debt	—		125.0
Current portion of long-term debt to parent	2.9		2.5
Accounts payable	181.8		161.6
Payables to related parties	35.6		16.9
Other current liabilities	50.2		71.6
Current liabilities	453.3		522.7
Long-term liabilities
Long-term debt to parent	—		2.9
Long-term debt	1,289.4		1,040.1
Deferred income taxes	774.1		725.9
Deferred investment tax credits	7.4		7.8
Regulatory liabilities	290.0		318.4
Environmental remediation liabilities	83.5		86.3
Pension and other postretirement benefit obligations	24.4		37.6
Payables to related parties	4.8		5.4
Other long-term liabilities	92.3		71.6
Long-term liabilities	2,565.9		2,296.0
Commitments and contingencies (Note 18)
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively	—		51.2
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding	95.6		95.6
Additional paid-in capital	861.8		782.0
Retained earnings	528.5		521.8
Total liabilities and shareholder's equity	$	4,505.1	$	4,269.3

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

2015 Form 10-K 49 Wisconsin Public Service Corporation

D. CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31
(in millions)	2015			2014			2013
Operating activities
Net income	$	125.2		$	140.7		$	137.9
Reconciliation to cash provided by operating activities
Depreciation and amortization	121.0			113.8			106.2
Pension and other postretirement (credit) expense	(2.7		)	(6.2		)	22.2
Contributions to pension and OPEB plans	(2.4		)	(49.5		)	(43.5		)
Deferred income taxes and investment tax credits, net	43.6			90.5			79.4
Termination of tolling agreement with Fox Energy Company LLC	—			—			(50.0		)
Change in –
Collateral on deposit	(17.4		)	(3.8		)	1.2
Accounts receivable and unbilled revenues	38.6			13.4			(14.6		)
Materials, supplies, and inventories	(16.1		)	(28.0		)	19.6
Prepaid taxes	17.6			(2.1		)	21.1
Other current assets	1.5			3.7			(2.3		)
Accounts payable	5.0			15.5			(18.0		)
Other current liabilities	(3.3		)	(14.0		)	6.5
Other, net	(5.9		)	(10.5		)	7.4
Net cash provided by operating activities	304.7			263.5			273.1
Investing activities
Capital expenditures	(371.0		)	(322.0		)	(236.1		)
Acquisition of Fox Energy Company LLC	—			—			(391.6		)
Grant received related to Crane Creek wind project	—			—			69.0
Other, net	(2.3		)	0.9			2.1
Net cash used for investing activities	(373.3		)	(321.1		)	(556.6		)
Financing activities
Change in short-term debt	37.7			119.5			(69.8		)
Borrowing on term credit facility	—			—			200.0
Repayment of term credit facility	—			—			(200.0		)
Repayment of long-term debt	(125.1		)	—			(147.0		)
Repayment of long-term debt to parent	(2.5		)	(0.9		)	(0.9		)
Issuance of long-term debt	250.0			—			450.0
Payments of dividend to parent	(115.1		)	(111.8		)	(108.6		)
Equity contribution from parent	235.0			55.0			200.0
Return of capital to parent	(150.0		)	—			(35.0		)
Preferred stock dividend requirements	(2.7		)	(3.1		)	(3.1		)
Redemption of preferred stock	(52.7		)	—			—
Other, net	(5.3		)	(1.4		)	(2.9		)
Net cash provided by financing activities	69.3			57.3			282.7
Net change in cash and cash equivalents	0.7			(0.3		)	(0.8		)
Cash and cash equivalents at beginning of year	5.4			5.7			6.5
Cash and cash equivalents at end of year	$	6.1		$	5.4		$	5.7

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

2015 Form 10-K 50 Wisconsin Public Service Corporation

E. CONSOLIDATED STATEMENTS OF EQUITY

(in millions)	Common Stock		Additional Paid in Capital			Retained Earnings			Total Common Shareholder's Equity
Balance at December 31, 2012	$	95.6	$	555.4		$	470.5		$	1,121.5
Net income attributed to common shareholder	—		—			134.8			134.8
Equity contribution from parent	—		200.0			—			200.0
Return of capital to parent	—		(35.0		)	—			(35.0		)
Dividends to parent	—		—			(108.6		)	(108.6		)
Other	—		3.1			(0.4		)	2.7
Balance at December 31, 2013	$	95.6	$	723.5		$	496.3		$	1,315.4
Net income attributed to common shareholder	—		—			137.6			137.6
Equity contribution from parent	—		55.0			—			55.0
Dividends to parent	—		—			(111.8		)	(111.8		)
Other	—		3.5			(0.3		)	3.2
Balance at December 31, 2014	$	95.6	$	782.0		$	521.8		$	1,399.4
Net income attributed to common shareholder	—		—			122.5			122.5
Equity contribution from parent	—		235.0			—			235.0
Return of capital to parent	—		(150.0		)	—			(150.0		)
Dividends to parent	—		—			(115.1		)	(115.1		)
Other	—		(5.2		)	(0.7		)	(5.9		)
Balance at December 31, 2015	$	95.6	$	861.8		$	528.5		$	1,485.9

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

2015 Form 10-K 51 Wisconsin Public Service Corporation

F. CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31
(in millions, except share and per share data)			2015				2014
Common stock equity
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares outstanding			$	95.6			$	95.6
Additional paid-in capital			861.8				782.0
Retained earnings			528.5				521.8
Total common stock equity			1,485.9				1,399.4
Preferred stock (Note 12)			—				51.2
Long-term debt to parent
	Interest Rate	Year Due
	8.76%	2015	—				2.0
	7.35%	2016	2.9				3.4
Total			2.9				5.4
Current portion of long-term debt to parent			(2.9		)		(2.5		)
Total long-term debt to parent			—				2.9
Long-term debt
First Mortgage Bonds (secured)
	Interest Rate	Year Due
	7.125%	2023	—			*	0.1
Senior Notes (unsecured)
	Interest Rate	Year Due
	6.375%	2015	—				125.0
	5.65%	2017	125.0				125.0
	1.65%	2018	250.0				—
	6.08%	2028	50.0				50.0
	5.55%	2036	125.0				125.0
	3.671%	2042	300.0				300.0
	4.752%	2044	450.0				450.0
Total First Mortgage Bonds and Senior Notes			1,300.0				1,175.1
Unamortized debt issuance costs			(9.9		)		(9.4		)
Unamortized discount on long-term debt			(0.7		)		(0.6		)
Total			1,289.4				1,165.1
Current portion of long-term debt			—				(125.0		)
Total long-term debt			1,289.4				1,040.1
Total capitalization			$	2,775.3			$	2,493.6

* In November 2015, we redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds.

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

2015 Form 10-K 52 Wisconsin Public Service Corporation

G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

We are an electric and natural gas utility company that services customers in northeastern Wisconsin and Michigan's Upper Peninsula. We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates.

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

At December 31, 2015, we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

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

(b) Reclassifications—As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below.

Statements of Income

• Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net.

• Payroll taxes of $8.3 million and $8.9 million for the years ended December 31, 2014 and 2013, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes.

• Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $5.9 million and $6.7 million for the years ended December 31, 2014 and 2013, respectively.

• Certain expenses in other operation and maintenance were reclassified to cost of sales, and depreciation and amortization. The amounts reclassified to other cost of sales were $3.1 million and $5.6 million for the years ended December 31, 2014 and 2013, respectively.

Balance Sheets

• Current regulatory assets of$1.4 millionand$23.6 millionwere reclassified to accounts receivable and long-term regulatory assets, respectively, at December 31, 2014.

• Current regulatory liabilities of$6.1 millionand$15.1 millionwere reclassified to other current liabilities and long-term regulatory liabilities, respectively, at December 31, 2014.

2015 Form 10-K 53 Wisconsin Public Service Corporation

• During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $0.6 million and $8.8 million, previously reported as other current assets and other long-term assets, respectively, were reclassified to offset long-term debt on the December 31, 2014 balance sheet.

• During the fourth quarter of 2015, we also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $3.8 million, previously reported as a component of other current liabilities, to long-term deferred income tax liabilities on the December 31, 2014 balance sheet.

Statements of Cash Flows

• Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections.

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

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

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

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

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

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

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

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

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

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

(in millions)	2015		2014
Fossil fuel	$	76.4	$	48.9
Materials and supplies	40.5		39.2
Natural gas in storage	28.1		36.1
Total	$	145.0	$	124.2

2015 Form 10-K 54 Wisconsin Public Service Corporation

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

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

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

We record straight-line depreciation expense over the estimated useful life of utility property, using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:

Annual Utility Composite Depreciation Rates	2015		2014		2013
Electric	2.70	%	2.73	%	2.79	%
Natural gas	2.15	%	2.17	%	2.19	%

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

We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense.

See Note 7, Property, Plant, and Equipment, for more information.

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

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 7.92%, 8.08%, and 8.61% for 2015, 2014, and 2013, respectively. Our average AFUDC wholesale rates were 5.10%, 6.99%, and 2.64% for 2015, 2014, and 2013, respectively.

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

(in millions)	2015		2014		2013
AFUDC – Debt	$	6.1	$	4.6	$	3.8
AFUDC – Equity	15.1		11.0		9.9

(i) Emission Allowances—We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers.

(j) Goodwill—Goodwill is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performed its annual goodwill impairment test as of April 1, 2015. Interim impairment tests are performed when impairment

2015 Form 10-K 55 Wisconsin Public Service Corporation

indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value.

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

(l) Environmental Remediation Costs — We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 18, Commitments and Contingencies, for more information.

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

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

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

(m) Income Taxes — We and our subsidiary are included in the consolidated United States income tax return filed by Integrys for all tax periods up to and including the tax year ended June 29, 2015. For all tax periods after June 29, 2015, we and our subsidiary are included within the WEC Energy Group consolidated return. Similarly, we and our subsidiary are party to a tax allocation arrangement with Integrys and its consolidated subsidiaries for all tax periods up to and including June 29, 2015, and are a party to a tax allocation arrangement with WEC Energy Group and its consolidated subsidiaries for tax periods ending after June 29, 2015.

Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.

We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.

We report interest and penalties accrued, related to income taxes, as a component of income tax expense in our income statements.

We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.

2015 Form 10-K 56 Wisconsin Public Service Corporation

See Note 15, Income Taxes, for more information regarding our accounting for income taxes.

(n) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 21, Regulatory Environment, for more information.

(o) Employee Benefits—The costs of pension and OPEB are expensed over the periods during which employees render service. The benefit costs associated with employee benefit plans are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information.

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

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

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

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

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

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

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input.

Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available. We recognize transfers at the value as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount for each such item approximates fair value. The fair values of long-term debt, including the current portion of long-term debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity.

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

See Note 19, Fair Value Measurements, for more information.

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

2015 Form 10-K 57 Wisconsin Public Service Corporation

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

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

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 20, Derivative Instruments, for more information.

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

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

NOTE 2—MERGER

On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded at December 31, 2015 related to the proposed construction.

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

In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:

(in millions)	2015
Electric utility segment	$	3.6
Natural gas utility segment	1.0
Total severance expense	$	4.6

NOTE 3—ACQUISITION

In March 2013, we acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved immediately after the purchase.

2015 Form 10-K 58 Wisconsin Public Service Corporation

The purchase included the Fox Energy Center, a 593 MW combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives us a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(in millions)
Assets acquired (1)
Inventories – materials and supplies	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets (2)	15.6
Total assets acquired	$	393.4
Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8

⁽¹⁾  Relates to the electric utility segment.

⁽²⁾  Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information.

Prior to the purchase, we supplied natural gas for the facility and purchased 500 MWs of capacity and the associated energy output under a tolling arrangement. We paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as we are authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.

Our 2015 retail electric rate increase included the recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. See Note 21, Regulatory Environment, for more information. Our rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.

Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by us. The plant is now part of our regulated fleet, used to serve our customers.

NOTE 4—RELATED PARTIES

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

We provide and receive services, property, and other items of value to and from our ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the WEC Merger on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WBS, and a new affiliated interest agreement (Non-WBS AIA) went into effect. The new Non-WBS AIA includes the former Wisconsin Energy Corporation and its subsidiaries. It governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries under new interim WBS affiliated interest agreements (interim WBS AIAs). The Non-WBS AIA includes no other significant changes from the prior Non-IBS affiliated interest agreement. The PSCW and all other relevant state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

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

2015 Form 10-K 59 Wisconsin Public Service Corporation

priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS are priced at cost.

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

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

We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost.

We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC under which either party may be a service provider. Services are billed to and from WRPC under these agreements at a fully allocated cost.

The table below includes information summarizing other transactions entered into with related parties:

(in millions)	December 31, 2015		December 31, 2014
Accounts receivable
Service provided to ATC	$	0.5	$	0.9
Notes payable *
Integrys	2.9		5.4
Accounts payable
Network transmission services from ATC	8.5		8.2
Liability related to income tax allocation
Integrys	5.4		6.1

* WPS Leasing, our consolidated subsidiary, has a note payable to Integrys. At December 31, 2015 and 2014, the current portion of the note payable was $2.9 million and $2.5 million, respectively.

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

(in millions)	2015		2014		2013
Electric transactions
Sales to UPPCO (1)	$	—	$	15.3	$	22.8
Sales to ITF (2)	—		0.1		—
Sales to Wisconsin Electric	0.1		—		—
Natural gas transactions
Sales to Wisconsin Electric	0.4		—		—
Sales to IES (3)	—		0.6		0.5
Purchases from IES (3)	—		2.5		0.9
Interest expense (4)
Integrys	0.3		0.5		0.5
Transactions with equity-method investees
Charges from ATC for network transmission services	101.3		99.0		98.4
Charges to ATC for services and construction	10.3		8.6		9.5
Purchases of energy from WRPC	3.8		3.7		3.7
Charges to WRPC for operations	1.1		1.4		0.9
Equity earnings from WPS Investments, LLC (5)	7.7		9.5		10.2
Sales of electricity to AMP Trillium, LLC (6)	0.1		—		—

⁽¹⁾  Integrys sold UPPCO in August 2014.

⁽²⁾  In February 2016, an agreement was entered into to sell ITF. This sale is scheduled to close in the first quarter of 2016.

⁽³⁾  Integrys sold IES's retail energy business in November 2014.

⁽⁴⁾  WPS Leasing has a note payable to Integrys.

⁽⁵⁾  WPS Investments, LLC is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015, we had an 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC.

⁽⁶⁾  In November 2015, ITF, an indirect wholly-owned subsidiary of Integrys, sold its ownership interest in AMP Trillium, LLC, a joint venture between ITF and AMP Americas, LLC. This joint venture owned and operated compressed natural gas fueling stations.

NOTE 5—SUPPLEMENTAL CASH FLOW INFORMATION

(in millions)	2015		2014			2013
Cash paid for interest, net of amount capitalized	$	58.1	$	56.8		$	43.9
Cash paid (received) for income taxes, net of refunds	14.5		(6.2		)	(27.3		)
Significant non-cash transactions:
Construction costs funded through accounts payable	70.5		54.0			37.3

2015 Form 10-K 61 Wisconsin Public Service Corporation

NOTE 6—REGULATORY ASSETS AND LIABILITIES

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

(in millions)	2015		2014		See Note
Regulatory assets (1) (2)
Unrecognized pension and OPEB costs (3)	$	176.6	$	185.6	17
Environmental remediation costs (4)	104.4		103.8		18
Income tax related items (5)	40.8		32.7
Termination of a tolling agreement with Fox Energy Company LLC	39.1		44.6		3
Crane Creek production tax credits (6)	30.9		32.2
De Pere Energy Center (7)	19.0		21.4
Energy costs recoverable through rate adjustments (8)	12.0		12.6
Other	39.9		25.6
Total regulatory assets	$	462.7	$	458.5
Balance Sheet Presentation
Current assets (9)	$	0.2	$	1.4
Regulatory assets	462.5		457.1
Total regulatory assets	$	462.7	$	458.5

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

⁽²⁾  As of December 31, 2015, we had $21.0 million of regulatory assets not earning a return.

⁽³⁾  Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans.

⁽⁴⁾  As of December 31, 2015, we had not yet made cash expenditures for $83.5 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.

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

⁽⁶⁾  In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12-year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039.

⁽⁷⁾  Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023.

⁽⁸⁾  Represents energy costs that will be recovered from customers in the future.

⁽⁹⁾  Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets.

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

(in millions)	2015		2014		See Note
Regulatory liabilities
Removal costs (1)	$	243.7	$	243.9
Energy costs refundable through rate adjustments (2)	29.4		6.0
Crane Creek depreciation deferral (3)	8.3		8.7
Unrecognized pension and OPEB costs (4)	1.0		42.4		17
Decoupling	—		12.3		21
Other	11.2		11.2
Total regulatory liabilities	$	293.6	$	324.5
Balance Sheet Presentation
Other current liabilities	$	3.6	$	6.1
Regulatory liabilities	290.0		318.4
Total regulatory liabilities	$	293.6	$	324.5

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

⁽²⁾  Represents energy costs that will be refunded to customers in the future.

⁽³⁾  Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.

⁽⁴⁾   Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

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

(in millions)	2015		2014
Electric utility	$	3,722.8	$	3,587.4
Natural gas utility	818.4		773.1
Total utility plant	4,541.2		4,360.5
Less: Accumulated depreciation	1,559.6		1,495.9
Net	2,981.6		2,864.6
CWIP	434.2		248.7
Plant to be retired, net *	—		12.5
Net utility plant	3,415.8		3,125.8
Non-utility plant	8.9		15.2
Less: Accumulated depreciation	6.1		10.0
Net non-utility plant	2.8		5.2
Total property, plant, and equipment	$	3,418.6	$	3,131.0

* In connection with the Consent Decree with the EPA, we retired Weston 1 and Pulliam Units 5 and 6 on June 1, 2015. See Note 18, Commitments and Contingencies, for more information regarding the Consent Decree.

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NOTE 8—JOINTLY OWNED UTILITY FACILITIES

We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. The amounts were as follows at December 31, 2015:

(in millions, except for percentages and MWs)	Weston 4			Columbia Energy Center Units 1 and 2			Edgewater Unit 4
Ownership	70.0		%	31.8		%	31.8		%
Our share of rated capacity (MWs) *	374.5			352.9			96.3
In-service date	2008			1975 and 1978			1969
Utility plant	$	591.5		$	404.6		$	47.6
Accumulated depreciation	$	(150.5	)	$	(122.6	)	$	(30.6	)
CWIP	$	5.9		$	23.4		$	0.4

* Based on expected capacity ratings for summer 2016. 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.

Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects. See Note 18, Commitments and Contingencies, for information related to the requirement to refuel, repower, or retire Edgewater Unit 4.

NOTE 9—ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of fly-ash landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.

The following table shows changes to our AROs:

(in millions)	2015					2014					2013
Balance as of January 1	$	20.3				$	18.0				$	16.7
Accretion	1.2					1.0					0.9
Additions and revisions to estimated cash flows (1)	11.4			(1	)	1.5			(2	)	0.5
Liabilities settled	(0.2		)			(0.2		)			(0.1		)
Balance as of December 31	$	32.7				$	20.3				$	18.0

⁽¹⁾  An ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates.

⁽²⁾  We revised the AROs recorded for the asbestos at our electric generation facilities primarily due to changes in estimated settlement dates.

NOTE 10—GOODWILL AND OTHER INTANGIBLE ASSETS

We had no changes to the carrying amount of goodwill during the years ended December 31, 2015 and 2014. In the second quarter of 2015, we completed our annual goodwill impairment test, and no impairment resulted from this test.

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The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets.

	December 31, 2015							December 31, 2014
(in millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	15.6	$	(7.5	)	$	8.1	$	15.6	$	(4.3	)	$	11.3
Unamortized intangible assets	0.4		—			0.4		—		—			—
Total intangible assets	$	16.0	$	(7.5	)	$	8.5	$	15.6	$	(4.3	)	$	11.3

* Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2015, was approximately three years.

NOTE 11—COMMON EQUITY

Stock-Based Compensation

Our employees were granted awards under Integrys’s stock-based compensation plans. Pursuant to the Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were settled in exchange for the right to be paid out in cash to award recipients. See Note 2, Merger, for more information regarding the merger.

The intrinsic values of the awards settled due to the merger were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options settled was not significant.

Compensation cost associated with stock-based compensation awards was allocated to us based on the percentages used for allocation of the award recipients’ labor costs. The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31:

(in millions)	2015		2014		2013
Stock options	$	—	$	1.0	$	0.7
Performance stock rights	1.3		6.3		1.1
Restricted share units	3.5		3.8		3.4
Total stock-based compensation expense	$	4.8	$	11.1	$	5.2
Deferred income tax benefit	$	1.9	$	4.4	$	2.1

A summary of the activity for our stock-based compensation awards for the year ended December 31, 2015, is presented below:

	Stock Options		Performance Stock Rights		Restricted Stock Units
Outstanding as of January 1, 2015	5,714		13,937		70,544
Granted	—		—		30,174
Dividend equivalents	N/A		N/A		1,267
Transferred	—		—		(166	)
Exercised/Distributed/Vested and Released *	(2,752	)	(2,229	)	(28,428	)
Settled as a result of WEC Merger	(2,962	)	(21,263	)	(73,391	)
Adjustment for performance stock rights distributed or settled	N/A		9,555		N/A
Outstanding as of December 31, 2015	—		—		—

* The intrinsic value of restricted stock unit awards vested and released was $2.2 million. The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant.

Restrictions

Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys.

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

See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2015, restricted retained earnings totaled $528.5 million. Our equity in undistributed earnings of investees accounted for by the equity method was $32.3 million at December 31, 2015.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Integrys may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their other subsidiaries.

NOTE 12—PREFERRED STOCK

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

2015	Shares Authorized	Shares Outstanding	Redemption Price Per Share	Total
$100 par value, Preferred Stock	1,000,000	—	N/A	N/A

2014 (in millions, except share and per share amounts)	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
$100 par value, Preferred Stock	1,000,000
5.00% Series		131,916	$	107.50	$	13.2
5.04% Series		29,983	102.81		3.0
5.08% Series		49,983	101.00		5.0
6.76% Series		150,000	103.35		15.0
6.88% Series		150,000	100.00		15.0
Total					$	51.2

On November 13, 2015, we redeemed all 511,882 outstanding shares of our five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and, (v) 150,000 shares of 6.88% Series. The aggregate redemption price was $52.7 million, plus accumulated and unpaid dividends.

NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings and their corresponding weighted-average interest rates as of December 31 were as follows:

(in millions, except percentages)	2015		2014
Commercial paper
Amount outstanding at December 31	$	182.8	$	145.1
Average interest rate on amounts outstanding at December 31	0.66%		0.32		%
Average amount outstanding during the year *	$	145.0	$	43.3

* Based on daily outstanding balances during the year.

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

2015 Form 10-K 66 Wisconsin Public Service Corporation

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

(in millions)	Maturity	2015
Revolving credit facility *	December 2016	$	250.0
Total short-term credit capacity		$	250.0
Less: commercial paper outstanding		182.8
Available capacity under existing agreement		$	67.2

* We plan to request approval from the PSCW to extend the maturity through December 2020.

In December 2015, we terminated our prior credit facilities and entered into a new credit facility maturing in 2016. The lenders under this facility have agreed that its maturity can be extended to December 2020, subject to our receipt of PSCW approval. This $250.0 million facility has a renewal provision for twoone-year extensions, subject to lender approval.

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

NOTE 14—LONG-TERM DEBT

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

In November 2015, we redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7.125% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption. Following the redemption, we discharged our mortgage indenture and do not intend to issue additional first mortgage bonds. All of our senior notes outstanding are now senior unsecured obligations and rank equally with all of our other unsecured obligations.

In December 2015, our $125.0 million of 6.375% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2015, we issued $250.0 million of 1.65% Senior Notes due December 4, 2018. The proceeds were used to repay short-term debt that we incurred to repay all of our $125.0 million of 6.375% Senior Notes at maturity, and for working capital and other general corporate purposes.

A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to our parent, is as follows:

(in millions)	Payments
2016	$	—
2017	125.0
2018	250.0
2019	—
2020	—
Thereafter	925.0
Total	$	1,300.0

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

2015 Form 10-K 67 Wisconsin Public Service Corporation

NOTE 15—INCOME TAXES

Income Tax Expense

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

(in millions)	2015			2014			2013
Current tax expense	$	31.4		$	(6.1	)	$	2.1
Deferred income taxes, net	44.0			91.1			80.1
Investment tax credit, net	(0.4		)	(0.3		)	(0.3		)
Total income tax expense	$	75.0		$	84.7		$	81.9

Statutory Rate Reconciliation

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

	2015					2014					2013
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
Expected tax at statutory federal tax rates	$	70.1		35.0	%	$	78.9		35.0	%	$	76.9		35.0	%
State income taxes net of federal tax benefit	9.9			5.0		10.9			4.8		10.5			4.8
AFUDC – Equity	(5.3		)	(2.6	)	(3.8		)	(1.7	)	(3.5		)	(1.6	)
Other, net	0.3			0.1		(1.3		)	(0.5	)	(2.0		)	(0.9	)
Total income tax expense	$	75.0		37.5	%	$	84.7		37.6	%	$	81.9		37.3	%

Deferred Income Tax Assets and Liabilities

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

(in millions)	2015		2014
Total deferred tax assets	$	23.9	$	4.4
Deferred tax liabilities
Plant-related	639.1		591.0
Employee benefits and compensation	91.7		83.9
Regulatory deferrals	52.0		42.4
Other	15.2		13.0
Total deferred tax liabilities	798.0		730.3
Deferred tax liability, net	$	774.1	$	725.9

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

Deferred tax credit carryforwards at December 31, 2015, included $2.0 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $3.0 million of general business credits, which have a carryback period of one year and a carryforward period of 20 years. The majority of the general business credit carryforwards will expire in 2033.

At December 31, 2015, we had deferred income tax assets of $16.1 million reflecting federal operating loss carryforwards, which have a carryback period of two years and a carryforward period of 20 years and will expire in 2034.

Unrecognized Tax Benefits

We had no unrecognized tax benefits at December 31, 2015, and 2014.

We had no accrued interest and penalties related to unrecognized tax benefits at December 31, 2015, and 2014.

2015 Form 10-K 68 Wisconsin Public Service Corporation

We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2015.

We file income tax returns in the United States federal jurisdiction and in our major state operating jurisdictions as a part of Integrys filings up to June 29, 2015, and as a part of WEC Energy Group filings for periods after June 29, 2015.

With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2012.

We file state tax returns based on income in our major state operating jurisdictions of Wisconsin and Michigan. We are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2015, we were subject to examination by the Wisconsin taxing authority for tax years 2011 through 2015 and the Michigan taxing authority for tax years 2008 through 2015. During 2015, the Michigan taxing authority continued its examination of tax years 2008 through 2011.

In the next 12 months, we do not expect to significantly change the amount of unrecognized tax benefits.

NOTE 16—GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed		Expiration
(in millions)	at December 31, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	9.5	$	—	$	9.5	$	—
Surety bonds(2)	1.1		1.1		—		—
Other guarantee(3)	20.3		20.0		—		0.3
Total guarantees	$	30.9	$	21.1	$	9.5	$	0.3

⁽¹⁾  At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our balance sheets.

⁽²⁾  Primarily for obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

⁽³⁾  Consists of (a) $20.0 million not reflected on our balance sheet for an interconnection agreement between us and ATC and (b) $0.3 million reflected on our balance sheet related to workers compensation.

NOTE 17—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in the Integrys retirement plan, a noncontributory, qualified pension plan sponsored by WBS. We are responsible for our share of the plan assets and obligations. We serve as plan sponsor and administrator for certain OPEB plans. The benefits are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. Integrys also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred.

The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. In March 2014, we remeasured the obligations of certain OPEB plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015.

2015 Form 10-K 69 Wisconsin Public Service Corporation

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

	Pension Costs						OPEB Costs
(in millions)	2015			2014			2015			2014
Change in benefit obligation
Obligation at January 1	$	791.8		$	717.5		$	252.5		$	292.7
Service cost	10.7			8.6			8.7			7.7
Interest cost	31.7			34.4			10.4			11.5
Plan amendments	—			—			—			(74.4		)
Transfer to affiliates *	(130.5		)	(12.1		)	—			—
Actuarial loss (gain), net	(36.4		)	73.0			(31.7		)	24.0
Participant contributions	—			—			0.3			0.5
Benefit payments	(33.3		)	(29.6		)	(8.6		)	(10.4		)
Federal subsidy on benefits paid	—			—			—			0.9
Plan curtailment	(0.1		)	$	—		—			$	—
Obligation at December 31	$	633.9		$	791.8		$	231.6		$	252.5
Change in fair value of plan assets
Fair value of plan assets at January 1	$	897.4		$	839.1		$	236.6		$	236.5
Actual return on plan assets	(29.4		)	53.1			(5.1		)	7.4
Employer contributions	1.1			46.9			1.3			2.6
Participant contributions	—			—			0.3			0.5
Benefit payments	(33.3		)	(29.6		)	(8.6		)	(10.4		)
Transfer to affiliates *	(116.8		)	(12.1		)	—			—
Fair value at December 31	$	719.0		$	897.4		$	224.5		$	236.6

* Benefit obligations and plan assets were moved along with our employees who were transferred to affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries.

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

	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015			2014
Pension and other postretirement benefit assets	$	93.8	$	128.9	$	8.6		$	—
Current liabilities	—		1.5		—			0.1
Pension and other postretirement benefit liabilities	8.7		21.8		15.7			15.8
Total net assets (liabilities)	$	85.1	$	105.6	$	(7.1	)	$	(15.9	)

The accumulated benefit obligation for the defined benefit pension plans was $569.6 million and $717.4 million at December 31, 2015, and 2014, respectively.

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)	2015		2014
Projected benefit obligation	$	8.7	$	23.3
Accumulated benefit obligation	8.5		21.5

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

	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015		2014
Net regulatory assets
Net actuarial loss	$	61.2	$	178.7	$	5.2	$	41.0
Prior service cost (credit)	—		1.8		—		(78.3		)
Total	$	61.2	$	180.5	$	5.2	$	(37.3	)

2015 Form 10-K 70 Wisconsin Public Service Corporation

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

	Pension Costs									OPEB Costs
(in millions)	2015			2014			2013			2015			2014			2013
Service cost	$	10.7		$	8.6		$	10.8		$	8.7		$	7.7		$	10.6
Interest cost	31.7			34.4			30.6			10.4			11.5			13.4
Expected return on plan assets	(64.8		)	(64.1		)	(57.2		)	(16.0		)	(16.0		)	(14.8		)
Loss on plan settlement	0.1			0.4			—			—			—			—
Amortization of prior service cost (credit)	0.2			0.6			3.6			(9.3		)	(8.0		)	(2.1		)
Amortization of net actuarial loss	21.0			15.0			24.0			3.7			2.8			7.5
Net periodic benefit cost	$	(1.1	)	$	(5.1	)	$	11.8		$	(2.5	)	$	(2.0	)	$	14.6

Assumptions – Pension and Other Postretirement Benefit Plans

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

	Pension		OPEB
	2015	2014	2015	2014
Discount rate	4.49%	4.08%	4.46%	4.11%
Rate of compensation increase	4.00%	4.23%	N/A	N/A
Assumed medical cost trend rate	N/A	N/A	7.50%	6.00%
Ultimate trend rate	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached	N/A	N/A	2021	2023

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

	Pension Costs
	2015	2014	2013
Discount rate	4.08%	4.92%	4.07%
Expected return on assets	7.75%	8.00%	8.00%
Rate of compensation increase	4.23%	4.25%	4.26%

	OPEB Costs
	2015	2014	2013
Discount rate	4.11%	4.78%	4.01%
Expected return on assets	7.75%	8.00%	8.00%
Assumed medical cost trend rate (Pre 65/Post 65)	6.00%	6.50%	7.00%
Ultimate trend rate	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2023	2019	2019

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

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

(in millions)	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	3.8	$	(2.9	)
Effect on the health care component of the accumulated postretirement benefit obligation	31.9		(25.7		)

2015 Form 10-K 71 Wisconsin Public Service Corporation

Plan Assets

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

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

Central to the policy are target allocation ranges by major asset categories. The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans' actuarial assumptions and that are competitive with like instruments employing similar investment strategies. The portfolio diversification provides protection against significant concentrations of risk in the plan assets. In 2014, the pension plan target asset allocation was 70% equity securities and 30% fixed income securities. In December 2014, we changed the pension plan target asset allocation to 60% equity securities and 40% fixed income securities for 2015. The target asset allocation for OPEB plans that have significant assets is 70% equity securities and 30% fixed income securities. Equity securities primarily include investments in large-cap and small-cap companies. Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities.

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

The following tables provide the fair values of our investments by asset class:

	December 31, 2015
	Pension Plan Assets											OPEB Assets
(in millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset class
Cash and cash equivalents	$	—		$	27.4		$	—	$	27.4		$	4.6	$	1.0	$	—	$	5.6
Equity securities:
U.S. Equity	39.2			162.2			—		201.4			11.9		60.0		—		71.9
International Equity	40.3			179.3			—		219.6			15.5		58.5		—		74.0
Fixed income securities: (1)
U.S. Bonds	6.3			218.3			—		224.6			65.1		—		—		65.1
International Bonds	—			55.9			—		55.9			—		—		—		—
	85.8			643.1			—		728.9			97.1		119.5		—		216.6
401(h) other benefit plan assets invested as pension assets (2)	(0.9		)	(7.2		)	—		(8.1		)	0.9		7.2		—		8.1
Total (3)	$	84.9		$	635.9		$	—	$	720.8		$	98.0	$	126.7	$	—	$	224.7

⁽¹⁾  This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

⁽²⁾  Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

⁽³⁾  Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

2015 Form 10-K 72 Wisconsin Public Service Corporation

	December 31, 2014
	Pension Plan Assets											OPEB Assets
(in millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset class
Cash and cash equivalents	$	0.3		$	25.3		$	—	$	25.6		$	3.4	$	1.5			$	4.9
Equity securities:
U.S. Equity	53.3			197.8			—		251.1			14.6		62.4				77.0
International Equity	54.4			225.9			—		280.3			17.6		65.5				83.1
Fixed income securities: (1)
U.S. Bonds	41.3			261.8			—		303.1			62.8		—				62.8
International Bonds	—			44.6			—		44.6			—		—				—
	149.3			755.4			—		904.7			98.4		129.4		—		227.8
401(h) other benefit plan assets invested as pension assets (2)	(1.5		)	(7.3		)	—		(8.8		)	1.5		7.3		—		8.8
Total (3)	$	147.8		$	748.1		$	—	$	895.9		$	99.9	$	136.7	$	—	$	236.6

⁽¹⁾  This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

⁽²⁾  Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

⁽³⁾  Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2014. There was no level 3 activity in 2015.

(in millions)	International Bonds			U.S. Bonds			Total
Beginning balance at January 1, 2014	$	1.3		$	0.7		$	2.0
Net realized and unrealized gains	0.1			0.1			0.2
Sales	(1.4		)	(0.8		)	(2.2		)
Ending balance at December 31, 2014	$	—		$	—		$	—

Cash Flows

We expect to contribute $1.4 million to the pension plans and $2.1 million to OPEB plans in 2016, dependent on various factors affecting us, including our liquidity position and tax law changes.

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

(in millions)	Pension Costs		OPEB Costs
2016	$	46.9	$	9.6
2017	29.6		10.5
2018	29.1		11.4
2019	32.6		12.2
2020	33.7		13.0
2021-2025	172.4		73.7

Savings Plans

Integrys maintains a 401(k) Savings Plan for substantially all of our full-time employees. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution up to certain limits. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. Certain employees participate in a defined contribution pension plan, in which certain amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Our share of the total costs incurred under all of these plans was $9.7 million in 2015, $8.6 million in 2014, and $8.2 million in 2013.

2015 Form 10-K 73 Wisconsin Public Service Corporation

NOTE 18—COMMITMENTS AND CONTINGENCIES

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

Energy Related Purchased Power Agreements

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

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

				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2016		2017		2018		2019		2020		Later Years
Electric utility:
Purchased power	2027	$	732.6	$	85.5	$	53.5	$	56.2	$	57.5	$	59.8	$	420.1
Coal supply and transportation	2019	198.4		97.3		46.5		43.5		11.1		—		—
Natural gas utility supply and transportation	2024	198.1		43.8		42.9		42.4		27.1		14.6		27.3
Total		$	1,129.1	$	226.6	$	142.9	$	142.1	$	95.7	$	74.4	$	447.4

Operating Leases

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

Rental expense attributable to operating leases was $1.4 million, $1.6 million, and $2.3 million in 2015, 2014, and 2013, respectively.

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

Year Ending December 31	Payments (in millions)
2016	$	0.4
2017	0.8
2018	0.6
2019	0.4
2020	0.5
Later years	12.3
Total	$	15.0

Environmental Matters

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

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

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

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

2015 Form 10-K 74 Wisconsin Public Service Corporation

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

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

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

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

• the remediation of former manufactured gas plant sites.

Air Quality

Sulfur Dioxide National Air Ambient Quality Standards

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

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

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO₂. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016.

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

8-Hour Ozone National Air Ambient Quality Standards

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

Mercury and Other Hazardous Air Pollutants

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

Our compliance plans currently include capital projects for our jointly owned plants to achieve the required reductions for MATS. Construction of the ReACT^TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date of July 2016. Controls for acid gases and mercury are already in operation at the Pulliam units.

2015 Form 10-K 75 Wisconsin Public Service Corporation

Although we received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is shut down to complete the construction of the ReACT^TM system.

Climate Change

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

Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO₂ equivalent reduction goal by about 10%. The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule.

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

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, we reported aggregated CO₂ equivalent emissions of approximately 6.2 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 5.7 million metric tonnes to the EPA for 2015. The level of CO₂ and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2014, we reported aggregated CO₂ equivalent emissions of approximately 3.9 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 3.5 million metric tonnes to the EPA for 2015.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

2015 Form 10-K 76 Wisconsin Public Service Corporation

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8 and Weston Units 2 through 4. 

During 2016-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Entrainment studies are currently being conducted at Pulliam Units 7 and 8.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin. Unless pending challenges to the final guidelines are successful, the WDNR will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Pulliam Units 7 and 8 and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $10 million to $20 million for these bottom ash transport systems.

Land Quality

Coal Combustion Residuals Rule

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

Coal Combustion Product Landfill Sites

We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015, 2014, and 2013, landfill remediation expenses were not material. See Note 9, Asset Retirement Obligations, for more information about obligations related to these sites.

2015 Form 10-K 77 Wisconsin Public Service Corporation

Renewables, Efficiency, and Conservation

Wisconsin Act 141

In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we are required to increase our renewable energy percentage to 9.74%. To comply with these requirements, we constructed the Crane Creek wind park. We also rely on renewable energy purchases to meet our renewable portfolio standard commitments.

We are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, that should allow us to remain in compliance through 2023. If market conditions are favorable, we may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of our annual operating revenues.

Manufactured Gas Plant Remediation

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

In addition, some of these sites are coordinating the investigation and cleanup subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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

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

(in millions)	2015		2014
Regulatory assets	$	104.4	$	102.3
Reserves for future remediation	83.5		86.3

Enforcement and Litigation Matters

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

Weston Title V Air Permit

In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, we challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The administrative law judge (ALJ) dismissed some of the petition issues relating to the averaging period and monitoring issues.

2015 Form 10-K 78 Wisconsin Public Service Corporation

In May 2014, the WDNR issued a Notice of Violation (NOV) alleging that we failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler.

In June 2015, the WDNR issued a NOV alleging that we failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied our request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV.

The contested case has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.

Consent Decrees

Consent Decree – Weston and Pulliam

In November 2009, the EPA issued a NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. We entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the U.S. District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes:

• the installation of emission control technology, including ReACT™ on Weston 3,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects totaling $6.0 million, and

• a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023.

We received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. The majority of the beneficial environmental projects proposed by us have been approved by the EPA. We are currently working with the EPA on certain changes to the environmental projects, but these changes are not expected to materially impact the overall cost.

Also, in May 2010, we received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2015. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, Wisconsin Electric (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, Wisconsin Power and Light, Madison Gas and Electric, and Wisconsin Electric entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. The final Consent Decree includes:

• the installation of emission control technology, including scrubbers at the Columbia plant,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects, with our portion totaling $1.3 million, and

• Our portion of a civil penalty and legal fees totaling $0.4 million.

2015 Form 10-K 79 Wisconsin Public Service Corporation

As mentioned above, the Consent Decree contains a requirement to refuel, repower, or retire Edgewater Unit 4, of which we are a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available. All of the beneficial environmental projects that we proposed have been approved by the EPA.

NOTE 19—FAIR VALUE MEASUREMENTS

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

	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.3	$	—	$	—	$	0.3
FTRs	—		—		2.0		2.0
Total derivative assets	$	0.3	$	—	$	2.0	$	2.3
Derivative liabilities
Natural gas contracts	$	0.9	$	—	$	—	$	0.9
Petroleum products contracts	0.5		—		—		0.5
Coal contracts	—		4.7		—		4.7
Total derivative liabilities	$	1.4	$	4.7	$	—	$	6.1

	December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	—	$	0.1	$	—	$	0.1
FTRs	—		—		2.2		2.2
Total derivative assets	$	—	$	0.1	$	2.2	$	2.3
Derivative liabilities
Natural gas contracts	$	2.2	$	—	$	—	$	2.2
FTRs	—		—		0.3		0.3
Petroleum products contracts	1.1		—		—		1.1
Coal contracts	—		1.2		2.2		3.4
Total derivative liabilities	$	3.3	$	1.2	$	2.5	$	7.0

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:

(in millions)	2015			2014			2013
Balance at the beginning of the period	$	(0.3	)	$	(1.3	)	$	(5.4	)
Realized and unrealized (losses) gains	(10.7		)	(1.0		)	3.3
Purchases	9.8			4.3			3.2
Sales	(0.1		)	—			(0.2		)
Settlements	(1.4		)	(3.5		)	(2.2		)
Net transfers out of level 3	4.7			1.2			—
Balance at the end of the period	$	2.0		$	(0.3	)	$	(1.3	)

2015 Form 10-K 80 Wisconsin Public Service Corporation

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

Fair Value of Financial Instruments

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

	December 31, 2015				December 31, 2014
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,289.4	$	1,350.4	$	1,165.1	$	1,286.2
Long-term debt to parent, including current portion	2.9		3.0		5.4		5.7
Preferred stock *	—		—		51.2		52.0

* On November 13, 2015, we redeemed all of our outstanding shares of preferred stock. See Note 12, Preferred Stock, for more information.

NOTE 20—DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:

		December 31, 2015				December 31, 2014
(in millions)	Balance Sheet Presentation	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Natural gas contracts	Other Current	$	0.3	$	0.9	$	0.1	$	2.1
Natural gas contracts	Other Long-term	—		—		—		0.1
Petroleum product contracts	Other Current	—		0.5		—		1.1
FTRs	Other Current	2.0		—		2.2		0.3
Coal contracts	Other Current	—		3.3		—		2.4
Coal contracts	Other Long-term	—		1.4		—		1.0
	Other Current	2.3		4.7		2.3		5.9
	Other Long-term	—		1.4		—		1.1
Total		$	2.3	$	6.1	$	2.3	$	7.0

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

	December 31, 2015				December 31, 2014				December 31, 2013
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas	22.9 Dth	$	(4.9	)	20.0 Dth	$	0.6		15.5 Dth	$	(0.8	)
Petroleum products	6.1 gallons	(1.7		)	5.3 gallons	(0.1		)	2.8 gallons	(0.1		)
FTRs	9.0 MWh	3.3			8.7 MWh	3.2			9.1 MWh	5.1
Total		$	(3.3	)		$	3.7			$	4.2

At December 31, 2015, and December 31, 2014, we had posted collateral of $17.6 million and $6.6 million, respectively, in our margin accounts.

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

	December 31, 2015						December 31, 2014
	Derivative			Derivative			Derivative			Derivative
(in millions)	Assets			Liabilities			Assets			Liabilities
Gross amount recognized on the balance sheet	$	2.3		$	6.1		$	2.3		$	7.0
Gross amount not offset on the balance sheet *	(0.3		)	(1.4		)	(0.4		)	(3.6		)
Net amount	$	2.0		$	4.7		$	1.9		$	3.4

* Includes cash collateral posted of $1.1 million and $3.2 million as of December 31, 2015 and December 31, 2014, respectively.

2015 Form 10-K 81 Wisconsin Public Service Corporation

NOTE 21—REGULATORY ENVIRONMENT

2016 Wisconsin Rate Order

In April 2015, we initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). Based on the order, the PSCW will continue to allow escrow treatment for ATC and MISO network transmission expenses, including any future SSR payments. This allows us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. In addition, the PSCW approved a deferral for ReACT™, which requires us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.

2015 Wisconsin Rate Order

In April 2014, we initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% ROE. The order also included a common equity component of 50.28%. The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014.

The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, we would have realized an electric rate decrease. In addition, we received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information. The PSCW is allowing us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window.

The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, we would have realized a retail natural gas rate increase.

2014 Wisconsin Rate Order

In March 2013, we initiated a rate proceeding with the PSCW. In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% ROE. The order also included a common equity component average of 50.14%. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 18, Commitments and Contingencies, for more information. Additionally, the order required us to terminate our existing decoupling mechanism, beginning January 1, 2014.

2015 Form 10-K 82 Wisconsin Public Service Corporation

2013 Wisconsin Rate Order

In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW issued a final written order, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% ROE and a common equity component average of 51.61%. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that were recovered in 2014 rates. In addition, we were authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct CSAPR costs incurred through the end of 2012. Lastly, the order authorized us to switch from production tax credits to a Section 1603 Grant for the Crane Creek wind project.

A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers were subject to these caps.

2015 Michigan Rate Order

In October 2014, we initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.2% ROE and a common equity component average of 50.48%. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, we will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. We also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. Lastly, we will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

2015 Form 10-K 83 Wisconsin Public Service Corporation

NOTE 22—SEGMENT INFORMATION

At December 31, 2015, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are our electric utility operations and the natural gas utility operations. The other segment includes non-utility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC. Operating income is used to measure segment profitability and to allocate resources to our businesses. All of our operations and assets are located within the United States. The table below presents information related to our reportable segments:

	Regulated Utilities
2015 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,187.8	$	295.5	$	1,483.3	$	—	$	—		$	1,483.3
Intersegment revenues	—		10.7		10.7		0.8		(11.5		)	—
Other operation and maintenance	424.3		69.6		493.9		0.3		(0.8		)	493.4
Depreciation and amortization	103.7		17.0		120.7		0.3		—			121.0
Operating income	194.0		34.0		228.0		0.1		—			228.1
Other income, net	15.6		0.4		16.0		9.6		—			25.6
Interest expense	43.0		10.2		53.2		0.3		—			53.5
Capital expenditures	319.4		51.6		371.0		—		—			371.0
Total assets	3,718.9		697.9		4,416.8		88.3		—			4,505.1
	Regulated Utilities
2014 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,223.7	$	459.9	$	1,683.6	$	—	$	—		$	1,683.6
Intersegment revenues	—		12.4		12.4		1.4		(13.8		)	—
Other operation and maintenance	425.8		73.5		499.3		0.4		—			499.7
Depreciation and amortization	100.5		16.2		116.7		0.6		(0.5		)	116.8
Operating income	204.8		52.4		257.2		0.4		—			257.6
Other income, net	11.7		0.6		12.3		12.9		—			25.2
Interest expense	45.1		10.2		55.3		2.1		—			57.4
Capital expenditures	272.7		49.3		322.0		—		—			322.0
Total assets	3,503.0		680.9		4,183.9		85.4		—			4,269.3
	Regulated Utilities
2013 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,243.0	$	337.5	$	1,580.5	$	—	$	—		$	1,580.5
Intersegment revenues	—		10.9		10.9		1.4		(12.3		)	—
Other operation and maintenance	405.0		65.1		470.1		0.3		—			470.4
Depreciation and amortization	93.7		15.6		109.3		0.6		(0.5		)	109.4
Operating income	189.5		50.0		239.5		0.5		—			240.0
Other income, net	9.9		0.2		10.1		13.4		—			23.5
Interest expense	33.0		8.5		41.5		2.2		—			43.7
Capital expenditures	590.3		37.4		627.7		—		—			627.7
Total assets	3,233.6		632.3		3,865.9		85.7		—			3,951.6

2015 Form 10-K 84 Wisconsin Public Service Corporation

NOTE 23—QUARTERLY FINANCIAL INFORMATION (Unaudited)

(in millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2015
Operating revenues	$	425.0	$	330.3	$	390.8	$	337.2	$	1,483.3
Operating income	69.9		44.2		88.5		25.5		228.1
Net income attributed to common shareholder	39.0		22.6		50.3		10.6		$	122.5
2014
Operating revenues	$	556.0	$	359.0	$	370.9	$	397.7	$	1,683.6
Operating income	87.4		36.3		77.7		56.2		257.6
Net income attributed to common shareholder	50.3		17.1		42.2		28.0		137.6

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

NOTE 24—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

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

Classification and Measurement of Financial Instruments

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

Leases

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

2015 Form 10-K 85 Wisconsin Public Service Corporation

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (a) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (b) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2015.

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

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this annual report.

Changes in Internal Control

There were no changes in our internal control over financial reporting during the fourth quarter of 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2015, the WEC Merger was completed. WEC Energy Group is currently in the process of integrating and aligning the operations, processes, and internal controls of the combined company. See Note 2, Merger, for more information.

ITEM 9B. OTHER INFORMATION

None.

2015 Form 10-K 86 Wisconsin Public Service Corporation

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Omitted pursuant to General Instruction I(2)c.

ITEM 11. EXECUTIVE COMPENSATION

Omitted pursuant to General Instruction I(2)c.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Omitted pursuant to General Instruction I(2)c.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Omitted pursuant to General Instruction I(2)c.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following is a summary of the fees for professional services provided to us by Deloitte & Touche LLP in 2015 and 2014:

Fees	2015		2014
Audit fees (1)	$	1,062,678	$	988,466
All other fees (2)	26,550		990
Total fees	$	1,089,228	$	989,456

⁽¹⁾  Audit Fees. Consists of aggregate fees for the audits of the annual consolidated financial statements and reviews of the interim condensed consolidated financial statements included in quarterly reports. Audit fees also include services that are normally provided by Deloitte & Touche LLP in connection with statutory and regulatory filings or engagements, including comfort letters, consents, and other services related to SEC matters, and consultations arising during the course of the audits and reviews concerning financial accounting and reporting standards.

⁽²⁾  All Other Fees. Consists of fees for services provided to us by Deloitte & Touche LLP for products and services other than the services reported above. All Other Fees relate to a WPS file review in 2015 and to training provided in 2014.

In considering the nature of the services provided by the independent registered public accounting firm, the Audit Committee of the Board of Directors of Integrys (Audit Committee), prior to the WEC Merger, determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with the independent registered public accounting firm and Integrys's management at the time and determined that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as those of the American Institute of Certified Public Accountants. The Audit Committee approved in advance 100% of the audit services described above in accordance with its pre-approval policy at the time.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor

The Audit and Oversight Committee (Audit Committee) of the Board of Directors of WEC Energy Group, which is comprised solely of independent directors, is responsible for appointing and overseeing our independent auditor. The Committee has the sole and ultimate authority to appoint, retain, and evaluate the services of the independent auditor. The Audit Committee is committed to ensuring the independence of the auditor, both in appearance as well as in fact. When evaluating the independence of the auditor, the Audit Committee considers whether a relationship with or service provided by the auditor:

• creates a mutual or conflicting interest with WEC Energy Group or its subsidiaries;

• places the auditor in the position of auditing their own work;

• results in the auditor functioning as management or employees of WEC Energy Group or its subsidiaries; or

• places the auditor in a position of being an advocate for WEC Energy Group or its subsidiaries.

2015 Form 10-K 87 Wisconsin Public Service Corporation

Pre-Approval Process

Before engagement of the independent auditor for the next year's audit, the independent auditor will submit (i) a description of all services anticipated to be rendered during the following year, as well as an estimate of the fees for each of the services, for the Audit Committee to approve, and (ii) written confirmation that the performance of any non-audit services is permissible and will not impact the firm's independence. Annual pre-approval will be deemed effective for a period of twelve months from the date of the pre-approval, unless the Audit Committee specifically provides for a different period. A fee level will be established for all permissible, pre-approved non-audit services. Any additional audit service, audit related service, tax service and other service must also be pre-approved.

The Audit Committee delegates pre-approval authority to the Audit Committee's chair. The Audit Committee chair shall report any pre-approval decisions at the next Audit Committee meeting. Under the pre-approval policy, the Audit Committee may not delegate to management its responsibilities to pre-approve services performed by the independent auditor.

Prohibited Activities are services prohibited by the SEC or by the Public Company Accounting Oversight Board to be performed by our independent auditor. These services include:

• bookkeeping or other services related to the accounting records or financial statements of the Corporation;

• financial information systems design and implementation;

• appraisal or valuation services, fairness opinions or contribution-in-kind reports;

• actuarial services;

• internal audit outsourcing services;

• management functions or human resources;

• broker-dealer, investment advisor or investment banking services;

• legal services and expert services unrelated to the audit;

• services provided for a contingent fee or commission; and

• services related to planning, marketing or opining in favor of the tax treatment of a confidential transaction or aggressive tax position transaction that was initially recommended, directly or indirectly, by the independent auditor.

In addition, the independent auditor may not provide any services, including personal financial counseling and tax services, to any officer or other employee of WEC Energy Group or its subsidiaries in a financial reporting oversight role or chair of the Audit Committee or to an immediate family member of these individuals, including spouses, spousal equivalents, and dependents.

2015 Form 10-K 88 Wisconsin Public Service Corporation

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Documents filed as part of this report:

(1) Consolidated Financial Statements included in Part II at Item 8 above:

	Description	Pages in 10-K
1.	Financial Statements and Reports of Independent Registered Public Accounting Firm Included in Part II of This Report
	Report of Independent Registered Public Accounting Firm	47
	Consolidated Income Statements for the three years ended December 31, 2015, 2014, and 2013	48
	Consolidated Balance Sheets as of December 31, 2015, and 2014	49
	Consolidated Statements of Cash Flows for the three years ended December 31, 2015, 2014, and 2013	50
	Consolidated Statements of Equity as of December 31, 2015, 2014, and 2013	51
	Consolidated Statements of Capitalization as of December 31, 2015, and 2014	52
	Notes to Consolidated Financial Statements	53
2.	Financial Statement Schedules Included in Part IV of This Report
	Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2015, 2014, and 2013.	90
	Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
3.	Exhibits and Exhibit Index
	See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.	92

2015 Form 10-K 89 Wisconsin Public Service Corporation

SCHEDULE II

WISCONSIN PUBLIC SERVICE CORPORATION

VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts (in millions)	Balance at Beginning of the Period		Expense (1)		Net Write-offs (2)			Balance at End of the Period
December 31, 2015	$	3.2	$	6.7	$	(7.4	)	$	2.5
December 31, 2014	$	2.5	$	7.3	$	(6.6	)	$	3.2
December 31, 2013	$	2.5	$	5.2	$	(5.2	)	$	2.5

⁽¹⁾  Net of recoveries.

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

2015 Form 10-K 90 Wisconsin Public Service Corporation

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		WISCONSIN PUBLIC SERVICE CORPORATION
	By	/s/ALLEN L. LEVERETT
Date:	February 26, 2016	Allen L. Leverett
		Chairman, Chief Executive Officer and President

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

/s/ALLEN L. LEVERETT	February 26, 2016
Allen L. Leverett, Chairman, Chief Executive Officer and
President, and Director -- Principal Executive Officer
/s/J. PATRICK KEYES	February 26, 2016
J. Patrick Keyes, Executive Vice President and Chief
Financial Officer and Director -- Principal Financial Officer
/s/WILLIAM J. GUC	February 26, 2016
William J. Guc, Vice President and
Controller -- Principal Accounting Officer
/s/J. KEVIN FLETCHER	February 26, 2016
J. Kevin Fletcher, Director
/s/SUSAN H. MARTIN	February 26, 2016
Susan H. Martin, Director

2015 Form 10-K 91 Wisconsin Public Service Corporation

WISCONSIN PUBLIC SERVICE COMPANY

(Commission File No. 01-3016)

EXHIBIT INDEX

to

Annual Report on Form 10-K

For the year ended December 31, 2015

Set forth below is a listing of all exhibits to this Annual Report on Form 10-K, including those incorporated by reference.

Exhibit Number	Description of Documents
2	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1* #	Purchase and Sale Agreement among WPS, Fox Energy OP, L.P., and Fox River Power LLC, dated as of September 28, 2012. (Incorporated by reference to Exhibit 2 to WPS's Form 10-Q/A for the quarter ended September 30, 2012, filed April 1, 2013.)
3	Articles of Incorporation and By-laws
3.1	Restated Articles of Incorporation of WPS as effective May 26, 1972, and amended through May 31, 1988 and Articles of Amendment to Restated Articles of Incorporation of WPS dated June 9, 1993. (Incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-3, Reg. No. 333-182491, filed July 2, 2012.)
3.2	By-Laws of WPS, as amended through June 29, 2015.
4	Instruments defining the rights of security holders, including indentures
4.1	Indenture, dated as of December 1, 1998, between Wisconsin Public Service Corporation ("WPS") and U.S. Bank National Association (successor to Firstar Bank Milwaukee, N.A., National Association) (Exhibit 4A to Form 8-K filed December 18, 1998); First Supplemental Indenture, dated as of December 1, 1998, between WPS and Firstar Bank Milwaukee, N.A., National Association (Exhibit 4C to Form 8-K filed December 18, 1998); Fifth Supplemental Indenture, dated as of December 1, 2006, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 30, 2006); Seventh Supplemental Indenture, dated as of November 1, 2007, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 16, 2007); Ninth Supplemental Indenture, dated as of December 1, 2012, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 29, 2012); Tenth Supplemental Indenture, dated as of November 1, 2013, by and between WPS and U.S. Bank Nation Association (Exhibit 4.1 to Form 8-K filed November 18, 2013); Eleventh Supplemental Indenture, dated as of December 4, 2015, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed December 4, 2015) All references to periodic reports are to those of WPS (File No. 1-3016).
	Certain agreements and instruments with respect to unregistered debt not exceeding 10% of the total assets of us and our subsidiary on a consolidated basis have been omitted as permitted by related instructions. We agree pursuant to Item 601(b)(4) of Regulation S-K to furnish a copy of any such agreement or instrument to the SEC upon request.
10	Material Contracts
10.1* #	Joint Plant Agreement by and between WPS and Dairyland Power Cooperative, dated as of November 23, 2004. (Incorporated by reference to Exhibit 10.19 to Integrys Energy Group's and WPS's Form 10-K for the year ended December 31, 2004.)
10.2	Revised Agreement for Construction and Operation of Columbia Generating Plant among WPS, Wisconsin Power and Light Company, and Madison Gas and Electric Company, dated July 26, 1973. (Incorporated by reference to Exhibit 5.07 in File No. 2-48781.)
	Note: Two asterisks (**) identify management contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10-K. Certain compensatory plans, contracts or arrangements in which directors or executive officers of WPS participate are not filed as WPS exhibits in reliance on the exclusion in Item 601(b)(10)(iii)(C)(6) of Regulation S-K. WPS is a wholly-owned subsidiary of WEC Energy Group, Inc., Commission File No. 001-09057, and such compensatory plans, contracts or arrangements are filed as exhibits to WEC Energy Group’s periodic reports under the Securities Exchange Act of 1934.
23	Consents of experts and counsel
23.1	Consent of Independent Registered Public Accounting Firm for WPS.
31	Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS.
32	Section 1350 Certifications
32.1	Written Statement of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350 for WPS.

2015 Form 10-K 92 Wisconsin Public Service Corporation

32.2	Written Statement of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS.
101	Interactive Data File

*	Schedules and exhibits to this document are not filed therewith. The registrant agrees to furnish supplementally a copy of any such schedule or exhibit to the SEC upon request.
#	Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of SEC pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934, as amended. The redacted material was filed separately with the SEC.
	Exhibit 21 has been omitted pursuant to General Instruction I(2)b.

2015 Form 10-K 93 Wisconsin Public Service Corporation

EX-3.2

Exhibit 3.2

BYLAWS

of

WISCONSIN PUBLIC SERVICE CORPORATION

As Amended to June 29, 2015, Inclusive

Exhibit 3.2

WISCONSIN PUBLIC SERVICE CORPORATION

BY-LAWS

As In Effect June 29, 2015

ARTICLE I. OFFICES

1. Principal Office

The principal office of the Corporation in the State of Wisconsin shall be in the City of Green Bay. The Corporation may also have offices at such other places, within and outside of the State of Wisconsin, as the Board of Directors may designate or as the business of the Corporation may require.

2. Registered Office

The Board of Directors shall designate the registered office of the Corporation and may change such registered office by resolution.

ARTICLE II. SHAREHOLDERS

1. Annual Meeting

The annual meeting of the shareholders ("Annual Meeting") shall be held each year at such time or on such day as may be designated by resolution of the Board of Directors. In fixing a meeting date for any Annual Meeting, the Board of Directors may consider such factors as it deems relevant within the good faith exercise of its business judgment.

2. Purposes of Annual Meeting

At each Annual Meeting, the shareholders shall elect the directors and transact such other business as may properly come before the Annual Meeting in accordance with Section 14 of Article II of these By‑laws. If the election of directors shall not be held on the date fixed as herein provided, for any Annual Meeting, or any adjournment thereof, the Board of Directors shall cause the election to be held at a special meeting of shareholders (a "Special Meeting") as soon thereafter as is practicable.

3. Special Meetings

a. A Special Meeting may be called only by (i) the Board of Directors, (ii) the Chairman of the Board, (iii) the Chief Executive Officer, (iv) a President or (v) the Secretary and shall be called by the Corporation upon the demand,

2

Exhibit 3.2

in accordance with this Section 3, of the holders of record of shares representing at least 10% of all the votes entitled to be cast on any issue proposed to be considered at the Special Meeting.

b. In order that the Corporation may determine the shareholders entitled to demand a Special Meeting, the Board of Directors may fix a record date to determine the shareholders entitled to make such a demand (the "Demand Record Date"). The Demand Record Date shall not precede the date upon which the resolution fixing the Demand Record Date is adopted by the Board of Directors and shall not be more than ten days after the date upon which the resolution fixing the Demand Record Date is adopted by the Board of Directors. Any shareholder of record seeking to have shareholders demand a Special Meeting shall, by sending written notice to the Secretary of the Corporation by hand or by certified or registered mail, return receipt requested, request the Board of Directors to fix a Demand Record Date. The Board of Directors shall promptly, but in all events within ten days after the date on which a valid request to fix a Demand Record Date is received, adopt a resolution fixing the Demand Record Date and shall make a public announcement of such Demand Record Date. If no Demand Record Date has been fixed by the Board of Directors within ten days after the date on which such request is received by the Secretary, the Demand Record Date shall be the 10th day after the first date on which a valid written request to set a Demand Record Date is received by the Secretary. To be valid, such written request shall set forth the purpose or purposes for which the Special Meeting is to be held, shall be signed by one or more shareholders of record (or their duly authorized proxies or other representatives), shall bear the date of signature of each such shareholder (or proxy or other representative) and shall set forth all information about each such shareholder and about the beneficial owner or owners, if any, on whose behalf the request is made that would be required to be set forth in a shareholder's notice described in paragraph (a) (ii) of Section 14 of this Article II.

c. In order for a shareholder or shareholders to demand a Special Meeting, a written demand or demands for a Special Meeting by the holders of record as of the Demand Record Date of shares representing at least 10% of all the votes entitled to be cast on any issue proposed to be considered at the Special Meeting must be delivered to the Corporation. To be valid, each written demand by a shareholder for a Special Meeting shall set forth the specific purpose or purposes for which the Special Meeting is to be held (which purpose or purposes shall be limited to the purpose or purposes set forth in the written request to set a Demand Record Date received by the Corporation pursuant to paragraph (b) of this Section 3), shall be signed by one or more persons who as of the Demand Record Date are shareholders of record (or their duly authorized proxies or other representatives), shall bear the date of signature of each such shareholder (or proxy or other representative), and shall set forth the name and

3

Exhibit 3.2

address, as they appear in the Corporation's books, of each shareholder signing such demand and the class and number of shares of the Corporation which are owned of record and beneficially by each such shareholder, shall be sent to the Secretary by hand or by certified or registered mail, return receipt requested, and shall be received by the Secretary within seventy days after the Demand Record Date.

d. The Corporation shall not be required to call a Special Meeting upon shareholder demand unless, in addition to the documents required by paragraph (c) of this Section 3, the Secretary receives a written agreement signed by each Soliciting Shareholder (as defined below), pursuant to which each Soliciting Shareholder, jointly and severally, agrees to pay the Corporation's costs of holding the Special Meeting, including the costs of preparing and mailing proxy materials for the Corporation's own solicitation, provided that if each of the resolutions introduced by any Soliciting Shareholder at such meeting is adopted, and each of the individuals nominated by or on behalf of any Soliciting Shareholder for election as a director at such meeting is elected, then the Soliciting Shareholders shall not be required to pay such costs. For purposes of this paragraph (d), the following terms shall have the meanings set forth below:

(i) "Affiliate" of any Person (as defined herein) shall mean any Person controlling, controlled by or under common control with such first Person.

(ii) "Participant" shall have the meaning assigned to such term in Rule 14a-11 promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act").

(iii) "Person" shall mean any individual, firm, corporation, partnership, joint venture, association, trust, unincorporated organization or other entity.

(iv) "Proxy" shall have the meaning assigned to such term in Rule 14a‑1 promulgated under the Exchange Act.

(v) "Solicitation" shall have the meaning assigned to such term in Rule 14a‑11 promulgated under the Exchange Act.

(vi) "Soliciting Shareholder" shall mean, with respect to any Special Meeting demanded by a shareholder or shareholders, any of the following Persons:

(a) if the number of shareholders signing the demand or demands of meeting delivered to the Corporation pursuant to paragraph (c) of this Section 3 is ten or fewer, each shareholder signing any such demand;

4

Exhibit 3.2

(b) if the number of shareholders signing the demand or demands of meeting delivered to the Corporation pursuant to paragraph (c) of this Section 3 is more than ten, each Person who either (I) was a Participant in any Solicitation of such demand or demands or (II) at the time of the delivery to the Corporation of the documents described in paragraph (c) of this Section 3 had engaged or intends to engage in any Solicitation of Proxies for use at such Special Meeting (other than a Solicitation of Proxies on behalf of the Corporation); or

(c) any Affiliate of a Soliciting Shareholder, if a majority of the directors then in office determine, reasonably and in good faith, that such Affiliate should be required to sign the written notice described in paragraph (c) of this Section 3 and/or the written agreement described in this paragraph (d) in order to prevent the purposes of this Section 3 from being evaded.

e. Except as provided in the following sentence, any Special Meeting shall be held at such hour and day as may be designated by whichever of the Board of Directors, the Chairman of the Board, the Chief Executive Officer, a President or the Secretary shall have called such meeting. In the case of any Special Meeting called by the Chairman of the Board, the Chief Executive Officer, a President or the Secretary upon the demand of shareholders (a "Demand Special Meeting"), such meeting shall be held at such hour and day as may be designated by the Board of Directors; provided, however, that the date of any Demand Special Meeting shall be not more than seventy days after the Meeting Record Date (as defined in Section 6 of Article II of these By‑laws); and provided further that in the event that the directors then in office fail to designate an hour and date for a Demand Special Meeting within ten days after the date that valid written demands for such meeting by the holders of record as of the Demand Record Date of shares representing at least 10% of all the votes entitled to be cast on each issue proposed to be considered at the Special Meeting are delivered to the Corporation (the "Delivery Date"), then such meeting shall be held at 2:00 P.M. local time on the 100th day after the Delivery Date or, if such 100th day is not a Business Day (as defined below), on the first preceding Business Day. In fixing a meeting date for any Special Meeting, the Board of Directors, the Chairman of the Board, the Chief Executive Officer, a President or the Secretary may consider such factors as it or he deems relevant within the good faith exercise of its or his business judgment, including, without limitation, the nature of the action proposed to be taken, the facts and circumstances surrounding any demand for such meeting, and any plan of the Board of Directors to call an Annual Meeting or a Special Meeting for the conduct of related business.

5

Exhibit 3.2

f. The Corporation may engage regionally or nationally recognized independent inspectors of elections to act as an agent of the Corporation for the purpose of promptly performing a ministerial review of the validity of any purported written demand or demands for a Special Meeting received by the Secretary. For the purpose of permitting the inspectors to perform such review, no purported demand shall be deemed to have been delivered to the Corporation until the earlier of (i) five Business Days following receipt by the Secretary of such purported demand and (ii) such date as the independent inspectors certify to the Corporation that the valid demands received by the Secretary represent at least 10% of all the votes entitled to be cast on each issue proposed to be considered at the Special Meeting. Nothing contained in this paragraph (f) shall in any way be construed to suggest or imply that the Board of Directors or any shareholder shall not be entitled to contest the validity of any demand, whether during or after such five Business Day period, or to take any other action (including, without limitation, the commencement, prosecution or defense of any litigation with respect thereto).

g. For purposes of these By‑laws, "Business Day" shall mean any day other than a Saturday, a Sunday or a day on which banking institutions in the State of Wisconsin are authorized or obligated by law or executive order to close.

4. Place of Meeting

The Board of Directors, the Chairman of the Board, the Chief Executive Officer, a President or the Secretary may designate any place, either within or without the State of Wisconsin, as the place of meeting for any Annual Meeting or for any Special Meeting or for any postponement or adjournment thereof. If no designation is made, the place of meeting shall be the principal business office of the Corporation in the State of Wisconsin. Any meeting may be adjourned to reconvene at any place designated by vote of the Board of Directors or by the Chairman of the Board, the Chief Executive Officer, a President or the Secretary.

5. Notice of Meeting

Written or printed notice stating the date, time and place of any Annual Meeting or Special Meeting shall be delivered not less than ten days (unless a longer period is required by the Wisconsin Business Corporation Law or the Articles of Incorporation of the Corporation) nor more than 70 days before the date of such meeting either personally or by mail, by or at the direction of the Chairman of the Board, the Chief Executive Officer, a President or the Secretary, to each shareholder of record entitled to vote at such meeting and to such other shareholders as required by the Wisconsin Business Corporation Law. In the event of any Demand Special Meeting, such notice shall be sent not more than 45 days after the Delivery Date. If mailed, notice pursuant to this Section 5 shall be deemed to be effective when deposited in the United States mail, addressed

6

Exhibit 3.2

to the shareholder at his address as it appears on the stock record books of the Corporation, with postage thereon prepaid. Unless otherwise required by the Wisconsin Business Corporation Law or the Articles of Incorporation of the Corporation, a notice of an Annual Meeting need not include a description of the purpose for which the meeting is called. In the case of any Special Meeting, (a) the notice of meeting shall describe any business that the Board of Directors shall have theretofore determined to bring before the meeting and (b) in the case of a Demand Special Meeting, the notice of meeting (i) shall describe any business set forth in the statement of purpose of the demands received by the Corporation in accordance with Section 3 of this Article II and (ii) shall contain all of the information required in the notice received by the Corporation in accordance with Section 14(b) of this Article II. If an Annual Meeting or Special Meeting is adjourned to a different date, time or place, the Corporation shall not be required to give notice of the new date, time or place if the new date, time or place is announced at the meeting before adjournment; provided, however, that if a new Meeting Record Date for an adjourned meeting is or must be fixed, the Corporation shall give notice of the adjourned meeting to persons who are shareholders as of the new Meeting Record Date.

6. Fixing of Record Date

The Board of Directors may fix in advance a date not less than 10 days and not more than 70 days prior to the date of any Annual Meeting or Special Meeting (other than a Demand Special Meeting) as the record date for the purpose of determining shareholders entitled to notice of, and to vote at, such meeting ("Meeting Record Date"). If a Meeting Record Date is not fixed by the Board of Directors or by the Wisconsin Business Corporation Law for any Annual Meeting or Special Meeting (other than a Demand Special Meeting), the Meeting Record Date shall be the close of business on the day before the first notice is given to Shareholders. In the case of any Demand Special Meeting, (i) the Meeting Record Date shall not be later than the 30^th day after the Delivery Date and (ii) if the Board of Directors fails to fix the Meeting Record Date within 30 days after the Delivery Date, then the close of business on such 30^th day shall be the Meeting Record Date. The shareholders of record on the Meeting Record Date shall be the shareholders entitled to notice of, and to vote at, the meeting. Except as provided by the Wisconsin Business Corporation Law for a court-ordered adjournment, a determination of shareholders entitled to notice of, and to vote at, any Annual Meeting or Special Meeting is effective for any adjournment of such meeting unless the Board of Directors fixes a new Meeting Record Date, which it shall do if the meeting is adjourned to a date more than 120 days after the date fixed for the original meeting. The Board of Directors may also fix in advance a date as the record date for the purpose of determining shareholders entitled to take any other action or determining shareholders for any other purpose. Such record date shall be not more than 70 days prior to the date on which the particular action, requiring such determination of shareholders, is to be taken. The record date for determining shareholders entitled to a distribution (other than a distribution involving a purchase, redemption or other acquisition of

7

Exhibit 3.2

the Corporation's shares) or a share dividend is the date on which the Board of Directors authorizes the distribution or share dividend, as the case may be, unless the Board of Directors fixes a different record date.

7. Voting Records

After a Meeting Record Date has been fixed, the Corporation shall prepare a list of the names of all of the shareholders entitled to notice of the meeting. The list shall be arranged by class or series of shares, if any, and show the address of, and number of shares held by, each shareholder. Such list shall be available for inspection by any shareholder, beginning two business days after notice of the meeting is given for which the list was prepared and continuing to the date of the meeting, at the Corporation's principal office or at a place identified in the meeting notice in the city where the meeting will be held. A shareholder or his agent may, on written demand, inspect and, subject to the limitations imposed by the Wisconsin Business Corporation Law, copy the list, during regular business hours and at his or her expense, during the period that it is available for inspection pursuant to this Section 7. The Corporation shall make the shareholders' list available at the meeting and any shareholder or his or her agent or attorney may inspect the list at any time during the meeting or any adjournment thereof. Refusal or failure to prepare or make available the shareholders' list shall not affect the validity of any action taken at a meeting of shareholders.

8. Quorum and Voting Requirements; Postponements; Adjournments

a. Shares entitled to vote as a separate voting group may take action on a matter at any Annual Meeting or Special Meeting only if a quorum of those shares exists with respect to that matter. If the Corporation has only one class of stock outstanding, such class shall constitute a separate voting group for purposes of this Section 8. Except as otherwise provided in the Articles of Incorporation of this Corporation or the Wisconsin Business Corporation Law, a majority of the votes entitled to be cast on the matter shall constitute a quorum of the voting group for action on that matter. Once a share is represented for any purpose at any Annual Meeting or Special Meeting, other than for the purpose of objecting to holding the meeting or transacting business at the meeting, it is considered present for purposes of determining whether a quorum exists for the remainder of the meeting and for any adjournment of that meeting, unless a new Meeting Record Date is or must be set for the adjourned meeting. If a quorum exists, except in the case of the election of directors, action on a matter shall be approved if the votes cast within the voting group favoring the action exceed the votes cast opposing the action, unless the Articles of Incorporation of the Corporation or the Wisconsin Business Corporation Law requires a greater number of affirmative votes. Unless otherwise provided in the Articles of Incorporation of the Corporation, each director shall be elected by a plurality of the votes cast by the shares entitled to

8

Exhibit 3.2

vote in the election of directors at any Annual Meeting or Special Meeting at which a quorum is present.

b. The Board of Directors acting by resolution may postpone and reschedule any previously scheduled Annual Meeting or Special Meeting; provided, however, that a Demand Special Meeting shall not be postponed beyond the 100^th day following the Delivery Date. Any Annual Meeting or Special Meeting may be adjourned from time to time, whether or not there is a quorum, (i) at any time, upon a resolution of shareholders if the votes cast in favor of such resolution by the holders of shares of each voting group entitled to vote on any matter theretofore properly brought before the meeting exceed the number of votes cast against such resolution by the holders of shares of each such voting group or (ii) at any time prior to the transaction of any business at such meeting, by the Chairman of the Board, the Chief Executive Officer, a President or the Secretary or pursuant to a resolution of the Board of Directors. No notice of the time and place of adjourned meetings need be given except as required by the Wisconsin Business Corporation Law. At any adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the meeting as originally notified.

9. Conduct of Meetings

The Chairman of the Board, and in his or her absence, the Vice Chairman of the Board, and in his or her absence, the Chief Executive Officer, and in his or her absence, a President, and in their absence, a Vice President in the order provided under Section 5 of Article IV of these By‑laws, and in their absence, any person chosen by the shareholders present shall call any Annual Meeting or Special Meeting to order and shall act as chairman of such meeting, and the Secretary of the Corporation shall act as secretary of all Annual Meetings and Special Meetings, but in the absence of the Secretary, the presiding officer may appoint any other person to act as secretary of the meeting.

10. Proxies

At all meetings of shareholders, a shareholder entitled to vote may vote his or her or its shares in person or by proxy. A shareholder entitled to vote at a meeting of shareholders may authorize another person to act for the shareholder by appointing the person as proxy. Without limiting the manner in which a shareholder may appoint a proxy, a shareholder or the shareholder's authorized officer, director, employee, agent or attorney-in-fact may use any of the following as a valid means to make such an appointment:

a. Appointment of a proxy in writing by signing or causing the shareholder's signature to be affixed to an appointment form by any reasonable means, including, but not limited to, by facsimile signature.

9

Exhibit 3.2

b. Appointment of a proxy by transmitting or authorizing the transmission of an electronic transmission of the appointment to the person who will be appointed as proxy or to a proxy solicitation firm, proxy support service organization or like agent authorized to receive the transmission by the person who will be appointed as proxy. Every electronic transmission shall contain, or be accompanied by, information that can be used to reasonably determine that the shareholder transmitted or authorized the transmission of the electronic transmission. Any person charged with determining whether a shareholder transmitted or authorized the transmission of the electronic transmission shall specify the information upon which the determination is made.

An appointment of a proxy is effective when a signed appointment form or an electronic transmission of the appointment is received by the inspector of elections or the officer or agent of the Corporation authorized to tabulate votes. An appointment is valid for 11 months unless a different period is expressly provided in the appointment. Unless otherwise provided, a proxy may be revoked any time before it is voted, either by appointing a new proxy in accordance with the Wisconsin Business Corporation Law or by oral notice given by the shareholder to the presiding officer during the meeting. The presence of a shareholder who has made an effective proxy appointment shall not itself constitute a revocation. The Board of Directors shall have the power and authority to make rules establishing presumptions as to the validity and sufficiency of proxies.

11. Voting of Shares

a. Each outstanding share shall be entitled to one vote upon each matter submitted to a vote at any Annual Meeting or Special Meeting, except to the extent that the voting rights of the shares of any class or classes are enlarged, limited or denied by the Wisconsin Business Corporation Law or the Articles of Incorporation of the Corporation.

b. Shares held by another corporation, if a sufficient number of shares entitled to elect a majority of the directors of such other corporation is held directly or indirectly by the Corporation, shall not be entitled to vote at any Annual Meeting or Special Meeting, but shares held in a fiduciary capacity may be voted.

12. Acceptance of Instruments Showing Shareholder Action

If the name signed on a vote, consent, waiver or proxy appointment corresponds to the name of a shareholder, the Corporation, if acting in good faith, may accept the vote, consent, waiver or proxy appointment and give it effect as the act of a shareholder. If the name signed on a vote, consent, waiver or proxy appointment does not correspond to the name of a shareholder, the Corporation, if acting in good faith, may accept the vote, consent, waiver or proxy appointment and give it effect as the act of the shareholder if any of the following apply:

10

Exhibit 3.2

a. The shareholder is an entity and the name signed purports to be that of an officer or agent of the entity.

b. The name purports to be that of a personal representative, administrator, executor, guardian or conservator representing the shareholder and, if the Corporation requests, evidence of fiduciary status acceptable to the Corporation is presented with respect to the vote, consent, waiver or proxy appointment.

c. The name signed purports to be that of a receiver or trustee in bankruptcy of the shareholder and, if the Corporation requests, evidence of this status acceptable to the Corporation is presented with respect to the vote, consent, waiver or proxy appointment.

d. The name signed purports to be that of a pledgee, beneficial owner, or attorney-in-fact of the shareholder and, if the Corporation requests, evidence acceptable to the Corporation of the signatory's authority to sign for the shareholder is presented with respect to the vote, consent, waiver or proxy appointment.

e. Two or more persons are the shareholder as co-tenants or fiduciaries and the name signed purports to be the name of at least one of the co-owners and the person signing appears to be acting on behalf of all co-owners.

The Corporation may reject a vote, consent, waiver or proxy appointment if the Secretary or other officer or agent of the Corporation who is authorized to tabulate votes, acting in good faith, has reasonable basis for doubt about the validity of the signature on it or about the signatory's authority to sign for the shareholder.

13. Waiver of Notice by Shareholders

A shareholder may waive any notice required by the Wisconsin Business Corporation Law, the Articles of Incorporation of the Corporation or these By‑laws before or after the date and time stated in the notice. The waiver shall be in writing and signed by the shareholder entitled to the notice, contain the same information that would have been required in the notice under applicable provisions of the Wisconsin Business Corporation Law (except that the time and place of meeting need not be stated) and be delivered to the Corporation for inclusion in the corporate records. A shareholder's attendance at any Annual Meeting or Special Meeting, in person or by proxy, waives objection to all of the following: (a) lack of notice or defective notice of the meeting, unless the shareholder at the beginning of the meeting or promptly upon arrival objects to holding the meeting or transacting business at the meeting; and (b) consideration of a particular matter at the meeting that is not within the purpose described in the meeting notice, unless the shareholder objects to considering the matter when it is presented.

11

Exhibit 3.2

14. Notice of Shareholder Business and Nomination of Directors

a. Annual Meetings.

(i) Nominations of persons for election to the Board of Directors of the Corporation and the proposal of business to be considered by the shareholders may be made at an Annual Meeting (A) pursuant to the Corporation's notice of meeting, (B) by or at the direction of the Board of Directors or (C) by any shareholder of the Corporation who is a shareholder of record at the time of giving of notice provided for in this Section 14 and who is entitled to vote at the meeting and complies with the notice procedures set forth in this Section 14.

(ii) For nominations or other business to be properly brought before an Annual Meeting by a shareholder pursuant to clause (C) of paragraph (a)(i) of this Section 14, the shareholder must have given timely notice thereof in writing to the Secretary of the Corporation. To be timely, a shareholder's notice shall be received by the Secretary of the Corporation at the principal offices of the Corporation not less than 45 days nor (except for shareholder proposals included in a proxy statement for such Annual Meeting in accordance with the requirements of Rule 14a‑8 under the Exchange Act) more than 70 days prior to the first annual anniversary of the date set forth in the Corporation's proxy statement for the immediately preceding Annual Meeting as the date on which the Corporation first mailed definitive proxy materials for the immediately preceding Annual Meeting (the "Anniversary Date"); provided, however, that in the event that the date for which the Annual Meeting is called is advanced by more than 30 days or delayed by more than 30 days from the first annual anniversary of the immediately preceding Annual Meeting, notice by the shareholder to be timely must be so delivered not earlier than the close of business on the 100^th day prior to the date of such Annual Meeting and not later than (A) the 75^th day prior to the date of such Annual Meeting or (B) the 10^th day following the day on which public announcement of the date of such Annual Meeting is first made. In no event shall the announcement of an adjournment of an Annual Meeting commence a new time period for the giving of a shareholder notice as described above. Such shareholder's notice shall be signed by the shareholder of record who intends to make the nomination or introduce the other business (or his duly authorized proxy or other representative), shall bear the date of signature of such shareholder (or proxy or other representative) and shall set forth: (A) the name and address, as they appear on this Corporation's books, of such shareholder and the beneficial owner or owners, if any, on whose behalf the nomination or

12

Exhibit 3.2

proposal is made; (B) the class and number of shares of the Corporation which are beneficially owned by such shareholder or beneficial owner or owners; (C) a representation that such shareholder is a holder of record of shares of the Corporation entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to make the nomination or introduce the other business specified in the notice; (D) in the case of any proposed nomination for election or re-election as a director, (I) the name and residence address of the person or persons to be nominated, (II) a description of all arrangements or understandings between such shareholder or beneficial owner or owners and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination is to be made by such shareholder, (III) such other information regarding each nominee proposed by such shareholder as would be required to be disclosed in solicitations of proxies for elections of directors, or would be otherwise required to be disclosed, in each case pursuant to Regulation 14A under the Exchange Act, including any information that would be required to be included in a proxy statement filed pursuant to Regulation 14A had the nominee been nominated by the Board of Directors and (IV) the written consent of each nominee to be named in a proxy statement and to serve as a director of the Corporation if so elected; and (E) in the case of any other business that such shareholder proposes to bring before the meeting, (I) a brief description of the business desired to be brought before the meeting and, if such business includes a proposal to amend these By‑laws, the language of the proposed amendment, (II) such shareholder's and beneficial owner's or owners' reasons for conducting such business at the meeting and (III) any material interest in such business of such shareholder and beneficial owner or owners.

(iii) Notwithstanding anything in the second sentence of paragraph (a)(ii) of this Section 14 to the contrary, in the event that the number of directors to be elected to the Board of Directors of the Corporation is increased and there is no public announcement naming all of the nominees for director or specifying the size of the increased Board of Directors made by the Corporation at least 45 days prior to the Anniversary Date, a shareholder's notice required by this Section 14 shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be received by the Secretary at the principal offices of the Corporation not later than the close of business on the 10^th day following the day on which such public announcement is first made by the Corporation.

13

Exhibit 3.2

b. Special Meetings. Only such business shall be conducted at a Special Meeting as shall have been described in the notice of meeting sent to shareholders pursuant to Section 5 of Article II of these By-laws. Nominations of persons for election to the Board of Directors may be made at a Special Meeting at which directors are to be elected pursuant to such notice of meeting (i) by or at the direction of the Board of Directors or (ii) by any shareholder of the Corporation who (A) is a shareholder of record at the time of giving of such notice of meeting, (B) is entitled to vote at the meeting and (C) complies with the notice procedures set forth in this Section 14. Any shareholder desiring to nominate persons for election to the Board of Directors at such a Special Meeting shall cause a written notice to be received by the Secretary of the Corporation at the principal offices of the Corporation not earlier than ninety days prior to such Special Meeting and not later than the close of business on the later of (x) the 60th day prior to such Special Meeting and (y) the 10th day following the day on which public announcement is first made of the date of such Special Meeting and of the nominees proposed by the Board of Directors to be elected at such meeting. Such written notice shall be signed by the shareholder of record who intends to make the nomination (or his duly authorized proxy or other representative), shall bear the date of signature of such shareholder (or proxy or other representative) and shall set forth: (A) the name and address, as they appear on the Corporation's books, of such shareholder and the beneficial owner or owners, if any, on whose behalf the nomination is made; (B) the class and number of shares of the Corporation which are beneficially owned by such shareholder or beneficial owner or owners; (C) a representation that such shareholder is a holder of record of shares of the Corporation entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to make the nomination specified in the notice; (D) the name and residence address of the person or persons to be nominated; (E) a description of all arrangements or understandings between such shareholder or beneficial owner or owners and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination is to be made by such shareholder; (F) such other information regarding each nominee proposed by such shareholder as would be required to be disclosed in solicitations of proxies for elections of directors, or would be otherwise required to be disclosed, in each case pursuant to Regulation 14A under the Exchange Act, including any information that would be required to be included in a proxy statement filed pursuant to Regulation 14A had the nominee been nominated by the Board of Directors; and (G) the written consent of each nominee to be named in a proxy statement and to serve as a director of the Corporation if so elected.

c. General.

(i) Only persons who are nominated in accordance with the procedures set forth in this Section 14 shall be eligible to serve as

14

Exhibit 3.2

directors. Only such business shall be conducted at an Annual Meeting or Special Meeting as shall have been brought before such meeting in accordance with the procedures set forth in this Section 14. The chairman of the meeting shall have the power and duty to determine whether a nomination or any business proposed to be brought before the meeting was made in accordance with the procedures set forth in this Section 14 and, if any proposed nomination or business is not in compliance with this Section 14, to declare that such defective proposal shall be disregarded.

(ii) For purposes of this Section 14, "public announcement" shall mean disclosure in a press release reported by the Dow Jones News Service, Associated Press or comparable national news service or in a document publicly filed by the Corporation with the Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act.

(iii) Notwithstanding the foregoing provisions of this Section 14, a shareholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 14. Nothing in this Section 14 shall be deemed to limit the Corporation's obligation to include shareholder proposals in its proxy statement if such inclusion is required by Rule 14a-8 under the Exchange Act.

ARTICLE III. BOARD OF DIRECTORS

1.    General Powers

The business and affairs of the Corporation shall be managed by its Board of Directors. The Board shall determine the nature and character of the business to be conducted by the Corporation and the method of doing so; what employees, agents, and officers shall be employed and their compensation; and what purchases or contracts for purchase shall be made. The Board may delegate any of its aforesaid powers to committees or to officers, agents, or employees as it may from time to time determine.

2.    Number of Directors

The number of directors of the Corporation shall be fixed from time to time by the directors or the shareholders and shall be a minimum of three (3).

15

Exhibit 3.2

3.    Term

At each annual meeting of shareholders, the directors shall be elected to hold office until the next annual meeting of shareholders, and until their successors are elected and qualify.

4.    Qualifications

No director elected to such office for the first time after January 1, 1972 shall be eligible for re-election after attaining the age of 70 years. Directors need not be shareholders of the Corporation or residents of the State of Wisconsin.

5.    Meetings

The Board of Directors shall hold its meetings at such place or places, within or without the State of Wisconsin, as the Board may from time to time determine.

a. A meeting of the Board of Directors, to be known as the annual meeting, may be held, without notice, immediately after and at the same place as the annual meeting of the shareholders at which such Board is elected, for the purpose of electing the officers of the Corporation and to transact such other business as may come before the Board. Such annual meeting may be held at a different place than the annual meeting of shareholders and/or on a date subsequent to the annual meeting of shareholders, if notice of such different place and/or date has been given to or waived by all the directors.

b. Regular meetings of the Board of Directors may be held without call and without notice, at such times and in such places as the Board may by resolution from time to time determine.

c. Special meetings of the Board of Directors may be called at any time by the Chairman of the Board or the Chief Executive Officer and shall be called by the Secretary of the Corporation upon the written request of three or more directors.

16

Exhibit 3.2

6.    Notice; Waiver

Notice of each special meeting of the Board of Directors shall be given by written notice delivered or communicated in person, by telegraph, teletype, facsimile, or other form of wire or wireless communication, or by mail or private carrier, to each director at his business address or at such other address as such director shall have designated in writing filed with the Secretary, in each case not less than 48 hours prior to the meeting. The notice need not prescribe the purpose of the special meeting of the Board of Directors or the business to be transacted at such meeting. If mailed, such notice shall be deemed to be effective when deposited in the United States mail so addressed, with postage thereon prepaid. If notice is given by telegram, such notice shall be deemed to be effective when the telegram is delivered to the telegraph company. If notice is given by private carrier, such notice shall be deemed to be effective when delivered to the private carrier. Whenever any notice whatever is required to be given to any director of the Corporation under the Articles of Incorporation, these By-laws, or any provision of the Wisconsin Business Corporation Law, a waiver thereof in writing, signed at any time, whether before or after the date and time of meeting, by the director entitled to such notice shall be deemed equivalent to the giving of such notice. The Corporation shall retain any such waiver as part of the permanent corporate records. A director's attendance at or participation in a meeting waives any required notice to him or her of the meeting unless the director at the beginning of the meeting or promptly upon his or her arrival objects to holding the meeting or transacting business at the meeting and does not thereafter vote for or assent to action taken at the meeting.

7.    Quorum

Except as otherwise provided by the Wisconsin Business Corporation Law, by the Articles of Incorporation, or these By-laws, a majority of the number of directors specified in Section 2 of Article III of these By-laws shall constitute a quorum for the transaction of business at any meeting of the Board of Directors. Except as otherwise provided by the Wisconsin Business Corporation Law, by the Articles of Incorporation, or by these By-laws, a quorum of any committee of the Board of Directors created pursuant to Section 13 hereof shall consist of a majority of the number of directors appointed to serve on the committee. A majority of the directors present (though less than such quorum) may adjourn any meeting of the Board of Directors or any committee thereof, as the case may be, from time to time without further notice.

8.    Manner of Acting

The affirmative vote of a majority of the directors present at a meeting of the Board of Directors or a committee thereof at which a quorum is present shall be the act of the Board of Directors or such committee, as the case may be, unless the Wisconsin Business Corporation Law, the Articles of Incorporation, or these By-laws require the vote of a greater number of directors.

17

Exhibit 3.2

9.    Minutes of Meetings

Minutes of any regular or special meeting of the Board of Directors shall be prepared and distributed to each director.

10.    Vacancies

Vacancies occurring in the Board of Directors shall be filled in the manner provided in Article V of the Articles of Incorporation.

11.    Compensation

The Board of Directors, irrespective of any personal interest of any of its members, may establish reasonable compensation of all directors for services to the Corporation as directors, officers, or otherwise, or may delegate such authority to an appropriate committee. The Board of Directors also shall have authority to provide for or delegate authority to an appropriate committee to provide for reasonable pensions, disability, or death benefits, and other benefits or payments, to directors, officers, and employees, and to their estates, families, dependents, or beneficiaries on account of prior services rendered by such directors, officers, and employees to the Corporation.

12.    Presumption of Assent

A director who is present and is announced as present at a meeting of the Board of Directors or any committee thereof created in accordance with Section 13 of this Article III, when corporate action is taken, assents to the action taken unless any of the following occurs:

a. The director objects at the beginning of the meeting or promptly upon his or her arrival to holding the meeting or transacting business at the meeting.

b. The director's dissent or abstention from the action taken is entered in the minutes of the meeting.

c. The director delivers written notice that complies with the Wisconsin Business Corporation Law of his or her dissent or abstention to the presiding officer of the meeting before its adjournment or to the Corporation immediately after adjournment of the meeting.

Such right of dissent or abstention shall not apply to a director who votes in favor of the action taken.

18

Exhibit 3.2

13.    Committees

The Board of Directors by resolution adopted by the affirmative vote of a majority of all of the directors then in office may create one or more committees, appoint members of the Board of Directors to serve on the committees, and designate other members of the Board of Directors to serve as alternates. Each committee shall have two or more members who shall, unless otherwise provided by the Board of Directors, serve at the pleasure of the Board of Directors. A committee may be authorized to exercise the authority of the Board of Directors, except that a committee may not do any of the following:

a. Authorize distributions.

b. Approve or propose to shareholders action that the Wisconsin Business Corporation Law requires to be approved by shareholders.

c. Fill vacancies on the Board of Directors or, unless the Board of Directors provides by resolution that vacancies on a committee shall be filled by the affirmative vote of the remaining committee members, on any Board committee.

d. Amend the Corporation's Articles of Incorporation.

e. Adopt, amend, or repeal By-laws.

f. Approve a plan of merger not requiring shareholder approval.

g. Authorize or approve reacquisition of shares, except according to a formula or method prescribed by the Board of Directors.

h. Authorize or approve the issuance or sale or contract for sale of shares, or determine the designation and relative rights, preferences and limitations of a class or series of shares, except that the Board of Directors may authorize a committee to do so within limits prescribed by the Board of Directors. Unless otherwise provided by the Board of Directors in creating the committee, a committee may employ counsel, accountants, and other consultants to assist it in the exercise of its authority.

14. Telephonic Meetings

Except as herein provided and notwithstanding any place set forth in the notice of the meeting or these By-laws, members of the Board of Directors (and any committees thereof created pursuant to Section 13 of this Article III) may participate in regular or special meetings by, or through the use of, any means of communication by which all participants may simultaneously hear each other, such as by conference telephone. If a meeting is conducted by such means, then at the commencement of such meeting the presiding officer shall inform the

19

Exhibit 3.2

participating directors that a meeting is taking place at which official business may be transacted. Any participant in a meeting by such means shall be deemed present in person at such meeting. Notwithstanding the foregoing, no action may be taken at any meeting held by such means on any particular matter which the presiding officer determines, in his or her sole discretion, to be inappropriate under the circumstances for action at a meeting held by such means. Such determination shall be made and announced in advance of such meeting.

15.    Action without Meeting

Any action required or permitted by the Wisconsin Business Corporation Law to be taken at a meeting of the Board of Directors or a committee thereof created pursuant to Section 13 of this Article III may be taken without a meeting if the action is taken by all members of the Board or of the committee. The action shall be evidenced by one or more written consents describing the action taken, signed by each director or committee member and retained by the Corporation. Such action shall be effective when the last director or committee member signs the consent, unless the consent specifies a different effective date.

ARTICLE IV. OFFICERS

1. Principal Officers

The principal officers of the Corporation required by statute shall be one or more Presidents (as may be elected by the Board of Directors), such number of Vice Presidents as may be elected by the Board of Directors, a Secretary, and a Treasurer. The Board of Directors may elect from among the directors a Chairman of the Board of Directors and a Vice Chairman of the Board of Directors; may designate such Chairman, Vice Chairman, or any principal officer as the Chief Executive Officer; may designate the President or Presidents as a Chief Operating Officer; may elect such Assistant Secretaries and Assistant Treasurers and other officers as it shall deem necessary; and may prescribe by resolution their respective powers and duties.

2.    Chairman of the Board of Directors

If a Chairman of the Board of Directors shall be elected, he or she shall preside as Chairman of all meetings of the shareholders and of the Board of Directors. He or she shall have such other authority as the Board may from time to time prescribe. If there is no Chairman of the Board, or in the absence of the Chairman, the presiding officer at meetings of the shareholders, and of the Board of Directors shall be another officer in the following order of priority: Vice Chairman of the Board of Directors, Chief Executive Officer, Presidents, and Vice Presidents (subject, however, to Section 5 of this Article).

20

Exhibit 3.2

3.    Chief Executive Officer

The Chief Executive Officer shall be the principal executive officer of the Corporation and, subject to the control of the Board of Directors, shall in general exercise active supervision over the business, property, and affairs of the Corporation.

a. The Chief Executive Officer shall have authority, subject to such rules as may be prescribed from time to time by the Board or its committees, to appoint agents or employees other than those elected by the Board, to prescribe their powers and duties, and to delegate such authority as he or she may see fit. Any agent or employee not elected by the Board shall hold office at the discretion of the Chief Executive Officer or other officer employing him.

b. The Chief Executive Officer is authorized to sign, execute, and acknowledge, on behalf of the Corporation, all deeds, mortgages, bonds, notes, debentures, contracts, leases, reports, and other documents and instruments, except where the signing and execution thereof by some other officer or agent shall be expressly authorized and directed by law or by the Board or by these By-laws. Unless otherwise provided by law or by the Board, the Chief Executive Officer may authorize any officer, employee, or agent to sign, execute, and acknowledge, on behalf of the Corporation, and in his place and stead, all such documents and instruments.

c. Unless otherwise ordered by the Board of Directors, the Chief Executive Officer, or a proxy appointed by him, shall have full power and authority, in the name of and on behalf of the Corporation, to attend, act, and vote at any meeting of the shareholders of any other corporation in which the Corporation may hold shares of stock. At any such meeting, he or she shall possess and may exercise any and all rights and powers incident to the ownership of shares of stock.

d. The Chief Executive Officer shall have such other powers and perform such other duties as are incident to the office of Chief Executive Officer and as may be prescribed by the Board.

4.    Presidents

The President or Presidents shall be the principal operating officer(s) of the Corporation, shall assist the Chief Executive Officer in exercising general supervision over the business and affairs of the Corporation, and shall perform such other duties and have such authority as from time to time may be delegated or assigned to him or her by the Chief Executive Officer or by the Board of Directors (including the power to sign, execute and acknowledge all documents and instruments referred to in Section 3 of this Article). In the event there be more than one President, each such President shall be assigned responsibility for a designated group, division or function of the Corporation’s business, an

21

Exhibit 3.2

appropriate descriptive designation shall be added to his or her title and he or she shall have authority over that group, division or function. During the absence or disability of the Chief Executive Officer, or while that office is vacant, the President or Presidents shall exercise all the powers and discharge all of the duties of the Chief Executive Officer.

5.    Vice Presidents

In the absence of any President or during his or her inability or refusal to act, his or her powers and duties shall temporarily devolve upon such Vice Presidents or other officers as shall be designated by the Board of Directors or, if not designated by the Board, by the Chief Executive Officer or other officer to whom such power may be delegated by the Board; provided, that no Vice President or other officer shall act as a member or chairman of any committee of the Board of Directors of which a President is a member or chairman, except at the direction of the Board.

a. Each Vice President shall have such powers and perform such other duties as may be assigned to him or her by the Board or the Chief Executive Officer, including the power to sign, execute, and acknowledge all documents and instruments referred to in Section 3 of this Article.

b. The Board may assign to any Vice President, general supervision and charge over any branch of the business and affairs of the Corporation, subject to such limitations as it may elect to impose.

c. The Board of Directors may, if it chooses, designate one or more of the Vice Presidents "Executive Vice President" with such powers and duties as the Board shall prescribe.

6.    Secretary

The Secretary shall attend, and keep the minutes of, meetings of the shareholders, the Board of Directors and, unless otherwise directed by any such committee, all committees, in books provided for that purpose; shall have custody of the corporate records and seal; shall see that notices are given and records and reports properly kept and filed as required by law or by these By-laws; and, in general, shall have such other powers and perform such other duties as are incident to the office of Secretary and as may be assigned to him or her by the Board of Directors or the Chief Executive Officer.

7.    Assistant Secretaries

In the absence of the Secretary, or during his or her inability or refusal to act, his or her powers and duties shall temporarily devolve upon such one of the Assistant Secretaries as the Chief Executive Officer or the Board of Directors may direct. The Assistant Secretaries shall have such other powers and perform such other duties as may be assigned to them by the Board, the Chief Executive Officer, or the Secretary.

22

Exhibit 3.2

8.    Treasurer

The Treasurer shall have charge and custody of the funds, securities, and other evidences of value of the Corporation, and shall keep and deposit them as required by the Board of Directors. He or she shall keep proper accounts of all receipts and disbursements and of the financial transactions of the Corporation. He or she shall render statements of such accounts and of money received and disbursed by him or her and of property and money belonging to the Corporation as required by the Board. The Treasurer shall have such other powers and perform such other duties as are incident to the office of Treasurer and as from time to time may be prescribed by the Board or the Chief Executive Officer.

9.    Assistant Treasurers

In the absence of the Treasurer, or during his or her inability or refusal to act, his or her powers and duties shall temporarily devolve upon such one of the Assistant Treasurers as the Chief Executive Officer or the Board of Directors may direct. The Assistant Treasurers shall have such other powers and perform such other duties as from time to time may be assigned to them, respectively, by the Board, the Chief Executive Officer, or the Treasurer.

10.    Other Assistants and Acting Officers

The Board of Directors shall have the power to appoint any person to act as assistant to any officer, or as agent for the Corporation in his or her stead, or to perform the duties of such officer whenever for any reason it is impracticable for such officer to act personally, and such assistant or acting officer or other agent so appointed by the Board of Directors or an authorized officer shall have the power to perform all the duties of the office to which he or she is so appointed to be an assistant, or as to which he or she is so appointed to act, except as such power may be otherwise defined or restricted by the Board of Directors.

11.    Compensation

The salaries or other compensation of all officers elected as provided under Section 1 of this Article (other than assistant officers) shall be fixed from time to time by the Board of Directors. The salaries or other compensation of all other agents and employees of the Corporation shall be fixed from time to time by the Chief Executive Officer, but only within such limits as to amount, and in accordance with such other conditions as may be prescribed by or under the authority of the Board of Directors.

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Exhibit 3.2

12.    Tenure

Each officer shall hold office until his or her successor shall have been duly elected and qualified, or until his or her death, resignation, disqualification, or removal. Any officer, agent, or employee may be removed, with or without cause, at any time by the Board of Directors notwithstanding the contract rights, if any, of the officer removed. The appointment of an officer does not of itself create contract rights.

13.    Resignation

An officer may resign at any time by delivering notice to the Corporation that complies with the Wisconsin Business Corporation Law. The resignation shall be effective when the notice is delivered, unless the notice specifies a later effective date, and the Corporation accepts the later effective date.

14.    Vacancies

Any vacancy in any office may be filled by the Board of Directors for the unexpired portion of the term. If a resignation of an officer is effective at a later date as contemplated by Section 13 of this Article IV, the Board of Directors may fill the pending vacancy before the effective date if the Board provides that the successor may not take office until the effective date.

15.    Reassignment of Duties

In case of the absence or disability of any officer of the Corporation, or for any other reason deemed sufficient by the Board of Directors, the Board may reassign or delegate the powers and duties, or any of them, to any other officer, director, or person it may select.

ARTICLE V. CERTIFICATES FOR AND TRANSFER OF SHARES

1.    Form

Certificates representing shares of the Corporation shall be in such form as shall be determined by the Board of Directors. All certificates for shares shall be consecutively numbered or otherwise identified. The name and address of the person to whom the shares represented thereby are issued, with the number of shares and date of issue, shall be entered on the stock transfer books of the Corporation. All certificates surrendered for the transfer shall be cancelled, and no new certificate shall be issued until the former certificate for a like number of shares shall have been surrendered and cancelled, except in case of a lost or destroyed certificate provided for in Section 4 of this Article V or a certificate for shares transferred in compliance with the escheat laws of any state.

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Exhibit 3.2

2.    Signatures

Certificates representing shares of the Corporation shall be signed by the Chief Executive Officer, a President or a Vice President and by the Secretary or an Assistant Secretary; and may be sealed with the seal of the Corporation (which may be a facsimile) and countersigned and registered in such manner, if any, as the Board of Directors may prescribe. Whenever any certificate is manually signed on behalf of a transfer agent or a registrar, other than the Corporation itself or an employee of the Corporation, the signatures of the Chief Executive Officer, President, Vice President, Secretary, or Assistant Secretary, upon such certificate may be facsimiles. In case any officer who has signed, or whose facsimile signature has been placed upon such certificate, ceases to be such officer before such certificate is issued, it may be issued with the same effect as if he or she were such officer at the date of its issue.

3.    Restrictions on Transfer

The face or reverse side of each certificate representing shares shall bear a conspicuous notation of any restriction imposed by the Corporation upon the transfer of such shares.

4.    Lost, Destroyed, or Stolen Certificates

Where the owner claims that his certificate for shares has been lost, destroyed, or wrongfully taken, a new certificate shall be issued in place thereof if the owner:

a. So requests before the Corporation has notice that such shares have been acquired by a bona fide purchaser.

b. Files with the Corporation a sufficient indemnity bond.

c. Satisfies such other reasonable requirements as may be prescribed by or under the authority of the Board of Directors.

5.    Transfer of Shares

Prior to due presentment of a certificate for shares for registration of transfer, the Corporation may treat the registered owner of such shares as the person exclusively entitled to vote, to receive notifications, and otherwise to have and exercise all the rights and powers of an owner. Where a certificate for shares is presented to the Corporation with a request to register for transfer, the Corporation shall not be liable to the owner or any other person suffering loss as a result of such registration of transfer if:

a. There were on or with the certificate the necessary endorsements.

25

Exhibit 3.2

b. The Corporation had no duty to inquire into adverse claims or has discharged any such duty.

The Corporation may require reasonable assurance that said endorsements are genuine and effective and compliance with such other regulations as may be prescribed by or under the authority of the Board of Directors.

6.    Consideration for Shares

The Board of Directors may authorize shares to be issued for consideration consisting of any tangible or intangible property or benefit to the Corporation, including cash, promissory notes, services performed, contracts for services to be performed, or other securities of the Corporation. Before the Corporation issues shares, the Board of Directors shall determine that the consideration received or to be received for the shares to be issued is adequate. The determination of the Board of Directors is conclusive insofar as the adequacy of consideration for the issuance of shares relates to whether the shares are validly issued, fully paid, and nonassessable. The Corporation may place in escrow shares issued in whole or in part for a contract for future services or benefits, a promissory note, or otherwise for property to be issued in the future, or make other arrangements to restrict the transfer of the shares, and may credit distributions in respect of the shares against their purchase price, until the services are performed, the benefits or property are received, or the promissory note is paid. If the services are not performed, the benefits or property are not received or the promissory note is not paid, the Corporation may cancel, in whole or in part, the shares escrowed or restricted and the distributions credited.

7.    Other Rules

The Board of Directors shall have the power and authority to make all such further rules and regulations not inconsistent with the statutes of the State of Wisconsin as it may deem expedient concerning the issue, transfer, and registration of certificates representing shares of the Corporation, including the appointment and designation of Transfer Agents and Registrars.

ARTICLE VI. INDEMNIFICATION OF OFFICERS AND DIRECTORS

1.    Mandatory Indemnification

a. In all cases other than those set forth in Section 1b hereof, subject to the conditions and limitations set forth hereinafter in this Article VI, the Corporation shall indemnify and hold harmless any person who is or was a party, or is threatened to be made a party, to any Action (see Section 16 of this Article VI for definitions of capitalized terms used herein) by reason of his or her status as an Executive, and/or as to acts performed in the course

26

Exhibit 3.2

of such Executive's duties to the Corporation and/or an Affiliate, against Liabilities and reasonable Expenses incurred by or on behalf of an Executive in connection with any Action, including, without limitation, in connection with the investigation, defense, settlement, or appeal of any Action; provided, pursuant to Section 3 of this Article VI, that it is not determined by the Authority or by a court, that the Executive engaged in misconduct which constitutes a Breach of Duty.

b. To the extent an Executive has been successful on the merits or otherwise in connection with any Action, including, without limitation, the settlement, dismissal, abandonment, or withdrawal of any such Action where the Executive does not pay, incur, or assume any material Liabilities, or in connection with any claim, issue or matter therein, he or she shall be indemnified by the Corporation against reasonable Expenses incurred by or on behalf of him or her in connection therewith. The Corporation shall pay such Expenses to the Executive (net of all Expenses, if any, previously advanced to the Executive pursuant to Section 2 of this Article VI), or to such other person or entity as the Executive may designate in writing to the Corporation, within ten days after the receipt of the Executive's written request therefor, without regard to the provisions of Section 3 of this Article VI. In the event the Corporation refuses to pay such requested Expenses, the Executive may petition a court to order the Corporation to make such payment pursuant to Section 4 of this Article VI.

c. Notwithstanding any other provision contained in this Article VI to the contrary, the Corporation shall not:

(1) Indemnify, contribute or advance Expenses to an Executive with respect to any Action initiated or brought voluntarily by the Executive and not by way of defense, except with respect to Actions:

(a) Brought to establish or enforce a right to indemnification, contribution and/or an advance of Expenses under Section 4 of this Article VI, under the Statute as it may then be in effect or under any other statute or law or otherwise as required;

(b) Initiated or brought voluntarily by an Executive to the extent such Executive is successful on the merits or otherwise in connection with such an Action in accordance with and pursuant to Section 1b of this Article VI; or

(c) As to which the Board determines it to be appropriate.

(2) Indemnify the Executive under this Article VI for any amounts paid in settlement of any Action effected without the Corporation's written consent.

27

Exhibit 3.2

The Corporation shall not settle in any manner which would impose any Liabilities or other type of limitation on the Executive without the Executive's written consent. Neither the Corporation nor the Executive shall unreasonably withhold their consent to any proposed settlement.

d. An Executive's conduct with respect to an employee benefit plan sponsored by or otherwise associated with the Corporation and/or an Affiliate for a purpose he or she reasonably believes to be in the interests of the participants in and beneficiaries of such plan is conduct that does not constitute a breach or failure to perform his or her duties to the Corporation or an Affiliate, as the case may be.

2.    Advance for Expenses

a. The Corporation shall pay to an Executive, or to such other person or entity as the Executive may designate in writing to the Corporation, his or her reasonable Expenses incurred by or on behalf of such Executive in connection with any Action, claim, issue, or matter associated with any such Action, in advance of the final disposition or conclusion of any such Action (or claim, issue, or matter associated with any such Action), within ten days after the receipt of the Executive's written request therefor; provided, the following conditions are satisfied:

(1) The Executive has first requested an advance of such Expenses in writing (and delivered a copy of such request to the Corporation) from the insurance carrier(s), if any, to whom a claim has been reported under an applicable insurance policy purchased by the Corporation and each such insurance carrier, if any, has declined to make such an advance;

(2) The Executive furnishes to the Corporation an executed written certificate affirming his or her good faith belief that he or she has not engaged in misconduct which constitutes a Breach of Duty; and

(3) The Executive furnishes to the Corporation an executed written agreement to repay any advances made under this Section 2 if it is ultimately determined that he or she is not entitled to be indemnified by the Corporation for such Expenses pursuant to this Article VI.

b. If the Corporation makes an advance of Expenses to an Executive pursuant to this Section 2, the Corporation shall be subrogated to every right of recovery the Executive may have against any insurance carrier from whom the Corporation has purchased insurance for such purpose.

3.    Determination of Right to Indemnification

28

Exhibit 3.2

a. Except as otherwise set forth in this Section 3 or in Section 1c of this Article VI, any indemnification to be provided to an Executive by the Corporation under Section 1a of this Article VI upon the final disposition or conclusion of any Action, claim, issue, or matter associated with any such Action, unless otherwise ordered by a court, shall be paid by the Corporation to the Executive (net of all Expenses, if any, previously advanced to the Executive pursuant to Section 2 of this Article VI), or to such other person or entity as the Executive may designate in writing to the Corporation, within 60 days after the receipt of the Executive's written request therefor. Such request shall include an accounting of all amounts for which indemnification is being sought. No further corporate authorization for such payment shall be required other than this Section 3.

b. Notwithstanding the foregoing, the payment of such requested indemnifiable amounts pursuant to Section 1a of this Article VI may be denied by the Corporation if:

(1) The Board by a majority vote thereof determines that the Executive has engaged in misconduct which constitutes a Breach of Duty; or

(2) A majority of the directors of the Corporation are a party in interest to such Action.

c. In either event of nonpayment pursuant to Section 3b of this Article VI, the Board shall immediately authorize and direct, by resolution, that an independent determination be made as to whether the Executive has engaged in misconduct which constitutes a Breach of Duty and, therefore, whether indemnification of the Executive is proper pursuant to this Article VI.

d. Such independent determination shall be made, at the option of the Executive(s) seeking indemnification, by:

(1) A panel of three arbitrators (selected as set forth below in Section 3f of this Article VI from the panels of arbitrators of the American Arbitration Association) in Milwaukee, Wisconsin, in accordance with the Commercial Arbitration Rules then prevailing of the American Arbitration Association;

(2) An independent legal counsel mutually selected by the Executive(s) seeking indemnification and the Board by a majority vote of a quorum thereof consisting of directors who were not parties in interest to such Action (or, if such quorum is not obtainable, by the majority vote of the entire Board); or

(3) A court in accordance with Section 4 of this Article VI.

e. In any such determination there shall exist a rebuttable presumption that the Executive has not engaged in misconduct which constitutes a Breach of Duty and is, therefore, entitled to indemnification hereunder. The burden of

29

Exhibit 3.2

rebutting such presumption by clear and convincing evidence shall be on the Corporation.

f. If a panel of arbitrators is to be employed hereunder, one of such arbitrators shall be selected by the Board by a majority vote of a quorum thereof consisting of directors who were not parties in interest to such Action or, if such quorum is not obtainable, by an independent legal counsel chosen by the majority vote of the entire Board, the second by the Executive(s) seeking indemnification, and the third by the previous two arbitrators.

g. The Authority shall make its independent determination hereunder within 60 days of being selected and shall simultaneously submit a written opinion of its conclusions to both the Corporation and the Executive.

h. If the Authority determines that an Executive is entitled to be indemnified for any amounts pursuant to this Article VI, the Corporation shall pay such amounts to the Executive (net of all Expenses, if any, previously advanced to the Executive pursuant to Section 2 of this Article VI), including interest thereon as provided in Section 6c of this Article VI, or such other person or entity as the Executive may designate in writing to the Corporation, within ten days of receipt of such opinion.

i. Except with respect to any judicial determination pursuant to Section 4 of this Article VI, the Expenses associated with the indemnification process set forth in this Section 3 of this Article VI, including, without limitation, the Expenses of the Authority selected hereunder, shall be paid by the Corporation.

4.    Court-Ordered Indemnification and Advance for Expenses

a. An Executive may, either before or within two years after a determination, if any, has been made by the Authority, petition the court before which such Action was brought or any other court of competent jurisdiction to independently determine whether or not he or she has engaged in misconduct which constitutes a Breach of Duty and is, therefore, entitled to indemnification under the provisions of this Article VI. Such court shall thereupon have the exclusive authority to make such determination unless and until such court dismisses or otherwise terminates such proceeding without having made such determination. An Executive may petition a court under this Section 4 either to seek an initial determination by the court as authorized by Section 3d of this Article VI or to seek review by the court of a previous adverse determination by the Authority.

b. The court shall make its independent determination irrespective of any prior determination made by the Authority; provided, however, that there shall exist a rebuttable presumption that the Executive has not engaged in misconduct which constitutes a Breach of Duty and is, therefore, entitled to indemnification hereunder. The burden of rebutting such presumption by clear and convincing evidence shall be on the Corporation.

30

Exhibit 3.2

c. In the event the court determines that an Executive has engaged in misconduct which constitutes a Breach of Duty, it may nonetheless order indemnification to be paid by the Corporation if it determines that the Executive is fairly and reasonably entitled to indemnification in view of all of the circumstances of such Action.

d. In the event the Corporation does not:

(1) Advance Expenses to the Executive within ten days of such Executive's compliance with Section 2 of this Article VI; or

(2) Indemnify an Executive with respect to requested Expenses under Section 1b of this Article VI within ten days of such Executive's written request therefore, the Executive may petition the court before which such Action was brought, if any, or any other court of competent jurisdiction to order the Corporation to pay such reasonable Expenses immediately.

Such court, after giving any notice it considers necessary, shall order the Corporation to pay such Expenses if it determines that the Executive has complied with the applicable provisions of Section 2 of this Article VI or Section 1b of this Article VI, as the case may be.

e. If the court determines pursuant to this Section 4 of this Article VI that the Executive is entitled to be indemnified for any Liabilities and/or Expenses, or to the advance of Expenses, unless otherwise ordered by such court, the Corporation shall pay such Liabilities and/or Expenses to the Executive (net of all Expenses, if any, previously advanced to the Executive pursuant to Section 2 of this Article VI), including interest thereon as provided in Section 6c of this Article VI, or to such other person or entity as the Executive may designate in writing to the Corporation, within ten days of the rendering of such determination.

f. An Executive shall pay all Expenses incurred by such Executive in connection with the judicial determination provided in this Section 4 of this Article VI, unless it shall ultimately be determined by the court that he or she is entitled, in whole or in part, to be indemnified by, or to receive an advance from, the Corporation as authorized by this Article VI. All Expenses incurred by an Executive in connection with any subsequent appeal of the judicial determination provided for in this Section 4 of this Article VI shall be paid by the Executive regardless of the disposition of such appeal.

5.    Termination of an Action is Nonconclusive

The adverse termination of any Action against an Executive by judgment, order settlement, conviction, or upon a plea of no contest or its equivalent, shall not, of itself, create a presumption that the Executive has engaged in misconduct which constitutes a Breach of Duty.

31

Exhibit 3.2

6.    Partial Indemnification; Reasonableness; Interest

a. If it is determined by the Authority, or by a court, that an Executive is entitled to indemnification as to some claims, issues, or matters, but not as to other claims, issues, or matters, involved in any Action, the Authority, or the court, shall authorize the proration and payment by the Corporation of such Liabilities and/or reasonable Expenses with respect to which indemnification is sought by the Executive, among such claims, issues, or matters as the Authority, or the court, shall deem appropriate in light of all of the circumstances of such Action.

b. If it is determined by the Authority, or by a court, that certain Expenses incurred by or on behalf of an Executive are for whatever reason unreasonable in amount, the Authority, or the court, shall nonetheless authorize indemnification to be paid by the Corporation to the Executive for such Expenses as the Authority, or the court, shall deem reasonable in light of all of the circumstances of such Action.

c. Interest shall be paid by the Corporation to an Executive, to the extent deemed appropriate by the Authority, or by a court, at a reasonable interest rate, for amounts for which the Corporation indemnifies or advances to the Executive.

7.    Insurance; Subrogation

a. The Corporation may purchase and maintain insurance on behalf of any person who is or was an Executive of the Corporation, and/or is or was serving as an Executive of an Affiliate, against Liabilities and/or Expenses asserted against him or her and/or incurred by or on behalf of him or her in any such capacity, or arising out of his or her status as such an Executive, whether or not the Corporation would have the power to indemnify him or her against such Liabilities and/or Expenses under this Article VI or under the Statute as it may then be in effect. Except as expressly provided herein, the purchase and maintenance of such insurance shall not in any way limit or affect the rights and obligations of the Corporation and/or any Executive under this Article VI. Such insurance may, but need not, be for the benefit of all Executives of the Corporation and those serving as an Executive of an Affiliate.

b. If an Executive shall receive payment from any insurance carrier or from the plaintiff in any Action against such Executive in respect of indemnified amounts after payments on account of all or part of such indemnified amounts have been made by the Corporation pursuant to this Article VI, such Executive shall promptly reimburse the Corporation for the amount, if any, by which the sum of such payment by such insurance carrier or such plaintiff and payments by the Corporation to such Executive exceeds such indemnified amounts; provided, however, that such portions, if any, of such

32

Exhibit 3.2

insurance proceeds that are required to be reimbursed to the insurance carrier under the terms of its insurance policy, such as deductible, retention, or co-insurance amounts, shall not be deemed to be payments to such Executive hereunder.

c. Upon payment of indemnified amounts under this Article VI, the Corporation shall be subrogated to such Executive's rights against any insurance carrier in respect of such indemnified amounts; and the Executive shall execute and deliver any and all instruments and/or documents and perform any and all other acts or deeds which the Corporation shall deem necessary or advisable to secure such rights. The Executive shall do nothing to prejudice such rights of recovery or subrogation.

8.    Witness Expenses

The Corporation shall advance or reimburse any and all reasonable Expenses incurred by or on behalf of an Executive in connection with his or her appearance as a witness in any Action at a time when he or she has not been formally named a defendant or respondent to such an Action, within ten days after the receipt of an Executive's written request therefore.

9.    Contribution

a. Subject to the limitations of this Section 9, if the indemnity provided for in Section 1 of this Article VI is unavailable to an Executive for any reason whatsoever, the Corporation, in lieu of indemnifying the Executive, shall contribute to the amount incurred by or on behalf of the Executive, whether for Liabilities and/or for reasonable Expenses in connection with any Action in such proportion as deemed fair and reasonable by the Authority, or by a court, in light of all of the circumstances of any such Action, in order to reflect:

(1) The relative benefits received by the Corporation and the Executive as a result of the event(s) and/or transaction(s) giving cause to such Action; and/or

(2) The relative fault of the Corporation (and its other Executives, employees, and/or agents) and the Executive in connection with such event(s) and/or transaction(s).

b. The relative fault of the Corporation (and its other Executives, employees, and/or agents), on the one hand, and of the Executive, on the other hand, shall be determined by reference to, among other things, the parties' relative intent, knowledge, access to information, and opportunity to correct or prevent the circumstances resulting in such Liabilities and/or Expenses. The Corporation agrees that it would not be just and equitable if contribution pursuant to this Section 9 were determined by pro rata allocation or any

33

Exhibit 3.2

other method of allocation which does not take account of the foregoing equitable considerations.

c. An Executive shall not be entitled to contribution from the Corporation under this Section 9 in the event it is determined by the Authority, or by a court, that the Executive has engaged in misconduct which constitutes a Breach of Duty.

d. The Corporation's payment of, and an Executive's right to, contribution under this Section 9 shall be made and determined in accordance with and pursuant to the provisions in Sections 3 and/or 4 of this Article VI relating to the Corporation's payment of, and the Executive's right to, indemnification under this Article VI.

10.    Indemnification of Employees

Unless otherwise specifically set forth in this Article VI, the Corporation shall indemnify and hold harmless any person who is or was a party, or is threatened to be made a party to any Action by reason of his or her status as, or the fact that he or she is or was an employee or authorized agent or representative of the Corporation and/or an Affiliate as to acts performed in the course and within the scope of such employee's, agent's, or representative's duties to the Corporation and/or an Affiliate, in accordance with and to the fullest extent permitted by the Statute as it may then be in effect.

11.    Severability

If any provision of this Article VI shall be deemed invalid or inoperative, or if a court of competent jurisdiction determines that any of the provisions of this Article VI contravene public policy, this Article VI shall be construed so that the remaining provisions shall not be affected, but shall remain in full force and effect, and any such provisions which are invalid or inoperative or which contravene public policy shall be deemed, without further Action or deed by or on behalf of the Corporation, to be modified, amended, and/or limited, but only to the extent necessary to render the same valid and enforceable, and the Corporation shall indemnify an Executive as to Liabilities and reasonable Expenses with respect to any Action to the full extent permitted by any applicable provision of this Article VI that shall not have been invalidated and to the full extent otherwise permitted by the Statute as it may then be in effect.

34

Exhibit 3.2

12.    Nonexclusivity of Article VI

The right to indemnification, contribution, and advancement of Expenses provided to an Executive by this Article VI shall not be deemed exclusive of any other rights to indemnification, contribution, and/or advancement of Expenses which any Executive or other employee or agent of the Corporation and/or of an Affiliate may be entitled under any charter provision, written agreement, resolution, vote of shareholders, or disinterested directors of the Corporation or otherwise, including, without limitation, under the Statute as it may then be in effect, both as to acts in his or her official capacity as such Executive or other employee or agent of the Corporation and/or of an Affiliate or as to acts in any other capacity while holding such office or position, whether or not the Corporation would have the power to indemnify, contribute, and/or advance Expenses to the Executive under this Article VI or under the Statute; provided that it is not determined that the Executive or other employee or agent has engaged in misconduct which constitutes a Breach of Duty.

13.    Notice to the Corporation; Defense of Actions

a. An Executive shall promptly notify the Corporation in writing upon being served with or having actual knowledge of any citation, summons, complaint, indictment, or any other similar document relating to any Action which may result in a claim of indemnification, contribution, or advancement of Expenses hereunder, but the omission so to notify the Corporation will not relieve the Corporation from any liability which it may have to the Executive otherwise than under this Article VI unless the Corporation shall have been irreparably prejudiced by such omission.

b. With respect to any such Action as to which an Executive notifies the Corporation of the commencement thereof:

(1) The Corporation shall be entitled to participate therein at its own expense; and

(2) Except as otherwise provided below, to the extent that it may wish, the Corporation (or any other indemnifying party, including any insurance carrier, similarly notified by the Corporation or the Executive) shall be entitled to assume the defense thereof, with counsel selected by the Corporation (or such other indemnifying party) and reasonably satisfactory to the Executive.

c. After notice from the Corporation (or such other indemnifying party) to the Executive of its election to assume the defense of an Action, the Corporation shall not be liable to the Executive under this Article VI for any Expenses subsequently incurred by the Executive in connection with the defense thereof other than reasonable costs of investigation or as otherwise provided below. The Executive shall have the right to employ his or her own counsel

35

Exhibit 3.2

in such Action but the Expenses of such counsel incurred after notice from the Corporation (or such other indemnifying party) of its assumption of the defense thereof shall be at the expense of the Executive unless:

(1) The employment of counsel by the Executive has been authorized by the Corporation;

(2) The Executive shall have reasonably concluded that there may be a conflict of interest between the Corporation (or such other indemnifying party) and the Executive in the conduct of the defense of such Action; or

(3) The Corporation (or such other indemnifying party) shall not in fact have employed counsel to assume the defense of such Action, in each of which cases the Expenses of counsel shall be at the expense of the Corporation.

The Corporation shall not be entitled to assume the defense of any Derivative Action or any Action as to which the Executive shall have made the conclusion provided for in clause (2) above.

14.    Continuity of Rights and Obligations

The terms and provisions of this Article VI shall continue as to an Executive subsequent to the Termination Date and such terms and provisions shall inure to the benefit of the heirs, estate, executors, and administrators of such Executive and the successors and assigns of the Corporation, including, without limitation, any successor to the Corporation by way of merger, consolidation, and/or sale or disposition of all or substantially all of the assets or capital stock of the Corporation. Except as provided herein, all rights and obligations of the Corporation and the Executive hereunder shall continue in full force and effect despite the subsequent amendment or modification of the Corporation's Articles of Incorporation, as such are in effect on the date hereof, and such rights and obligations shall not be affected by any such amendment or modification, any resolution of directors or shareholders of the Corporation, or by any other corporate action which conflicts with or purports to amend, modify, limit, or eliminate any of the rights or obligations of the Corporation and/or of the Executive hereunder.

15.    Amendment

This Article VI may only be altered, amended, or repealed by the affirmative vote of a majority of the shareholders of the Corporation so entitled to vote; provided, however, that the Board may alter or amend this Article VI without such shareholder approval if any such alteration or amendment:

a. Is made in order to conform to any amendment or revision of the Wisconsin Business Corporation Law, including, without limitation, the Statute, which:

36

Exhibit 3.2

(1) Expands or permits the expansion of an Executive's right to indemnification thereunder;

(2) Limits or eliminates, or permits the limitation or elimination, of liability of the Executives; or

(3) Is otherwise beneficial to the Executives; or

b. in the sole judgment and discretion of the Board, does not materially adversely affect the rights and protections of the shareholders of the Corporation.

Any repeal, modification, or amendment of this Article VI shall not adversely affect any rights or protections of an Executive existing under this Article VI immediately prior to the time of such repeal, modification, or amendment and any such repeal, modification, or amendment shall have a prospective effect only.

16.    Certain Definitions

The following terms as used in this Article VI shall be defined as follows:

a. "Action(s)" shall include, without limitation, any threatened, pending, or completed action, claim, litigation, suit, or proceeding, whether civil, criminal, administrative, arbitrative, or investigative, whether predicated on foreign, federal, state, or local law, whether brought under and/or predicated upon the Securities Act of 1933, as amended, and/or the Securities Exchange Act of 1934, as amended, and/or their respective state counterparts, and/or any rule or regulation promulgated thereunder, whether a Derivative Action, and whether formal or informal.

b. "Affiliate" shall include, without limitation, any corporation, partnership, joint venture, employee benefit plan, trust, or other similar enterprise that directly or indirectly through one or more intermediaries, controls or is controlled by, or is under common control with, the Corporation.

c. "Authority" shall mean the panel of arbitrators or independent legal counsel selected under Section 3 of this Article VI.

d. "Board" shall mean the Board of Directors of the Corporation.

e. "Breach of Duty" shall mean the Executive breached or failed to perform his or her duties to the Corporation or an Affiliate, as the case may be, and the Executive's breach of or failure to perform those duties constituted:

37

Exhibit 3.2

(1) A willful failure to deal fairly with the Corporation (or an Affiliate) or its shareholders in connection with a matter in which the Executive has a material conflict of interest;

(2) A violation of the criminal law, unless the Executive:

(a) Had reasonable cause to believe his or her conduct was lawful; or

(b) Had no reasonable cause to believe his or her conduct was unlawful;

(3) A transaction from which the Executive derived an improper personal profit (unless such profit is determined to be immaterial in light of all the circumstances of the Action); or

(4) Willful misconduct.

f. "Derivative Action" shall mean any Action brought by or in the right of the Corporation and/or an Affiliate.

g. "Executive(s)" shall mean any individual who is, was, or has agreed to become a director and/or officer of the Corporation and/or an Affiliate.

h. "Expenses" shall include, without limitation, all expenses, fees, costs, charges, attorneys' fees and disbursements, other out-of-pocket costs, reasonable compensation for time spent by the Executive in connection with the Action for which he or she is not otherwise compensated by the Corporation, any Affiliate, any third party or other entity, and any and all other direct and indirect costs of any type or nature whatsoever.

i. "Liabilities" shall include, without limitation, judgments, amounts incurred in settlement, fines, penalties, and, with respect to any employee benefit plan, any excise tax or penalty incurred in connection therewith, and any and all other liabilities of every type or nature whatsoever.

j. "Statute" shall mean Wisconsin Business Corporation Law Sections 180.0850-180.0859 (or any successor provisions).

k. "Termination Date" shall mean the date an Executive ceases, for whatever reason, to serve in an employment relationship with the Company and/or any Affiliate.

38

Exhibit 3.2

ARTICLE VII. SEAL

Board of Directors

The Board of Directors shall provide a corporate seal which shall be circular in form and shall have inscribed thereon the words "WISCONSIN PUBLIC SERVICE CORPORATION, GREEN BAY, WIS., CORPORATE SEAL." The continued use for any purpose of any former corporate seal or facsimile thereof shall have the same effect as the use of the corporate seal or facsimile thereof in the form provided by the preceding sentence.

ARTICLE VIII. AMENDMENTS

1. The Board of Directors shall have authority to adopt, amend, or repeal the By‑laws of this Corporation upon affirmative vote of a majority of the total number of directors at a meeting of the Board, the notice of which shall have included notice of the proposed amendment; but the Board of Directors shall have no power to amend any By-law adopted or amended by the shareholders after May 23, 1972, or to reinstate any By-law repealed by the shareholders after May 23, 1972, unless the shareholders shall hereafter confer such authority upon the Board of Directors.

2. The shareholders shall have power to adopt, amend, or repeal any of the By‑laws of the Corporation, at any regular or special meeting of the shareholders, in accordance with the provisions of Article II of these By-laws. There shall be included in the notice of such regular or special meeting a statement of the nature of any amendment that is proposed for the consideration of the shareholders by the holders of at least 5% of the voting stock of the Corporation in a writing delivered to the Secretary of the Corporation not less than 90 days prior to the date of such meeting or by the Board of Directors.

39

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-199909 on Form S-3 of our report dated February 26, 2016, relating to the financial statements and financial statement schedule of Wisconsin Public Service Corporation and subsidiary, appearing in this Annual Report on Form 10-K of Wisconsin Public Service Corporation and subsidiary for the year ended December 31, 2015.

/s/ Deloitte & Touche LLP

Milwaukee, Wisconsin

February 26, 2016

EX-31.1

Exhibit 31.1

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Allen L. Leverett, certify that:

1. I have reviewed this annual report on Form 10-K of Wisconsin Public Service Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2016

/s/ALLEN L. LEVERETT

Allen L. Leverett

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, J. Patrick Keyes, certify that:

1. I have reviewed this annual report on Form 10-K of Wisconsin Public Service Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2016

/s/J. PATRICK KEYES

J. Patrick Keyes

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Wisconsin Public Service Corporation (the "Company") on Form 10-K for the period ended December 31, 2015, as filed with the Securities and Exchange Commission on February 26, 2016 (the "Report"), I, Allen L. Leverett, Chairman, President and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ALLEN L. LEVERETT  

Allen L. Leverett

Chairman, President and Chief Executive Officer

February 26, 2016

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Wisconsin Public Service Corporation (the "Company") on Form 10-K for the period ended December 31, 2015, as filed with the Securities and Exchange Commission on February 26, 2016 (the "Report"), I, J. Patrick Keyes, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/J. PATRICK KEYES

J. Patrick Keyes

Executive Vice President and Chief Financial Officer

February 26, 2016

XML

DOCUMENT AND ENTITY INFORMATION - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	WISCONSIN PUBLIC SERVICE CORP
Entity Central Index Key	0000107833
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		23,896,962
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Operating revenues	$ 1,483.3	$ 1,683.6	$ 1,580.5
Cost of sales	599.8	771.1	721.5
Other operation and maintenance	493.4	499.7	470.4
Depreciation and amortization	121.0	116.8	109.4
Property and revenue taxes	41.0	38.4	39.2
Total operating expenses	1,255.2	1,426.0	1,340.5
Operating income	228.1	257.6	240.0
Other income, net	25.6	25.2	23.5
Interest expense	53.5	57.4	43.7
Other expense	(27.9)	(32.2)	(20.2)
Income before income taxes	200.2	225.4	219.8
Income tax expense	75.0	84.7	81.9
Net income	125.2	140.7	137.9
Preferred stock dividend requirements	2.7	3.1	3.1
Net income attributed to common shareholder	$ 122.5	$ 137.6	$ 134.8

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Cash and cash equivalents	$ 6.1	$ 5.4
Accounts receivable and unbilled revenues, net of reserves of $2.5 and $3.2, respectively	164.0	203.1
Receivables from related parties	3.1	1.3
Materials, supplies and inventories
Fuel and gas	104.5	85.0
Materials and supplies, at average cost	40.5	39.2
Prepaid taxes	48.1	65.7
Other current assets	27.0	17.7
Current assets	393.3	417.4
Property, plant, and equipment, net of accumulated depreciation of $1,565.7 and $1,542.5, respectively	3,418.6	3,131.0
Regulatory assets	462.5	457.1
Goodwill	36.4	36.4
Pension and other postretirement benefit assets	102.4	128.9
Other long-term assets	91.9	98.5
Long-term assets	4,111.8	3,851.9
Total assets	4,505.1	4,269.3
Liabilities and Shareholders' Equity
Short-term debt	182.8	145.1
Current portion of long-term debt	0.0	125.0
Current portion of long-term debt to parent	2.9	2.5
Accounts payable	181.8	161.6
Payables to related parties	35.6	16.9
Other current liabilities	50.2	71.6
Current liabilities	453.3	522.7
Long-term debt to parent	0.0	2.9
Long-term debt	1,289.4	1,040.1
Deferred income taxes	774.1	725.9
Deferred investment tax credits	7.4	7.8
Regulatory liabilities	290.0	318.4
Environmental remediation liabilities	83.5	86.3
Pension and other postretirement benefit obligations	24.4	37.6
Payables to related parties	4.8	5.4
Other long-term liabilities	92.3	71.6
Long-term liabilities	$ 2,565.9	$ 2,296.0
Commitments and contingencies (Note 18)
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively	$ 0.0	$ 51.2
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding	95.6	95.6
Additional paid-in capital	861.8	782.0
Retained earnings	528.5	521.8
Total liabilities and shareholder's equity	$ 4,505.1	$ 4,269.3

XML

CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves (in dollars)	$ 2.5	$ 3.2
Property, plant, and equipment, accumulated depreciation (in dollars)	$ 1,565.7	$ 1,542.5
Preferred stock, par value (in dollars per share)	$ 100	$ 100
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, shares issued	0	511,882
Preferred stock, shares outstanding	0	511,882
Common stock, par value (in dollars per share)	$ 4
Common stock, shares authorized	32,000,000
Common stock, shares issued	23,896,962	23,896,962
Common stock, shares outstanding	23,896,962	23,896,962

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities
Net income	$ 125.2	$ 140.7	$ 137.9
Reconciliation to cash provided by operating activities
Depreciation and amortization	121.0	113.8	106.2
Pension and other postretirement (credit) expense	(2.7)	(6.2)	22.2
Contributions to pension and OPEB plans	(2.4)	(49.5)	(43.5)
Deferred income taxes and investment tax credits, net	43.6	90.5	79.4
Termination of tolling agreement with Fox Energy Company LLC	0.0	0.0	(50.0)
Change in –
Collateral on deposit	(17.4)	(3.8)	1.2
Accounts receivable and unbilled revenues	38.6	13.4	(14.6)
Materials, supplies, and inventories	(16.1)	(28.0)	19.6
Prepaid taxes	17.6	(2.1)	21.1
Other current assets	1.5	3.7	(2.3)
Accounts payable	5.0	15.5	(18.0)
Other current liabilities	(3.3)	(14.0)	6.5
Other, net	(5.9)	(10.5)	7.4
Net cash provided by operating activities	304.7	263.5	273.1
Investing activities
Capital expenditures	(371.0)	(322.0)	(236.1)
Acquisition of Fox Energy Company LLC	0.0	0.0	(391.6)
Grant received related to Crane Creek wind project	0.0	0.0	69.0
Other, net	(2.3)	0.9	2.1
Net cash used for investing activities	(373.3)	(321.1)	(556.6)
Financing activities
Change in short-term debt	37.7	119.5	(69.8)
Borrowing on term credit facility	0.0	0.0	200.0
Repayment of term credit facility	0.0	0.0	(200.0)
Repayment of long-term debt	(125.1)	0.0	(147.0)
Repayment of long-term debt to parent	(2.5)	(0.9)	(0.9)
Issuance of long-term debt	250.0	0.0	450.0
Payments of dividend to parent	(115.1)	(111.8)	(108.6)
Equity contribution from parent	235.0	55.0	200.0
Return of capital to parent	(150.0)	0.0	(35.0)
Preferred stock dividend requirements	(2.7)	(3.1)	(3.1)
Redemption of preferred stock	(52.7)	0.0	0.0
Other, net	(5.3)	(1.4)	(2.9)
Net cash provided by financing activities	69.3	57.3	282.7
Net change in cash and cash equivalents	0.7	(0.3)	(0.8)
Cash and cash equivalents at beginning of year	5.4	5.7	6.5
Cash and cash equivalents at end of year	$ 6.1	$ 5.4	$ 5.7

XML

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total Common Shareholder's Equity	Common Stock	Additional Paid in Capital	Retained Earnings
Balance at Dec. 31, 2012		$ 1,121.5	$ 95.6	$ 555.4	$ 470.5
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholder	$ 134.8	134.8	0.0	0.0	134.8
Equity contribution from parent	200.0	200.0	0.0	200.0	0.0
Return of capital to parent	35.0	(35.0)	0.0	(35.0)	0.0
Dividends to parent		(108.6)	0.0	0.0	(108.6)
Other		2.7	0.0	3.1	(0.4)
Balance at Dec. 31, 2013		1,315.4	95.6	723.5	496.3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholder	137.6	137.6	0.0	0.0	137.6
Equity contribution from parent	55.0	55.0	0.0	55.0	0.0
Return of capital to parent	0.0
Dividends to parent		(111.8)	0.0	0.0	(111.8)
Other		3.2	0.0	3.5	(0.3)
Balance at Dec. 31, 2014	1,399.4	1,399.4	95.6	782.0	521.8
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholder	122.5	122.5	0.0	0.0	122.5
Equity contribution from parent	235.0	235.0	0.0	235.0	0.0
Return of capital to parent	150.0	(150.0)	0.0	(150.0)	0.0
Dividends to parent		(115.1)	0.0	0.0	(115.1)
Other		(5.9)	0.0	(5.2)	(0.7)
Balance at Dec. 31, 2015	$ 1,485.9	$ 1,485.9	$ 95.6	$ 861.8	$ 528.5

XML

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Capitalization
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares outstanding	$ 95.6	$ 95.6
Additional paid-in capital	861.8	782.0
Retained earnings	528.5	521.8
Total common stock equity	1,485.9	1,399.4
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively	0.0	51.2
Notes payable to Integrys	2.9	5.4
Current portion of long-term debt to parent	(2.9)	(2.5)
Total long-term debt to parent	0.0	2.9
Total First Mortgage Bonds and Senior Notes	1,300.0	1,175.1
Unamortized Debt Issuance Expense	(9.9)	(9.4)
Unamortized discount on long-term debt	(0.7)	(0.6)
Total	1,289.4	1,165.1
Current portion of long-term debt	0.0	(125.0)
Total long-term debt	1,289.4	1,040.1
Total capitalization	$ 2,775.3	2,493.6
Long Term debt to parent, 8.76% Series, Year Due, 2015
Schedule of Capitalization
Interest rate, (as a percent)	8.76%
Notes payable to Integrys	$ 0.0	2.0
Long Term debt to parent, 7.35% Series, Year Due, 2016
Schedule of Capitalization
Interest rate, (as a percent)	7.35%
Notes payable to Integrys	$ 2.9	3.4
Long Term debt, 7.125% Series, Year Due, 2023
Schedule of Capitalization
Interest rate, (as a percent)	7.125%
First Mortgage Bonds	$ 0.0	0.1
Long Term debt, 6.375% Series, Year Due, 2015
Schedule of Capitalization
Interest rate, (as a percent)	6.375%
Senior Notes	$ 0.0	125.0
Long Term debt, 5.65% Series, Year Due, 2017
Schedule of Capitalization
Interest rate, (as a percent)	5.65%
Senior Notes	$ 125.0	125.0
Long Term Debt 1.65% Series, Due 2018
Schedule of Capitalization
Interest rate, (as a percent)	1.65%
Senior Notes	$ 250.0	0.0
Long Term debt, 6.08% Series, Year Due, 2028
Schedule of Capitalization
Interest rate, (as a percent)	6.08%
Senior Notes	$ 50.0	50.0
Long Term debt, 5.55% Series, Year Due, 2036
Schedule of Capitalization
Interest rate, (as a percent)	5.55%
Senior Notes	$ 125.0	125.0
Long Term Debt 3.671% Series, Year Due, 2042
Schedule of Capitalization
Interest rate, (as a percent)	3.671%
Senior Notes	$ 300.0	300.0
Long Term debt 4.752% Series, Year Due 2044
Schedule of Capitalization
Interest rate, (as a percent)	4.752%
Senior Notes	$ 450.0	$ 450.0

XML

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION
Common stock, par value (in dollars per share)	$ 4
Common stock, shares authorized	32,000,000
Common stock, shares outstanding	23,896,962	23,896,962
Preferred stock, par value (in dollars per share)	$ 100	$ 100
Preferred stock, shares authorized	1,000,000	1,000,000

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

We are an electric and natural gas utility company that services customers in northeastern Wisconsin and Michigan's Upper Peninsula. We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates.

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

At December 31, 2015, we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

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

(b) Reclassifications—As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below.

Statements of Income

• Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net.

• Payroll taxes of $8.3 million and $8.9 million for the years ended December 31, 2014 and 2013, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes.

• Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $5.9 million and $6.7 million for the years ended December 31, 2014 and 2013, respectively.

• Certain expenses in other operation and maintenance were reclassified to cost of sales, and depreciation and amortization. The amounts reclassified to other cost of sales were $3.1 million and $5.6 million for the years ended December 31, 2014 and 2013, respectively.

Balance Sheets

• Current regulatory assets of$1.4 millionand$23.6 millionwere reclassified to accounts receivable and long-term regulatory assets, respectively, at December 31, 2014.

• Current regulatory liabilities of$6.1 millionand$15.1 millionwere reclassified to other current liabilities and long-term regulatory liabilities, respectively, at December 31, 2014.

• During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $0.6 million and $8.8 million, previously reported as other current assets and other long-term assets, respectively, were reclassified to offset long-term debt on the December 31, 2014 balance sheet.

• During the fourth quarter of 2015, we also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $3.8 million, previously reported as a component of other current liabilities, to long-term deferred income tax liabilities on the December 31, 2014 balance sheet.

Statements of Cash Flows

• Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections.

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

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

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

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

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

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

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

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

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

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

(in millions)	2015		2014
Fossil fuel	$	76.4	$	48.9
Materials and supplies	40.5		39.2
Natural gas in storage	28.1		36.1
Total	$	145.0	$	124.2

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

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

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

We record straight-line depreciation expense over the estimated useful life of utility property, using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:

Annual Utility Composite Depreciation Rates	2015		2014		2013
Electric	2.70	%	2.73	%	2.79	%
Natural gas	2.15	%	2.17	%	2.19	%

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

We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense.

See Note 7, Property, Plant, and Equipment, for more information.

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

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 7.92%, 8.08%, and 8.61% for 2015, 2014, and 2013, respectively. Our average AFUDC wholesale rates were 5.10%, 6.99%, and 2.64% for 2015, 2014, and 2013, respectively.

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

(in millions)	2015		2014		2013
AFUDC – Debt	$	6.1	$	4.6	$	3.8
AFUDC – Equity	15.1		11.0		9.9

(i) Emission Allowances—We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers.

(j) Goodwill—Goodwill is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performed its annual goodwill impairment test as of April 1, 2015. Interim impairment tests are performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value.

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

(l) Environmental Remediation Costs — We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 18, Commitments and Contingencies, for more information.

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

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

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

(m) Income Taxes — We and our subsidiary are included in the consolidated United States income tax return filed by Integrys for all tax periods up to and including the tax year ended June 29, 2015. For all tax periods after June 29, 2015, we and our subsidiary are included within the WEC Energy Group consolidated return. Similarly, we and our subsidiary are party to a tax allocation arrangement with Integrys and its consolidated subsidiaries for all tax periods up to and including June 29, 2015, and are a party to a tax allocation arrangement with WEC Energy Group and its consolidated subsidiaries for tax periods ending after June 29, 2015.

Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.

We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.

We report interest and penalties accrued, related to income taxes, as a component of income tax expense in our income statements.

We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.

See Note 15, Income Taxes, for more information regarding our accounting for income taxes.

(n) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 21, Regulatory Environment, for more information.

(o) Employee Benefits—The costs of pension and OPEB are expensed over the periods during which employees render service. The benefit costs associated with employee benefit plans are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information.

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

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

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

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

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

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

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input.

Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available. We recognize transfers at the value as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount for each such item approximates fair value. The fair values of long-term debt, including the current portion of long-term debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity.

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

See Note 19, Fair Value Measurements, for more information.

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

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

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

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 20, Derivative Instruments, for more information.

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

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

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MERGER

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

MERGER

MERGER

On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded at December 31, 2015 related to the proposed construction.

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

In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:

(in millions)	2015
Electric utility segment	$	3.6
Natural gas utility segment	1.0
Total severance expense	$	4.6

ACQUISITION

In March 2013, we acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved immediately after the purchase.

The purchase included the Fox Energy Center, a 593 MW combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives us a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(in millions)
Assets acquired (1)
Inventories – materials and supplies	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets (2)	15.6
Total assets acquired	$	393.4
Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8

⁽¹⁾  Relates to the electric utility segment.

⁽²⁾  Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information.

Prior to the purchase, we supplied natural gas for the facility and purchased 500 MWs of capacity and the associated energy output under a tolling arrangement. We paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as we are authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.

Our 2015 retail electric rate increase included the recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. See Note 21, Regulatory Environment, for more information. Our rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.

Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by us. The plant is now part of our regulated fleet, used to serve our customers.

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ACQUISITION

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

ACQUISITION OF FOX ENERGY CENTER

MERGER

On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded at December 31, 2015 related to the proposed construction.

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

In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:

(in millions)	2015
Electric utility segment	$	3.6
Natural gas utility segment	1.0
Total severance expense	$	4.6

ACQUISITION

In March 2013, we acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved immediately after the purchase.

The purchase included the Fox Energy Center, a 593 MW combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives us a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(in millions)
Assets acquired (1)
Inventories – materials and supplies	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets (2)	15.6
Total assets acquired	$	393.4
Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8

⁽¹⁾  Relates to the electric utility segment.

⁽²⁾  Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information.

Prior to the purchase, we supplied natural gas for the facility and purchased 500 MWs of capacity and the associated energy output under a tolling arrangement. We paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as we are authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.

Our 2015 retail electric rate increase included the recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. See Note 21, Regulatory Environment, for more information. Our rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.

Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by us. The plant is now part of our regulated fleet, used to serve our customers.

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RELATED PARTIES

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

RELATED PARTIES

RELATED PARTIES

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

We provide and receive services, property, and other items of value to and from our ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the WEC Merger on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WBS, and a new affiliated interest agreement (Non-WBS AIA) went into effect. The new Non-WBS AIA includes the former Wisconsin Energy Corporation and its subsidiaries. It governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries under new interim WBS affiliated interest agreements (interim WBS AIAs). The Non-WBS AIA includes no other significant changes from the prior Non-IBS affiliated interest agreement. The PSCW and all other relevant state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

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

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

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

We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost.

We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC under which either party may be a service provider. Services are billed to and from WRPC under these agreements at a fully allocated cost.

The table below includes information summarizing other transactions entered into with related parties:

(in millions)	December 31, 2015		December 31, 2014
Accounts receivable
Service provided to ATC	$	0.5	$	0.9
Notes payable *
Integrys	2.9		5.4
Accounts payable
Network transmission services from ATC	8.5		8.2
Liability related to income tax allocation
Integrys	5.4		6.1

* WPS Leasing, our consolidated subsidiary, has a note payable to Integrys. At December 31, 2015 and 2014, the current portion of the note payable was $2.9 million and $2.5 million, respectively.

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

(in millions)	2015		2014		2013
Electric transactions
Sales to UPPCO (1)	$	—	$	15.3	$	22.8
Sales to ITF (2)	—		0.1		—
Sales to Wisconsin Electric	0.1		—		—
Natural gas transactions
Sales to Wisconsin Electric	0.4		—		—
Sales to IES (3)	—		0.6		0.5
Purchases from IES (3)	—		2.5		0.9
Interest expense (4)
Integrys	0.3		0.5		0.5
Transactions with equity-method investees
Charges from ATC for network transmission services	101.3		99.0		98.4
Charges to ATC for services and construction	10.3		8.6		9.5
Purchases of energy from WRPC	3.8		3.7		3.7
Charges to WRPC for operations	1.1		1.4		0.9
Equity earnings from WPS Investments, LLC (5)	7.7		9.5		10.2
Sales of electricity to AMP Trillium, LLC (6)	0.1		—		—

⁽¹⁾  Integrys sold UPPCO in August 2014.

⁽²⁾  In February 2016, an agreement was entered into to sell ITF. This sale is scheduled to close in the first quarter of 2016.

⁽³⁾  Integrys sold IES's retail energy business in November 2014.

⁽⁴⁾  WPS Leasing has a note payable to Integrys.

⁽⁵⁾  WPS Investments, LLC is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015, we had an 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC.

⁽⁶⁾  In November 2015, ITF, an indirect wholly-owned subsidiary of Integrys, sold its ownership interest in AMP Trillium, LLC, a joint venture between ITF and AMP Americas, LLC. This joint venture owned and operated compressed natural gas fueling stations.

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SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

CASH AND CASH EQUIVALENTS

SUPPLEMENTAL CASH FLOW INFORMATION

(in millions)	2015		2014			2013
Cash paid for interest, net of amount capitalized	$	58.1	$	56.8		$	43.9
Cash paid (received) for income taxes, net of refunds	14.5		(6.2		)	(27.3		)
Significant non-cash transactions:
Construction costs funded through accounts payable	70.5		54.0			37.3

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REGULATORY ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

REGULATORY ASSETS AND LIABILITIES

REGULATORY ASSETS AND LIABILITIES

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

(in millions)	2015		2014		See Note
Regulatory assets (1) (2)
Unrecognized pension and OPEB costs (3)	$	176.6	$	185.6	17
Environmental remediation costs (4)	104.4		103.8		18
Income tax related items (5)	40.8		32.7
Termination of a tolling agreement with Fox Energy Company LLC	39.1		44.6		3
Crane Creek production tax credits (6)	30.9		32.2
De Pere Energy Center (7)	19.0		21.4
Energy costs recoverable through rate adjustments (8)	12.0		12.6
Other	39.9		25.6
Total regulatory assets	$	462.7	$	458.5
Balance Sheet Presentation
Current assets (9)	$	0.2	$	1.4
Regulatory assets	462.5		457.1
Total regulatory assets	$	462.7	$	458.5

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

⁽²⁾  As of December 31, 2015, we had $21.0 million of regulatory assets not earning a return.

⁽³⁾  Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans.

⁽⁴⁾  As of December 31, 2015, we had not yet made cash expenditures for $83.5 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.

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

⁽⁶⁾  In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12-year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039.

⁽⁷⁾  Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023.

⁽⁸⁾  Represents energy costs that will be recovered from customers in the future.

⁽⁹⁾  Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets.

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

(in millions)	2015		2014		See Note
Regulatory liabilities
Removal costs (1)	$	243.7	$	243.9
Energy costs refundable through rate adjustments (2)	29.4		6.0
Crane Creek depreciation deferral (3)	8.3		8.7
Unrecognized pension and OPEB costs (4)	1.0		42.4		17
Decoupling	—		12.3		21
Other	11.2		11.2
Total regulatory liabilities	$	293.6	$	324.5
Balance Sheet Presentation
Other current liabilities	$	3.6	$	6.1
Regulatory liabilities	290.0		318.4
Total regulatory liabilities	$	293.6	$	324.5

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

⁽²⁾  Represents energy costs that will be refunded to customers in the future.

⁽³⁾  Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.

⁽⁴⁾   Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

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PROPERTY, PLANT, AND EQUIPMENT

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT

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

(in millions)	2015		2014
Electric utility	$	3,722.8	$	3,587.4
Natural gas utility	818.4		773.1
Total utility plant	4,541.2		4,360.5
Less: Accumulated depreciation	1,559.6		1,495.9
Net	2,981.6		2,864.6
CWIP	434.2		248.7
Plant to be retired, net *	—		12.5
Net utility plant	3,415.8		3,125.8
Non-utility plant	8.9		15.2
Less: Accumulated depreciation	6.1		10.0
Net non-utility plant	2.8		5.2
Total property, plant, and equipment	$	3,418.6	$	3,131.0

* In connection with the Consent Decree with the EPA, we retired Weston 1 and Pulliam Units 5 and 6 on June 1, 2015. See Note 18, Commitments and Contingencies, for more information regarding the Consent Decree.

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JOINTLY OWNED UTILITY FACILITIES

12 Months Ended

Dec. 31, 2015

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

JOINTLY OWNED UTILITY FACILITIES

JOINTLY OWNED UTILITY FACILITIES

We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. The amounts were as follows at December 31, 2015:

(in millions, except for percentages and MWs)	Weston 4			Columbia Energy Center Units 1 and 2			Edgewater Unit 4
Ownership	70.0		%	31.8		%	31.8		%
Our share of rated capacity (MWs) *	374.5			352.9			96.3
In-service date	2008			1975 and 1978			1969
Utility plant	$	591.5		$	404.6		$	47.6
Accumulated depreciation	$	(150.5	)	$	(122.6	)	$	(30.6	)
CWIP	$	5.9		$	23.4		$	0.4

* Based on expected capacity ratings for summer 2016. 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.

Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects. See Note 18, Commitments and Contingencies, for information related to the requirement to refuel, repower, or retire Edgewater Unit 4.

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of fly-ash landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.

The following table shows changes to our AROs:

(in millions)	2015					2014					2013
Balance as of January 1	$	20.3				$	18.0				$	16.7
Accretion	1.2					1.0					0.9
Additions and revisions to estimated cash flows (1)	11.4			(1	)	1.5			(2	)	0.5
Liabilities settled	(0.2		)			(0.2		)			(0.1		)
Balance as of December 31	$	32.7				$	20.3				$	18.0

⁽¹⁾  An ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates.

⁽²⁾  We revised the AROs recorded for the asbestos at our electric generation facilities primarily due to changes in estimated settlement dates.

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GOODWILL AND OTHER INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL AND OTHER INTANGIBLE ASSETS

GOODWILL AND OTHER INTANGIBLE ASSETS

We had no changes to the carrying amount of goodwill during the years ended December 31, 2015 and 2014. In the second quarter of 2015, we completed our annual goodwill impairment test, and no impairment resulted from this test.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets.

	December 31, 2015							December 31, 2014
(in millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	15.6	$	(7.5	)	$	8.1	$	15.6	$	(4.3	)	$	11.3
Unamortized intangible assets	0.4		—			0.4		—		—			—
Total intangible assets	$	16.0	$	(7.5	)	$	8.5	$	15.6	$	(4.3	)	$	11.3

* Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2015, was approximately three years.

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COMMON EQUITY

12 Months Ended

Dec. 31, 2015

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Stock-Based Compensation

Our employees were granted awards under Integrys’s stock-based compensation plans. Pursuant to the Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were settled in exchange for the right to be paid out in cash to award recipients. See Note 2, Merger, for more information regarding the merger.

The intrinsic values of the awards settled due to the merger were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options settled was not significant.

Compensation cost associated with stock-based compensation awards was allocated to us based on the percentages used for allocation of the award recipients’ labor costs. The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31:

(in millions)	2015		2014		2013
Stock options	$	—	$	1.0	$	0.7
Performance stock rights	1.3		6.3		1.1
Restricted share units	3.5		3.8		3.4
Total stock-based compensation expense	$	4.8	$	11.1	$	5.2
Deferred income tax benefit	$	1.9	$	4.4	$	2.1

A summary of the activity for our stock-based compensation awards for the year ended December 31, 2015, is presented below:

	Stock Options		Performance Stock Rights		Restricted Stock Units
Outstanding as of January 1, 2015	5,714		13,937		70,544
Granted	—		—		30,174
Dividend equivalents	N/A		N/A		1,267
Transferred	—		—		(166	)
Exercised/Distributed/Vested and Released *	(2,752	)	(2,229	)	(28,428	)
Settled as a result of WEC Merger	(2,962	)	(21,263	)	(73,391	)
Adjustment for performance stock rights distributed or settled	N/A		9,555		N/A
Outstanding as of December 31, 2015	—		—		—

* The intrinsic value of restricted stock unit awards vested and released was $2.2 million. The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant.

Restrictions

Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys.

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

See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2015, restricted retained earnings totaled $528.5 million. Our equity in undistributed earnings of investees accounted for by the equity method was $32.3 million at December 31, 2015.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Integrys may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their other subsidiaries.

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PREFERRED STOCK

12 Months Ended

Dec. 31, 2015

Class of Stock Disclosures [Abstract]

PREFERRED STOCK

PREFERRED STOCK

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

2015	Shares Authorized	Shares Outstanding	Redemption Price Per Share	Total
$100 par value, Preferred Stock	1,000,000	—	N/A	N/A

2014 (in millions, except share and per share amounts)	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
$100 par value, Preferred Stock	1,000,000
5.00% Series		131,916	$	107.50	$	13.2
5.04% Series		29,983	102.81		3.0
5.08% Series		49,983	101.00		5.0
6.76% Series		150,000	103.35		15.0
6.88% Series		150,000	100.00		15.0
Total					$	51.2

On November 13, 2015, we redeemed all 511,882 outstanding shares of our five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and, (v) 150,000 shares of 6.88% Series. The aggregate redemption price was $52.7 million, plus accumulated and unpaid dividends.

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SHORT-TERM DEBT AND LINES OF CREDIT

12 Months Ended

Dec. 31, 2015

Short-term Debt [Abstract]

SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings and their corresponding weighted-average interest rates as of December 31 were as follows:

(in millions, except percentages)	2015		2014
Commercial paper
Amount outstanding at December 31	$	182.8	$	145.1
Average interest rate on amounts outstanding at December 31	0.66%		0.32		%
Average amount outstanding during the year *	$	145.0	$	43.3

* Based on daily outstanding balances during the year.

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

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

(in millions)	Maturity	2015
Revolving credit facility *	December 2016	$	250.0
Total short-term credit capacity		$	250.0
Less: commercial paper outstanding		182.8
Available capacity under existing agreement		$	67.2

* We plan to request approval from the PSCW to extend the maturity through December 2020.

In December 2015, we terminated our prior credit facilities and entered into a new credit facility maturing in 2016. The lenders under this facility have agreed that its maturity can be extended to December 2020, subject to our receipt of PSCW approval. This $250.0 million facility has a renewal provision for twoone-year extensions, subject to lender approval.

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

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

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

In November 2015, we redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7.125% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption. Following the redemption, we discharged our mortgage indenture and do not intend to issue additional first mortgage bonds. All of our senior notes outstanding are now senior unsecured obligations and rank equally with all of our other unsecured obligations.

In December 2015, our $125.0 million of 6.375% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2015, we issued $250.0 million of 1.65% Senior Notes due December 4, 2018. The proceeds were used to repay short-term debt that we incurred to repay all of our $125.0 million of 6.375% Senior Notes at maturity, and for working capital and other general corporate purposes.

A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to our parent, is as follows:

(in millions)	Payments
2016	$	—
2017	125.0
2018	250.0
2019	—
2020	—
Thereafter	925.0
Total	$	1,300.0

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

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INCOME TAXES

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

Income Tax Expense

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

(in millions)	2015			2014			2013
Current tax expense	$	31.4		$	(6.1	)	$	2.1
Deferred income taxes, net	44.0			91.1			80.1
Investment tax credit, net	(0.4		)	(0.3		)	(0.3		)
Total income tax expense	$	75.0		$	84.7		$	81.9

Statutory Rate Reconciliation

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

	2015					2014					2013
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
Expected tax at statutory federal tax rates	$	70.1		35.0	%	$	78.9		35.0	%	$	76.9		35.0	%
State income taxes net of federal tax benefit	9.9			5.0		10.9			4.8		10.5			4.8
AFUDC – Equity	(5.3		)	(2.6	)	(3.8		)	(1.7	)	(3.5		)	(1.6	)
Other, net	0.3			0.1		(1.3		)	(0.5	)	(2.0		)	(0.9	)
Total income tax expense	$	75.0		37.5	%	$	84.7		37.6	%	$	81.9		37.3	%

Deferred Income Tax Assets and Liabilities

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

(in millions)	2015		2014
Total deferred tax assets	$	23.9	$	4.4
Deferred tax liabilities
Plant-related	639.1		591.0
Employee benefits and compensation	91.7		83.9
Regulatory deferrals	52.0		42.4
Other	15.2		13.0
Total deferred tax liabilities	798.0		730.3
Deferred tax liability, net	$	774.1	$	725.9

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

Deferred tax credit carryforwards at December 31, 2015, included $2.0 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $3.0 million of general business credits, which have a carryback period of one year and a carryforward period of 20 years. The majority of the general business credit carryforwards will expire in 2033.

At December 31, 2015, we had deferred income tax assets of $16.1 million reflecting federal operating loss carryforwards, which have a carryback period of two years and a carryforward period of 20 years and will expire in 2034.

Unrecognized Tax Benefits

We had no unrecognized tax benefits at December 31, 2015, and 2014.

We had no accrued interest and penalties related to unrecognized tax benefits at December 31, 2015, and 2014.

We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2015.

We file income tax returns in the United States federal jurisdiction and in our major state operating jurisdictions as a part of Integrys filings up to June 29, 2015, and as a part of WEC Energy Group filings for periods after June 29, 2015.

With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2012.

We file state tax returns based on income in our major state operating jurisdictions of Wisconsin and Michigan. We are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2015, we were subject to examination by the Wisconsin taxing authority for tax years 2011 through 2015 and the Michigan taxing authority for tax years 2008 through 2015. During 2015, the Michigan taxing authority continued its examination of tax years 2008 through 2011.

In the next 12 months, we do not expect to significantly change the amount of unrecognized tax benefits.

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GUARANTEES

12 Months Ended

Dec. 31, 2015

Guarantees [Abstract]

GUARANTEES

GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts Committed		Expiration
(in millions)	at December 31, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	9.5	$	—	$	9.5	$	—
Surety bonds(2)	1.1		1.1		—		—
Other guarantee(3)	20.3		20.0		—		0.3
Total guarantees	$	30.9	$	21.1	$	9.5	$	0.3

⁽¹⁾  At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our balance sheets.

⁽²⁾  Primarily for obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

⁽³⁾  Consists of (a) $20.0 million not reflected on our balance sheet for an interconnection agreement between us and ATC and (b) $0.3 million reflected on our balance sheet related to workers compensation.

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in the Integrys retirement plan, a noncontributory, qualified pension plan sponsored by WBS. We are responsible for our share of the plan assets and obligations. We serve as plan sponsor and administrator for certain OPEB plans. The benefits are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. Integrys also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred.

The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. In March 2014, we remeasured the obligations of certain OPEB plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015.

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

	Pension Costs						OPEB Costs
(in millions)	2015			2014			2015			2014
Change in benefit obligation
Obligation at January 1	$	791.8		$	717.5		$	252.5		$	292.7
Service cost	10.7			8.6			8.7			7.7
Interest cost	31.7			34.4			10.4			11.5
Plan amendments	—			—			—			(74.4		)
Transfer to affiliates *	(130.5		)	(12.1		)	—			—
Actuarial loss (gain), net	(36.4		)	73.0			(31.7		)	24.0
Participant contributions	—			—			0.3			0.5
Benefit payments	(33.3		)	(29.6		)	(8.6		)	(10.4		)
Federal subsidy on benefits paid	—			—			—			0.9
Plan curtailment	(0.1		)	$	—		—			$	—
Obligation at December 31	$	633.9		$	791.8		$	231.6		$	252.5
Change in fair value of plan assets
Fair value of plan assets at January 1	$	897.4		$	839.1		$	236.6		$	236.5
Actual return on plan assets	(29.4		)	53.1			(5.1		)	7.4
Employer contributions	1.1			46.9			1.3			2.6
Participant contributions	—			—			0.3			0.5
Benefit payments	(33.3		)	(29.6		)	(8.6		)	(10.4		)
Transfer to affiliates *	(116.8		)	(12.1		)	—			—
Fair value at December 31	$	719.0		$	897.4		$	224.5		$	236.6

* Benefit obligations and plan assets were moved along with our employees who were transferred to affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries.

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

	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015			2014
Pension and other postretirement benefit assets	$	93.8	$	128.9	$	8.6		$	—
Current liabilities	—		1.5		—			0.1
Pension and other postretirement benefit liabilities	8.7		21.8		15.7			15.8
Total net assets (liabilities)	$	85.1	$	105.6	$	(7.1	)	$	(15.9	)

The accumulated benefit obligation for the defined benefit pension plans was $569.6 million and $717.4 million at December 31, 2015, and 2014, respectively.

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)	2015		2014
Projected benefit obligation	$	8.7	$	23.3
Accumulated benefit obligation	8.5		21.5

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

	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015		2014
Net regulatory assets
Net actuarial loss	$	61.2	$	178.7	$	5.2	$	41.0
Prior service cost (credit)	—		1.8		—		(78.3		)
Total	$	61.2	$	180.5	$	5.2	$	(37.3	)

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

	Pension Costs									OPEB Costs
(in millions)	2015			2014			2013			2015			2014			2013
Service cost	$	10.7		$	8.6		$	10.8		$	8.7		$	7.7		$	10.6
Interest cost	31.7			34.4			30.6			10.4			11.5			13.4
Expected return on plan assets	(64.8		)	(64.1		)	(57.2		)	(16.0		)	(16.0		)	(14.8		)
Loss on plan settlement	0.1			0.4			—			—			—			—
Amortization of prior service cost (credit)	0.2			0.6			3.6			(9.3		)	(8.0		)	(2.1		)
Amortization of net actuarial loss	21.0			15.0			24.0			3.7			2.8			7.5
Net periodic benefit cost	$	(1.1	)	$	(5.1	)	$	11.8		$	(2.5	)	$	(2.0	)	$	14.6

Assumptions – Pension and Other Postretirement Benefit Plans

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

	Pension		OPEB
	2015	2014	2015	2014
Discount rate	4.49%	4.08%	4.46%	4.11%
Rate of compensation increase	4.00%	4.23%	N/A	N/A
Assumed medical cost trend rate	N/A	N/A	7.50%	6.00%
Ultimate trend rate	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached	N/A	N/A	2021	2023

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

	Pension Costs
	2015	2014	2013
Discount rate	4.08%	4.92%	4.07%
Expected return on assets	7.75%	8.00%	8.00%
Rate of compensation increase	4.23%	4.25%	4.26%

	OPEB Costs
	2015	2014	2013
Discount rate	4.11%	4.78%	4.01%
Expected return on assets	7.75%	8.00%	8.00%
Assumed medical cost trend rate (Pre 65/Post 65)	6.00%	6.50%	7.00%
Ultimate trend rate	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2023	2019	2019

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

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

(in millions)	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	3.8	$	(2.9	)
Effect on the health care component of the accumulated postretirement benefit obligation	31.9		(25.7		)

Plan Assets

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

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

Central to the policy are target allocation ranges by major asset categories. The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans' actuarial assumptions and that are competitive with like instruments employing similar investment strategies. The portfolio diversification provides protection against significant concentrations of risk in the plan assets. In 2014, the pension plan target asset allocation was 70% equity securities and 30% fixed income securities. In December 2014, we changed the pension plan target asset allocation to 60% equity securities and 40% fixed income securities for 2015. The target asset allocation for OPEB plans that have significant assets is 70% equity securities and 30% fixed income securities. Equity securities primarily include investments in large-cap and small-cap companies. Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities.

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

The following tables provide the fair values of our investments by asset class:

	December 31, 2015
	Pension Plan Assets											OPEB Assets
(in millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset class
Cash and cash equivalents	$	—		$	27.4		$	—	$	27.4		$	4.6	$	1.0	$	—	$	5.6
Equity securities:
U.S. Equity	39.2			162.2			—		201.4			11.9		60.0		—		71.9
International Equity	40.3			179.3			—		219.6			15.5		58.5		—		74.0
Fixed income securities: (1)
U.S. Bonds	6.3			218.3			—		224.6			65.1		—		—		65.1
International Bonds	—			55.9			—		55.9			—		—		—		—
	85.8			643.1			—		728.9			97.1		119.5		—		216.6
401(h) other benefit plan assets invested as pension assets (2)	(0.9		)	(7.2		)	—		(8.1		)	0.9		7.2		—		8.1
Total (3)	$	84.9		$	635.9		$	—	$	720.8		$	98.0	$	126.7	$	—	$	224.7

⁽¹⁾  This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

⁽²⁾  Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

⁽³⁾  Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

	December 31, 2014
	Pension Plan Assets											OPEB Assets
(in millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset class
Cash and cash equivalents	$	0.3		$	25.3		$	—	$	25.6		$	3.4	$	1.5			$	4.9
Equity securities:
U.S. Equity	53.3			197.8			—		251.1			14.6		62.4				77.0
International Equity	54.4			225.9			—		280.3			17.6		65.5				83.1
Fixed income securities: (1)
U.S. Bonds	41.3			261.8			—		303.1			62.8		—				62.8
International Bonds	—			44.6			—		44.6			—		—				—
	149.3			755.4			—		904.7			98.4		129.4		—		227.8
401(h) other benefit plan assets invested as pension assets (2)	(1.5		)	(7.3		)	—		(8.8		)	1.5		7.3		—		8.8
Total (3)	$	147.8		$	748.1		$	—	$	895.9		$	99.9	$	136.7	$	—	$	236.6

⁽¹⁾  This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

⁽²⁾  Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

⁽³⁾  Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2014. There was no level 3 activity in 2015.

(in millions)	International Bonds			U.S. Bonds			Total
Beginning balance at January 1, 2014	$	1.3		$	0.7		$	2.0
Net realized and unrealized gains	0.1			0.1			0.2
Sales	(1.4		)	(0.8		)	(2.2		)
Ending balance at December 31, 2014	$	—		$	—		$	—

Cash Flows

We expect to contribute $1.4 million to the pension plans and $2.1 million to OPEB plans in 2016, dependent on various factors affecting us, including our liquidity position and tax law changes.

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

(in millions)	Pension Costs		OPEB Costs
2016	$	46.9	$	9.6
2017	29.6		10.5
2018	29.1		11.4
2019	32.6		12.2
2020	33.7		13.0
2021-2025	172.4		73.7

Savings Plans

Integrys maintains a 401(k) Savings Plan for substantially all of our full-time employees. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution up to certain limits. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. Certain employees participate in a defined contribution pension plan, in which certain amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Our share of the total costs incurred under all of these plans was $9.7 million in 2015, $8.6 million in 2014, and $8.2 million in 2013.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

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

Energy Related Purchased Power Agreements

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

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

				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2016		2017		2018		2019		2020		Later Years
Electric utility:
Purchased power	2027	$	732.6	$	85.5	$	53.5	$	56.2	$	57.5	$	59.8	$	420.1
Coal supply and transportation	2019	198.4		97.3		46.5		43.5		11.1		—		—
Natural gas utility supply and transportation	2024	198.1		43.8		42.9		42.4		27.1		14.6		27.3
Total		$	1,129.1	$	226.6	$	142.9	$	142.1	$	95.7	$	74.4	$	447.4

Operating Leases

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

Rental expense attributable to operating leases was $1.4 million, $1.6 million, and $2.3 million in 2015, 2014, and 2013, respectively.

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

Year Ending December 31	Payments (in millions)
2016	$	0.4
2017	0.8
2018	0.6
2019	0.4
2020	0.5
Later years	12.3
Total	$	15.0

Environmental Matters

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

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

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

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

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

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

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

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

• the remediation of former manufactured gas plant sites.

Air Quality

Sulfur Dioxide National Air Ambient Quality Standards

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

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

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO₂. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016.

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

8-Hour Ozone National Air Ambient Quality Standards

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

Mercury and Other Hazardous Air Pollutants

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

Our compliance plans currently include capital projects for our jointly owned plants to achieve the required reductions for MATS. Construction of the ReACT^TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date of July 2016. Controls for acid gases and mercury are already in operation at the Pulliam units.

Although we received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is shut down to complete the construction of the ReACT^TM system.

Climate Change

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

Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO₂ equivalent reduction goal by about 10%. The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule.

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

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, we reported aggregated CO₂ equivalent emissions of approximately 6.2 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 5.7 million metric tonnes to the EPA for 2015. The level of CO₂ and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2014, we reported aggregated CO₂ equivalent emissions of approximately 3.9 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 3.5 million metric tonnes to the EPA for 2015.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8 and Weston Units 2 through 4. 

During 2016-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Entrainment studies are currently being conducted at Pulliam Units 7 and 8.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin. Unless pending challenges to the final guidelines are successful, the WDNR will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Pulliam Units 7 and 8 and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $10 million to $20 million for these bottom ash transport systems.

Land Quality

Coal Combustion Residuals Rule

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

Coal Combustion Product Landfill Sites

We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015, 2014, and 2013, landfill remediation expenses were not material. See Note 9, Asset Retirement Obligations, for more information about obligations related to these sites.

Renewables, Efficiency, and Conservation

Wisconsin Act 141

In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we are required to increase our renewable energy percentage to 9.74%. To comply with these requirements, we constructed the Crane Creek wind park. We also rely on renewable energy purchases to meet our renewable portfolio standard commitments.

We are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, that should allow us to remain in compliance through 2023. If market conditions are favorable, we may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of our annual operating revenues.

Manufactured Gas Plant Remediation

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

In addition, some of these sites are coordinating the investigation and cleanup subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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

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

(in millions)	2015		2014
Regulatory assets	$	104.4	$	102.3
Reserves for future remediation	83.5		86.3

Enforcement and Litigation Matters

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

Weston Title V Air Permit

In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, we challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The administrative law judge (ALJ) dismissed some of the petition issues relating to the averaging period and monitoring issues.

In May 2014, the WDNR issued a Notice of Violation (NOV) alleging that we failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler.

In June 2015, the WDNR issued a NOV alleging that we failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied our request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV.

The contested case has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.

Consent Decrees

Consent Decree – Weston and Pulliam

In November 2009, the EPA issued a NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. We entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the U.S. District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes:

• the installation of emission control technology, including ReACT™ on Weston 3,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects totaling $6.0 million, and

• a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023.

We received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. The majority of the beneficial environmental projects proposed by us have been approved by the EPA. We are currently working with the EPA on certain changes to the environmental projects, but these changes are not expected to materially impact the overall cost.

Also, in May 2010, we received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2015. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, Wisconsin Electric (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, Wisconsin Power and Light, Madison Gas and Electric, and Wisconsin Electric entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. The final Consent Decree includes:

• the installation of emission control technology, including scrubbers at the Columbia plant,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects, with our portion totaling $1.3 million, and

• Our portion of a civil penalty and legal fees totaling $0.4 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, or retire Edgewater Unit 4, of which we are a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available. All of the beneficial environmental projects that we proposed have been approved by the EPA.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.3	$	—	$	—	$	0.3
FTRs	—		—		2.0		2.0
Total derivative assets	$	0.3	$	—	$	2.0	$	2.3
Derivative liabilities
Natural gas contracts	$	0.9	$	—	$	—	$	0.9
Petroleum products contracts	0.5		—		—		0.5
Coal contracts	—		4.7		—		4.7
Total derivative liabilities	$	1.4	$	4.7	$	—	$	6.1

	December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	—	$	0.1	$	—	$	0.1
FTRs	—		—		2.2		2.2
Total derivative assets	$	—	$	0.1	$	2.2	$	2.3
Derivative liabilities
Natural gas contracts	$	2.2	$	—	$	—	$	2.2
FTRs	—		—		0.3		0.3
Petroleum products contracts	1.1		—		—		1.1
Coal contracts	—		1.2		2.2		3.4
Total derivative liabilities	$	3.3	$	1.2	$	2.5	$	7.0

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:

(in millions)	2015			2014			2013
Balance at the beginning of the period	$	(0.3	)	$	(1.3	)	$	(5.4	)
Realized and unrealized (losses) gains	(10.7		)	(1.0		)	3.3
Purchases	9.8			4.3			3.2
Sales	(0.1		)	—			(0.2		)
Settlements	(1.4		)	(3.5		)	(2.2		)
Net transfers out of level 3	4.7			1.2			—
Balance at the end of the period	$	2.0		$	(0.3	)	$	(1.3	)

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

Fair Value of Financial Instruments

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

	December 31, 2015				December 31, 2014
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,289.4	$	1,350.4	$	1,165.1	$	1,286.2
Long-term debt to parent, including current portion	2.9		3.0		5.4		5.7
Preferred stock *	—		—		51.2		52.0

* On November 13, 2015, we redeemed all of our outstanding shares of preferred stock. See Note 12, Preferred Stock, for more information.

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DERIVATIVE INSTRUMENTS

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:

		December 31, 2015				December 31, 2014
(in millions)	Balance Sheet Presentation	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Natural gas contracts	Other Current	$	0.3	$	0.9	$	0.1	$	2.1
Natural gas contracts	Other Long-term	—		—		—		0.1
Petroleum product contracts	Other Current	—		0.5		—		1.1
FTRs	Other Current	2.0		—		2.2		0.3
Coal contracts	Other Current	—		3.3		—		2.4
Coal contracts	Other Long-term	—		1.4		—		1.0
	Other Current	2.3		4.7		2.3		5.9
	Other Long-term	—		1.4		—		1.1
Total		$	2.3	$	6.1	$	2.3	$	7.0

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

	December 31, 2015				December 31, 2014				December 31, 2013
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas	22.9 Dth	$	(4.9	)	20.0 Dth	$	0.6		15.5 Dth	$	(0.8	)
Petroleum products	6.1 gallons	(1.7		)	5.3 gallons	(0.1		)	2.8 gallons	(0.1		)
FTRs	9.0 MWh	3.3			8.7 MWh	3.2			9.1 MWh	5.1
Total		$	(3.3	)		$	3.7			$	4.2

At December 31, 2015, and December 31, 2014, we had posted collateral of $17.6 million and $6.6 million, respectively, in our margin accounts.

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

	December 31, 2015						December 31, 2014
	Derivative			Derivative			Derivative			Derivative
(in millions)	Assets			Liabilities			Assets			Liabilities
Gross amount recognized on the balance sheet	$	2.3		$	6.1		$	2.3		$	7.0
Gross amount not offset on the balance sheet *	(0.3		)	(1.4		)	(0.4		)	(3.6		)
Net amount	$	2.0		$	4.7		$	1.9		$	3.4

* Includes cash collateral posted of $1.1 million and $3.2 million as of December 31, 2015 and December 31, 2014, respectively.

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REGULATORY ENVIRONMENT

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT

2016 Wisconsin Rate Order

In April 2015, we initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). Based on the order, the PSCW will continue to allow escrow treatment for ATC and MISO network transmission expenses, including any future SSR payments. This allows us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. In addition, the PSCW approved a deferral for ReACT™, which requires us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.

2015 Wisconsin Rate Order

In April 2014, we initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% ROE. The order also included a common equity component of 50.28%. The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014.

The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, we would have realized an electric rate decrease. In addition, we received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information. The PSCW is allowing us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window.

The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, we would have realized a retail natural gas rate increase.

2014 Wisconsin Rate Order

In March 2013, we initiated a rate proceeding with the PSCW. In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% ROE. The order also included a common equity component average of 50.14%. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 18, Commitments and Contingencies, for more information. Additionally, the order required us to terminate our existing decoupling mechanism, beginning January 1, 2014.

2013 Wisconsin Rate Order

In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW issued a final written order, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% ROE and a common equity component average of 51.61%. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that were recovered in 2014 rates. In addition, we were authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct CSAPR costs incurred through the end of 2012. Lastly, the order authorized us to switch from production tax credits to a Section 1603 Grant for the Crane Creek wind project.

A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers were subject to these caps.

2015 Michigan Rate Order

In October 2014, we initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.2% ROE and a common equity component average of 50.48%. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, we will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. We also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. Lastly, we will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

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SEGMENTS INFORMATION

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

SEGMENTS OF BUSINESS

SEGMENT INFORMATION

At December 31, 2015, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are our electric utility operations and the natural gas utility operations. The other segment includes non-utility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC. Operating income is used to measure segment profitability and to allocate resources to our businesses. All of our operations and assets are located within the United States. The table below presents information related to our reportable segments:

	Regulated Utilities
2015 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,187.8	$	295.5	$	1,483.3	$	—	$	—		$	1,483.3
Intersegment revenues	—		10.7		10.7		0.8		(11.5		)	—
Other operation and maintenance	424.3		69.6		493.9		0.3		(0.8		)	493.4
Depreciation and amortization	103.7		17.0		120.7		0.3		—			121.0
Operating income	194.0		34.0		228.0		0.1		—			228.1
Other income, net	15.6		0.4		16.0		9.6		—			25.6
Interest expense	43.0		10.2		53.2		0.3		—			53.5
Capital expenditures	319.4		51.6		371.0		—		—			371.0
Total assets	3,718.9		697.9		4,416.8		88.3		—			4,505.1
	Regulated Utilities
2014 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,223.7	$	459.9	$	1,683.6	$	—	$	—		$	1,683.6
Intersegment revenues	—		12.4		12.4		1.4		(13.8		)	—
Other operation and maintenance	425.8		73.5		499.3		0.4		—			499.7
Depreciation and amortization	100.5		16.2		116.7		0.6		(0.5		)	116.8
Operating income	204.8		52.4		257.2		0.4		—			257.6
Other income, net	11.7		0.6		12.3		12.9		—			25.2
Interest expense	45.1		10.2		55.3		2.1		—			57.4
Capital expenditures	272.7		49.3		322.0		—		—			322.0
Total assets	3,503.0		680.9		4,183.9		85.4		—			4,269.3
	Regulated Utilities
2013 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,243.0	$	337.5	$	1,580.5	$	—	$	—		$	1,580.5
Intersegment revenues	—		10.9		10.9		1.4		(12.3		)	—
Other operation and maintenance	405.0		65.1		470.1		0.3		—			470.4
Depreciation and amortization	93.7		15.6		109.3		0.6		(0.5		)	109.4
Operating income	189.5		50.0		239.5		0.5		—			240.0
Other income, net	9.9		0.2		10.1		13.4		—			23.5
Interest expense	33.0		8.5		41.5		2.2		—			43.7
Capital expenditures	590.3		37.4		627.7		—		—			627.7
Total assets	3,233.6		632.3		3,865.9		85.7		—			3,951.6

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QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION (Unaudited)

(in millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2015
Operating revenues	$	425.0	$	330.3	$	390.8	$	337.2	$	1,483.3
Operating income	69.9		44.2		88.5		25.5		228.1
Net income attributed to common shareholder	39.0		22.6		50.3		10.6		$	122.5
2014
Operating revenues	$	556.0	$	359.0	$	370.9	$	397.7	$	1,683.6
Operating income	87.4		36.3		77.7		56.2		257.6
Net income attributed to common shareholder	50.3		17.1		42.2		28.0		137.6

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

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NEW ACCOUNTING PRONOUNCEMENTS

12 Months Ended

Dec. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

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

Classification and Measurement of Financial Instruments

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

Leases

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

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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2015

Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

SCHEDULE II

WISCONSIN PUBLIC SERVICE CORPORATION

VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts (in millions)	Balance at Beginning of the Period		Expense (1)		Net Write-offs (2)			Balance at End of the Period
December 31, 2015	$	3.2	$	6.7	$	(7.4	)	$	2.5
December 31, 2014	$	2.5	$	7.3	$	(6.6	)	$	3.2
December 31, 2013	$	2.5	$	5.2	$	(5.2	)	$	2.5

⁽¹⁾  Net of recoveries.

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Nature of operations

On June 29, 2015, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group. See Note 2, Merger, for more information on the acquisition.

We are an electric and natural gas utility company that services customers in northeastern Wisconsin and Michigan's Upper Peninsula. We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates.

Consolidation

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

At December 31, 2015, we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities.

Investment

The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

Use of estimates

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

Reclassifications

As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below.

Statements of Income

• Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net.

• Payroll taxes of $8.3 million and $8.9 million for the years ended December 31, 2014 and 2013, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes.

• Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $5.9 million and $6.7 million for the years ended December 31, 2014 and 2013, respectively.

• Certain expenses in other operation and maintenance were reclassified to cost of sales, and depreciation and amortization. The amounts reclassified to other cost of sales were $3.1 million and $5.6 million for the years ended December 31, 2014 and 2013, respectively.

Balance Sheets

• Current regulatory assets of$1.4 millionand$23.6 millionwere reclassified to accounts receivable and long-term regulatory assets, respectively, at December 31, 2014.

• Current regulatory liabilities of$6.1 millionand$15.1 millionwere reclassified to other current liabilities and long-term regulatory liabilities, respectively, at December 31, 2014.

• During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $0.6 million and $8.8 million, previously reported as other current assets and other long-term assets, respectively, were reclassified to offset long-term debt on the December 31, 2014 balance sheet.

• During the fourth quarter of 2015, we also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $3.8 million, previously reported as a component of other current liabilities, to long-term deferred income tax liabilities on the December 31, 2014 balance sheet.

Statements of Cash Flows

• Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections.

Cash and cash equivalents

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

Revenues and customer receivables

We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers.

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

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

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

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

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

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

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

Inventories

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

Regulatory accounting

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

Property, plant, and equipment

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

We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense.

We record property, plant, and equipment at cost. Cost includes material, labor, and overhead. Utility property also includes AFUDC – Equity. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property, using depreciation rates approved by the applicable regulators.

AFUDC

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

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 7.92%, 8.08%, and 8.61% for 2015, 2014, and 2013, respectively. Our average AFUDC wholesale rates were 5.10%, 6.99%, and 2.64% for 2015, 2014, and 2013, respectively.

Emission allowances

We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers.

Goodwill

Goodwill is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performed its annual goodwill impairment test as of April 1, 2015. Interim impairment tests are performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value.

Asset retirement obligations

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

Environmental remediation costs

We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 18, Commitments and Contingencies, for more information.

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

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

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

Income taxes

We and our subsidiary are included in the consolidated United States income tax return filed by Integrys for all tax periods up to and including the tax year ended June 29, 2015. For all tax periods after June 29, 2015, we and our subsidiary are included within the WEC Energy Group consolidated return. Similarly, we and our subsidiary are party to a tax allocation arrangement with Integrys and its consolidated subsidiaries for all tax periods up to and including June 29, 2015, and are a party to a tax allocation arrangement with WEC Energy Group and its consolidated subsidiaries for tax periods ending after June 29, 2015.

Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.

We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.

We report interest and penalties accrued, related to income taxes, as a component of income tax expense in our income statements.

We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.

Guarantees

We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

Employee benefits

The costs of pension and OPEB are expensed over the periods during which employees render service. The benefit costs associated with employee benefit plans are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP.

Fair value

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

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

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

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

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

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

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input.

Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available. We recognize transfers at the value as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount for each such item approximates fair value. The fair values of long-term debt, including the current portion of long-term debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity.

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

Derivative instruments

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

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

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

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

Customer deposits and credit balances

When utility customers apply for new service, they may be required to provide a deposit for the service.

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Schedule of inventory

Our inventory as of December 31 consisted of:

(in millions)	2015		2014
Fossil fuel	$	76.4	$	48.9
Materials and supplies	40.5		39.2
Natural gas in storage	28.1		36.1
Total	$	145.0	$	124.2

Schedule of annual utility composite depreciation rates

Annual utility composite depreciation rates are shown below:

Annual Utility Composite Depreciation Rates	2015		2014		2013
Electric	2.70	%	2.73	%	2.79	%
Natural gas	2.15	%	2.17	%	2.19	%

Schedule of total AFUDC

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

(in millions)	2015		2014		2013
AFUDC – Debt	$	6.1	$	4.6	$	3.8
AFUDC – Equity	15.1		11.0		9.9

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MERGER (Tables)

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Severance expense by segment [Table Text Block]

The severance expense was recorded in the following segments:

(in millions)	2015
Electric utility segment	$	3.6
Natural gas utility segment	1.0
Total severance expense	$	4.6

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ACQUISITION (Tables)

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Schedule of assets acquired and liabilities assumed

The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(in millions)
Assets acquired (1)
Inventories – materials and supplies	$	3.0
Other current assets	0.4
Property, plant, and equipment	374.4
Other long-term assets (2)	15.6
Total assets acquired	$	393.4
Liabilities assumed
Accounts payable	$	1.8
Total liabilities assumed	$	1.8

⁽¹⁾  Relates to the electric utility segment.

⁽²⁾  Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information.

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RELATED PARTIES (Tables)

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Schedule of information summarizing other related party transactions

The table below includes information summarizing other transactions entered into with related parties:

(in millions)	December 31, 2015		December 31, 2014
Accounts receivable
Service provided to ATC	$	0.5	$	0.9
Notes payable *
Integrys	2.9		5.4
Accounts payable
Network transmission services from ATC	8.5		8.2
Liability related to income tax allocation
Integrys	5.4		6.1

* WPS Leasing, our consolidated subsidiary, has a note payable to Integrys. At December 31, 2015 and 2014, the current portion of the note payable was $2.9 million and $2.5 million, respectively.

Schedule of activity associated with related party transactions

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

(in millions)	2015		2014		2013
Electric transactions
Sales to UPPCO (1)	$	—	$	15.3	$	22.8
Sales to ITF (2)	—		0.1		—
Sales to Wisconsin Electric	0.1		—		—
Natural gas transactions
Sales to Wisconsin Electric	0.4		—		—
Sales to IES (3)	—		0.6		0.5
Purchases from IES (3)	—		2.5		0.9
Interest expense (4)
Integrys	0.3		0.5		0.5
Transactions with equity-method investees
Charges from ATC for network transmission services	101.3		99.0		98.4
Charges to ATC for services and construction	10.3		8.6		9.5
Purchases of energy from WRPC	3.8		3.7		3.7
Charges to WRPC for operations	1.1		1.4		0.9
Equity earnings from WPS Investments, LLC (5)	7.7		9.5		10.2
Sales of electricity to AMP Trillium, LLC (6)	0.1		—		—

⁽¹⁾  Integrys sold UPPCO in August 2014.

⁽²⁾  In February 2016, an agreement was entered into to sell ITF. This sale is scheduled to close in the first quarter of 2016.

⁽³⁾  Integrys sold IES's retail energy business in November 2014.

⁽⁴⁾  WPS Leasing has a note payable to Integrys.

⁽⁵⁾  WPS Investments, LLC is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015, we had an 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC.

⁽⁶⁾  In November 2015, ITF, an indirect wholly-owned subsidiary of Integrys, sold its ownership interest in AMP Trillium, LLC, a joint venture between ITF and AMP Americas, LLC. This joint venture owned and operated compressed natural gas fueling stations.

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

(in millions)	2015		2014			2013
Cash paid for interest, net of amount capitalized	$	58.1	$	56.8		$	43.9
Cash paid (received) for income taxes, net of refunds	14.5		(6.2		)	(27.3		)
Significant non-cash transactions:
Construction costs funded through accounts payable	70.5		54.0			37.3

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REGULATORY ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

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

(in millions)	2015		2014		See Note
Regulatory assets (1) (2)
Unrecognized pension and OPEB costs (3)	$	176.6	$	185.6	17
Environmental remediation costs (4)	104.4		103.8		18
Income tax related items (5)	40.8		32.7
Termination of a tolling agreement with Fox Energy Company LLC	39.1		44.6		3
Crane Creek production tax credits (6)	30.9		32.2
De Pere Energy Center (7)	19.0		21.4
Energy costs recoverable through rate adjustments (8)	12.0		12.6
Other	39.9		25.6
Total regulatory assets	$	462.7	$	458.5
Balance Sheet Presentation
Current assets (9)	$	0.2	$	1.4
Regulatory assets	462.5		457.1
Total regulatory assets	$	462.7	$	458.5

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

⁽²⁾  As of December 31, 2015, we had $21.0 million of regulatory assets not earning a return.

⁽³⁾  Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans.

⁽⁴⁾  As of December 31, 2015, we had not yet made cash expenditures for $83.5 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.

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

⁽⁶⁾  In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12-year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039.

⁽⁷⁾  Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023.

⁽⁸⁾  Represents energy costs that will be recovered from customers in the future.

⁽⁹⁾  Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets.

Schedule of Regulatory Liabilities

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

(in millions)	2015		2014		See Note
Regulatory liabilities
Removal costs (1)	$	243.7	$	243.9
Energy costs refundable through rate adjustments (2)	29.4		6.0
Crane Creek depreciation deferral (3)	8.3		8.7
Unrecognized pension and OPEB costs (4)	1.0		42.4		17
Decoupling	—		12.3		21
Other	11.2		11.2
Total regulatory liabilities	$	293.6	$	324.5
Balance Sheet Presentation
Other current liabilities	$	3.6	$	6.1
Regulatory liabilities	290.0		318.4
Total regulatory liabilities	$	293.6	$	324.5

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

⁽²⁾  Represents energy costs that will be refunded to customers in the future.

⁽³⁾  Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.

⁽⁴⁾   Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

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PROPERTY, PLANT, AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of property, plant, and equipment

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

(in millions)	2015		2014
Electric utility	$	3,722.8	$	3,587.4
Natural gas utility	818.4		773.1
Total utility plant	4,541.2		4,360.5
Less: Accumulated depreciation	1,559.6		1,495.9
Net	2,981.6		2,864.6
CWIP	434.2		248.7
Plant to be retired, net *	—		12.5
Net utility plant	3,415.8		3,125.8
Non-utility plant	8.9		15.2
Less: Accumulated depreciation	6.1		10.0
Net non-utility plant	2.8		5.2
Total property, plant, and equipment	$	3,418.6	$	3,131.0

* In connection with the Consent Decree with the EPA, we retired Weston 1 and Pulliam Units 5 and 6 on June 1, 2015. See Note 18, Commitments and Contingencies, for more information regarding the Consent Decree.

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JOINTLY OWNED UTILITY FACILITIES (Tables)

12 Months Ended

Dec. 31, 2015

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule of our share of significant jointly owned electric generating facilities

The amounts were as follows at December 31, 2015:

(in millions, except for percentages and MWs)	Weston 4			Columbia Energy Center Units 1 and 2			Edgewater Unit 4
Ownership	70.0		%	31.8		%	31.8		%
Our share of rated capacity (MWs) *	374.5			352.9			96.3
In-service date	2008			1975 and 1978			1969
Utility plant	$	591.5		$	404.6		$	47.6
Accumulated depreciation	$	(150.5	)	$	(122.6	)	$	(30.6	)
CWIP	$	5.9		$	23.4		$	0.4

* Based on expected capacity ratings for summer 2016. 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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ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of changes to asset retirement obligations

The following table shows changes to our AROs:

(in millions)	2015					2014					2013
Balance as of January 1	$	20.3				$	18.0				$	16.7
Accretion	1.2					1.0					0.9
Additions and revisions to estimated cash flows (1)	11.4			(1	)	1.5			(2	)	0.5
Liabilities settled	(0.2		)			(0.2		)			(0.1		)
Balance as of December 31	$	32.7				$	20.3				$	18.0

⁽¹⁾  An ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates.

⁽²⁾  We revised the AROs recorded for the asbestos at our electric generation facilities primarily due to changes in estimated settlement dates.

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GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of identifiable intangible assets other than goodwill

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets.

	December 31, 2015							December 31, 2014
(in millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	15.6	$	(7.5	)	$	8.1	$	15.6	$	(4.3	)	$	11.3
Unamortized intangible assets	0.4		—			0.4		—		—			—
Total intangible assets	$	16.0	$	(7.5	)	$	8.5	$	15.6	$	(4.3	)	$	11.3

* Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2015, was approximately three years.

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COMMON EQUITY (Tables)

12 Months Ended

Dec. 31, 2015

Stockholders' Equity Note [Abstract]

Schedule of stock-based compensation expense and the related deferred tax benefit recognized in income

The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31:

(in millions)	2015		2014		2013
Stock options	$	—	$	1.0	$	0.7
Performance stock rights	1.3		6.3		1.1
Restricted share units	3.5		3.8		3.4
Total stock-based compensation expense	$	4.8	$	11.1	$	5.2
Deferred income tax benefit	$	1.9	$	4.4	$	2.1

Summary of stock options, performance stock rights, and restricted share units activity

A summary of the activity for our stock-based compensation awards for the year ended December 31, 2015, is presented below:

	Stock Options		Performance Stock Rights		Restricted Stock Units
Outstanding as of January 1, 2015	5,714		13,937		70,544
Granted	—		—		30,174
Dividend equivalents	N/A		N/A		1,267
Transferred	—		—		(166	)
Exercised/Distributed/Vested and Released *	(2,752	)	(2,229	)	(28,428	)
Settled as a result of WEC Merger	(2,962	)	(21,263	)	(73,391	)
Adjustment for performance stock rights distributed or settled	N/A		9,555		N/A
Outstanding as of December 31, 2015	—		—		—

* The intrinsic value of restricted stock unit awards vested and released was $2.2 million. The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant.

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PREFERRED STOCK (Tables)

12 Months Ended

Dec. 31, 2015

Class of Stock Disclosures [Abstract]

Schedule of outstanding shares of preferred stock

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

2015	Shares Authorized	Shares Outstanding	Redemption Price Per Share	Total
$100 par value, Preferred Stock	1,000,000	—	N/A	N/A

2014 (in millions, except share and per share amounts)	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
$100 par value, Preferred Stock	1,000,000
5.00% Series		131,916	$	107.50	$	13.2
5.04% Series		29,983	102.81		3.0
5.08% Series		49,983	101.00		5.0
6.76% Series		150,000	103.35		15.0
6.88% Series		150,000	100.00		15.0
Total					$	51.2

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SHORT-TERM DEBT AND LINES OF CREDIT (Tables)

12 Months Ended

Dec. 31, 2015

Short-term Debt [Abstract]

Schedule of short-term borrowings

Our short-term borrowings and their corresponding weighted-average interest rates as of December 31 were as follows:

(in millions, except percentages)	2015		2014
Commercial paper
Amount outstanding at December 31	$	182.8	$	145.1
Average interest rate on amounts outstanding at December 31	0.66%		0.32		%
Average amount outstanding during the year *	$	145.0	$	43.3

* Based on daily outstanding balances during the year.

Schedule of revolving credit facilities and remaining available capacity

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

(in millions)	Maturity	2015
Revolving credit facility *	December 2016	$	250.0
Total short-term credit capacity		$	250.0
Less: commercial paper outstanding		182.8
Available capacity under existing agreement		$	67.2

* We plan to request approval from the PSCW to extend the maturity through December 2020.

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of all principal debt payment amounts related to bond maturities

A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to our parent, is as follows:

(in millions)	Payments
2016	$	—
2017	125.0
2018	250.0
2019	—
2020	—
Thereafter	925.0
Total	$	1,300.0

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of components of the provision for income tax expense

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

(in millions)	2015			2014			2013
Current tax expense	$	31.4		$	(6.1	)	$	2.1
Deferred income taxes, net	44.0			91.1			80.1
Investment tax credit, net	(0.4		)	(0.3		)	(0.3		)
Total income tax expense	$	75.0		$	84.7		$	81.9

Reconciliation of federal income taxes to the provision for income taxes reported in the income statement

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

	2015					2014					2013
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
Expected tax at statutory federal tax rates	$	70.1		35.0	%	$	78.9		35.0	%	$	76.9		35.0	%
State income taxes net of federal tax benefit	9.9			5.0		10.9			4.8		10.5			4.8
AFUDC – Equity	(5.3		)	(2.6	)	(3.8		)	(1.7	)	(3.5		)	(1.6	)
Other, net	0.3			0.1		(1.3		)	(0.5	)	(2.0		)	(0.9	)
Total income tax expense	$	75.0		37.5	%	$	84.7		37.6	%	$	81.9		37.3	%

Schedule of principal components of deferred income tax assets and liabilities recognized in the balance sheets

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

(in millions)	2015		2014
Total deferred tax assets	$	23.9	$	4.4
Deferred tax liabilities
Plant-related	639.1		591.0
Employee benefits and compensation	91.7		83.9
Regulatory deferrals	52.0		42.4
Other	15.2		13.0
Total deferred tax liabilities	798.0		730.3
Deferred tax liability, net	$	774.1	$	725.9

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GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2015

Guarantees [Abstract]

Schedule of outstanding guarantees

The following table shows our outstanding guarantees:

	Total Amounts Committed		Expiration
(in millions)	at December 31, 2015		Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	9.5	$	—	$	9.5	$	—
Surety bonds(2)	1.1		1.1		—		—
Other guarantee(3)	20.3		20.0		—		0.3
Total guarantees	$	30.9	$	21.1	$	9.5	$	0.3

⁽¹⁾  At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our balance sheets.

⁽²⁾  Primarily for obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

⁽³⁾  Consists of (a) $20.0 million not reflected on our balance sheet for an interconnection agreement between us and ATC and (b) $0.3 million reflected on our balance sheet related to workers compensation.

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Reconciliation of the changes in the plans' benefit obligations and fair value of assets

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

	Pension Costs						OPEB Costs
(in millions)	2015			2014			2015			2014
Change in benefit obligation
Obligation at January 1	$	791.8		$	717.5		$	252.5		$	292.7
Service cost	10.7			8.6			8.7			7.7
Interest cost	31.7			34.4			10.4			11.5
Plan amendments	—			—			—			(74.4		)
Transfer to affiliates *	(130.5		)	(12.1		)	—			—
Actuarial loss (gain), net	(36.4		)	73.0			(31.7		)	24.0
Participant contributions	—			—			0.3			0.5
Benefit payments	(33.3		)	(29.6		)	(8.6		)	(10.4		)
Federal subsidy on benefits paid	—			—			—			0.9
Plan curtailment	(0.1		)	$	—		—			$	—
Obligation at December 31	$	633.9		$	791.8		$	231.6		$	252.5
Change in fair value of plan assets
Fair value of plan assets at January 1	$	897.4		$	839.1		$	236.6		$	236.5
Actual return on plan assets	(29.4		)	53.1			(5.1		)	7.4
Employer contributions	1.1			46.9			1.3			2.6
Participant contributions	—			—			0.3			0.5
Benefit payments	(33.3		)	(29.6		)	(8.6		)	(10.4		)
Transfer to affiliates *	(116.8		)	(12.1		)	—			—
Fair value at December 31	$	719.0		$	897.4		$	224.5		$	236.6

* Benefit obligations and plan assets were moved along with our employees who were transferred to affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries.

Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans

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

	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015			2014
Pension and other postretirement benefit assets	$	93.8	$	128.9	$	8.6		$	—
Current liabilities	—		1.5		—			0.1
Pension and other postretirement benefit liabilities	8.7		21.8		15.7			15.8
Total net assets (liabilities)	$	85.1	$	105.6	$	(7.1	)	$	(15.9	)

Information for pension plans with an accumulated benefit obligation in excess of plan assets

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)	2015		2014
Projected benefit obligation	$	8.7	$	23.3
Accumulated benefit obligation	8.5		21.5

Amounts that had not yet been recognized in the entity's net periodic benefit cost

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

	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015		2014
Net regulatory assets
Net actuarial loss	$	61.2	$	178.7	$	5.2	$	41.0
Prior service cost (credit)	—		1.8		—		(78.3		)
Total	$	61.2	$	180.5	$	5.2	$	(37.3	)

Schedule of the components of net periodic benefit cost

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

	Pension Costs									OPEB Costs
(in millions)	2015			2014			2013			2015			2014			2013
Service cost	$	10.7		$	8.6		$	10.8		$	8.7		$	7.7		$	10.6
Interest cost	31.7			34.4			30.6			10.4			11.5			13.4
Expected return on plan assets	(64.8		)	(64.1		)	(57.2		)	(16.0		)	(16.0		)	(14.8		)
Loss on plan settlement	0.1			0.4			—			—			—			—
Amortization of prior service cost (credit)	0.2			0.6			3.6			(9.3		)	(8.0		)	(2.1		)
Amortization of net actuarial loss	21.0			15.0			24.0			3.7			2.8			7.5
Net periodic benefit cost	$	(1.1	)	$	(5.1	)	$	11.8		$	(2.5	)	$	(2.0	)	$	14.6

Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans

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

	Pension		OPEB
	2015	2014	2015	2014
Discount rate	4.49%	4.08%	4.46%	4.11%
Rate of compensation increase	4.00%	4.23%	N/A	N/A
Assumed medical cost trend rate	N/A	N/A	7.50%	6.00%
Ultimate trend rate	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached	N/A	N/A	2021	2023

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

	Pension Costs
	2015	2014	2013
Discount rate	4.08%	4.92%	4.07%
Expected return on assets	7.75%	8.00%	8.00%
Rate of compensation increase	4.23%	4.25%	4.26%

	OPEB Costs
	2015	2014	2013
Discount rate	4.11%	4.78%	4.01%
Expected return on assets	7.75%	8.00%	8.00%
Assumed medical cost trend rate (Pre 65/Post 65)	6.00%	6.50%	7.00%
Ultimate trend rate	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2023	2019	2019

Effects of a one-percentage-point change in assumed health care cost trend rates

For the year ended December 31, 2015, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:

(in millions)	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	3.8	$	(2.9	)
Effect on the health care component of the accumulated postretirement benefit obligation	31.9		(25.7		)

Investments recorded at fair value, by asset class

The following tables provide the fair values of our investments by asset class:

	December 31, 2015
	Pension Plan Assets											OPEB Assets
(in millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset class
Cash and cash equivalents	$	—		$	27.4		$	—	$	27.4		$	4.6	$	1.0	$	—	$	5.6
Equity securities:
U.S. Equity	39.2			162.2			—		201.4			11.9		60.0		—		71.9
International Equity	40.3			179.3			—		219.6			15.5		58.5		—		74.0
Fixed income securities: (1)
U.S. Bonds	6.3			218.3			—		224.6			65.1		—		—		65.1
International Bonds	—			55.9			—		55.9			—		—		—		—
	85.8			643.1			—		728.9			97.1		119.5		—		216.6
401(h) other benefit plan assets invested as pension assets (2)	(0.9		)	(7.2		)	—		(8.1		)	0.9		7.2		—		8.1
Total (3)	$	84.9		$	635.9		$	—	$	720.8		$	98.0	$	126.7	$	—	$	224.7

⁽¹⁾  This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

⁽²⁾  Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

⁽³⁾  Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

	December 31, 2014
	Pension Plan Assets											OPEB Assets
(in millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset class
Cash and cash equivalents	$	0.3		$	25.3		$	—	$	25.6		$	3.4	$	1.5			$	4.9
Equity securities:
U.S. Equity	53.3			197.8			—		251.1			14.6		62.4				77.0
International Equity	54.4			225.9			—		280.3			17.6		65.5				83.1
Fixed income securities: (1)
U.S. Bonds	41.3			261.8			—		303.1			62.8		—				62.8
International Bonds	—			44.6			—		44.6			—		—				—
	149.3			755.4			—		904.7			98.4		129.4		—		227.8
401(h) other benefit plan assets invested as pension assets (2)	(1.5		)	(7.3		)	—		(8.8		)	1.5		7.3		—		8.8
Total (3)	$	147.8		$	748.1		$	—	$	895.9		$	99.9	$	136.7	$	—	$	236.6

⁽¹⁾  This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

⁽²⁾  Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

⁽³⁾  Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

Reconciliation of changes in the fair value of pension assets categorized as Level 3 measurements

The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2014. There was no level 3 activity in 2015.

(in millions)	International Bonds			U.S. Bonds			Total
Beginning balance at January 1, 2014	$	1.3		$	0.7		$	2.0
Net realized and unrealized gains	0.1			0.1			0.2
Sales	(1.4		)	(0.8		)	(2.2		)
Ending balance at December 31, 2014	$	—		$	—		$	—

Schedule of expected future benefit payments

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

(in millions)	Pension Costs		OPEB Costs
2016	$	46.9	$	9.6
2017	29.6		10.5
2018	29.1		11.4
2019	32.6		12.2
2020	33.7		13.0
2021-2025	172.4		73.7

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of minimum future commitments related to purchase obligations

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

				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2016		2017		2018		2019		2020		Later Years
Electric utility:
Purchased power	2027	$	732.6	$	85.5	$	53.5	$	56.2	$	57.5	$	59.8	$	420.1
Coal supply and transportation	2019	198.4		97.3		46.5		43.5		11.1		—		—
Natural gas utility supply and transportation	2024	198.1		43.8		42.9		42.4		27.1		14.6		27.3
Total		$	1,129.1	$	226.6	$	142.9	$	142.1	$	95.7	$	74.4	$	447.4

Schedule of minimum future payments under noncancelable operating leases

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

Year Ending December 31	Payments (in millions)
2016	$	0.4
2017	0.8
2018	0.6
2019	0.4
2020	0.5
Later years	12.3
Total	$	15.0

Schedule of regulatory assets and reserves related to manufactured gas plants

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

(in millions)	2015		2014
Regulatory assets	$	104.4	$	102.3
Reserves for future remediation	83.5		86.3

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy

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

	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.3	$	—	$	—	$	0.3
FTRs	—		—		2.0		2.0
Total derivative assets	$	0.3	$	—	$	2.0	$	2.3
Derivative liabilities
Natural gas contracts	$	0.9	$	—	$	—	$	0.9
Petroleum products contracts	0.5		—		—		0.5
Coal contracts	—		4.7		—		4.7
Total derivative liabilities	$	1.4	$	4.7	$	—	$	6.1

	December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	—	$	0.1	$	—	$	0.1
FTRs	—		—		2.2		2.2
Total derivative assets	$	—	$	0.1	$	2.2	$	2.3
Derivative liabilities
Natural gas contracts	$	2.2	$	—	$	—	$	2.2
FTRs	—		—		0.3		0.3
Petroleum products contracts	1.1		—		—		1.1
Coal contracts	—		1.2		2.2		3.4
Total derivative liabilities	$	3.3	$	1.2	$	2.5	$	7.0

Reconciliation of changes in the fair value of items categorized as Level 3 measurements

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:

(in millions)	2015			2014			2013
Balance at the beginning of the period	$	(0.3	)	$	(1.3	)	$	(5.4	)
Realized and unrealized (losses) gains	(10.7		)	(1.0		)	3.3
Purchases	9.8			4.3			3.2
Sales	(0.1		)	—			(0.2		)
Settlements	(1.4		)	(3.5		)	(2.2		)
Net transfers out of level 3	4.7			1.2			—
Balance at the end of the period	$	2.0		$	(0.3	)	$	(1.3	)

Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value

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

	December 31, 2015				December 31, 2014
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,289.4	$	1,350.4	$	1,165.1	$	1,286.2
Long-term debt to parent, including current portion	2.9		3.0		5.4		5.7
Preferred stock *	—		—		51.2		52.0

* On November 13, 2015, we redeemed all of our outstanding shares of preferred stock. See Note 12, Preferred Stock, for more information.

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DERIVATIVE INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative assets and derivative liabilities

The following table shows our derivative assets and derivative liabilities:

		December 31, 2015				December 31, 2014
(in millions)	Balance Sheet Presentation	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Natural gas contracts	Other Current	$	0.3	$	0.9	$	0.1	$	2.1
Natural gas contracts	Other Long-term	—		—		—		0.1
Petroleum product contracts	Other Current	—		0.5		—		1.1
FTRs	Other Current	2.0		—		2.2		0.3
Coal contracts	Other Current	—		3.3		—		2.4
Coal contracts	Other Long-term	—		1.4		—		1.0
	Other Current	2.3		4.7		2.3		5.9
	Other Long-term	—		1.4		—		1.1
Total		$	2.3	$	6.1	$	2.3	$	7.0

Estimated notional volumes and gains (losses)

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

	December 31, 2015				December 31, 2014				December 31, 2013
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)			Volume	Gains (Losses)
Natural gas	22.9 Dth	$	(4.9	)	20.0 Dth	$	0.6		15.5 Dth	$	(0.8	)
Petroleum products	6.1 gallons	(1.7		)	5.3 gallons	(0.1		)	2.8 gallons	(0.1		)
FTRs	9.0 MWh	3.3			8.7 MWh	3.2			9.1 MWh	5.1
Total		$	(3.3	)		$	3.7			$	4.2

Potential effect of netting arrangements for recognized derivative assets and liabilities

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

	December 31, 2015						December 31, 2014
	Derivative			Derivative			Derivative			Derivative
(in millions)	Assets			Liabilities			Assets			Liabilities
Gross amount recognized on the balance sheet	$	2.3		$	6.1		$	2.3		$	7.0
Gross amount not offset on the balance sheet *	(0.3		)	(1.4		)	(0.4		)	(3.6		)
Net amount	$	2.0		$	4.7		$	1.9		$	3.4

* Includes cash collateral posted of $1.1 million and $3.2 million as of December 31, 2015 and December 31, 2014, respectively.

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SEGMENTS INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of information related to reportable segments

The table below presents information related to our reportable segments:

	Regulated Utilities
2015 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,187.8	$	295.5	$	1,483.3	$	—	$	—		$	1,483.3
Intersegment revenues	—		10.7		10.7		0.8		(11.5		)	—
Other operation and maintenance	424.3		69.6		493.9		0.3		(0.8		)	493.4
Depreciation and amortization	103.7		17.0		120.7		0.3		—			121.0
Operating income	194.0		34.0		228.0		0.1		—			228.1
Other income, net	15.6		0.4		16.0		9.6		—			25.6
Interest expense	43.0		10.2		53.2		0.3		—			53.5
Capital expenditures	319.4		51.6		371.0		—		—			371.0
Total assets	3,718.9		697.9		4,416.8		88.3		—			4,505.1
	Regulated Utilities
2014 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,223.7	$	459.9	$	1,683.6	$	—	$	—		$	1,683.6
Intersegment revenues	—		12.4		12.4		1.4		(13.8		)	—
Other operation and maintenance	425.8		73.5		499.3		0.4		—			499.7
Depreciation and amortization	100.5		16.2		116.7		0.6		(0.5		)	116.8
Operating income	204.8		52.4		257.2		0.4		—			257.6
Other income, net	11.7		0.6		12.3		12.9		—			25.2
Interest expense	45.1		10.2		55.3		2.1		—			57.4
Capital expenditures	272.7		49.3		322.0		—		—			322.0
Total assets	3,503.0		680.9		4,183.9		85.4		—			4,269.3
	Regulated Utilities
2013 (in millions)	Electric Utility		Natural Gas Utility		Total Utility		Other		Reconciling Eliminations			WPS Consolidated
External revenues	$	1,243.0	$	337.5	$	1,580.5	$	—	$	—		$	1,580.5
Intersegment revenues	—		10.9		10.9		1.4		(12.3		)	—
Other operation and maintenance	405.0		65.1		470.1		0.3		—			470.4
Depreciation and amortization	93.7		15.6		109.3		0.6		(0.5		)	109.4
Operating income	189.5		50.0		239.5		0.5		—			240.0
Other income, net	9.9		0.2		10.1		13.4		—			23.5
Interest expense	33.0		8.5		41.5		2.2		—			43.7
Capital expenditures	590.3		37.4		627.7		—		—			627.7
Total assets	3,233.6		632.3		3,865.9		85.7		—			3,951.6

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QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of quarterly financial information (unaudited)

(in millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2015
Operating revenues	$	425.0	$	330.3	$	390.8	$	337.2	$	1,483.3
Operating income	69.9		44.2		88.5		25.5		228.1
Net income attributed to common shareholder	39.0		22.6		50.3		10.6		$	122.5
2014
Operating revenues	$	556.0	$	359.0	$	370.9	$	397.7	$	1,683.6
Operating income	87.4		36.3		77.7		56.2		257.6
Net income attributed to common shareholder	50.3		17.1		42.2		28.0		137.6

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL INFORMATION (Details)	Dec. 31, 2015
Accounting Policies [Abstract]
Number of wholly owned subsidiaries	1

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATIONS (Details) - Restatement Adjustment [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Statement Reclassification [Member]
Prior Period Income Statement Reclassification Payroll Taxes	$ 8.3	$ 8.9
Prior Period Income Statement Reclassification Cost Of Sales	5.9	6.7
Prior Period Income Statement Reclassification Other Operation and Maintenance	3.1	$ 5.6
Balance Sheet Reclassification [Member]
Prior Period Balance Sheet Reclassification Current Regulatory Assets Accounts Receivable	1.4
Prior Period Balance Sheet Reclassification Regulatory Assets Current Long Term	23.6
Prior Period Balance Sheet Reclassification Current Regulatory Liabilities Other Current Liabilities	6.1
Prior Period Balance Sheet Reclassification Regulatory Liabilities Current Long Term	15.1
Prior Period Balance Sheet Reclassification ASU 2015-03 Current	0.6
Prior Period Balance Sheet Reclassification ASU 2015-03 Long-Term	8.8
Prior Period Balance Sheet Reclassification ASU 2015-17	3.8
Cash Flow Statement Reclassification [Member]
Prior Period Cash Flow Statement Reclassifications	$ 0.0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details)	12 Months Ended
	Dec. 31, 2015
Cash and cash equivalents
Maximum maturity of short-term investments to classify instruments as cash equivalents	3 months

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES REVENUES AND CUSTOMER RECEIVABLES (Details)	12 Months Ended
	Dec. 31, 2015 customer
Revenues from external customers
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required	2.00%
Customer concentration risk
Revenues from external customers
Customers that account for more than 10% of revenues	0
Threshold percentage of revenues from major customers	10.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Fossil fuel	$ 76.4	$ 48.9
Materials and supplies	40.5	39.2
Natural gas in storage	28.1	36.1
Total	$ 145.0	$ 124.2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PROPERTY, PLANT, AND EQUIPMENT (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Software
Property, plant and equipment
Useful life	3 years
Electric
Property, plant and equipment
Annual utility composite depreciation rate (as a percent)	2.70%	2.73%	2.79%
Natural gas
Property, plant and equipment
Annual utility composite depreciation rate (as a percent)	2.15%	2.17%	2.19%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AFUDC
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC calculation	50.00%
Allowance for borrowed funds used during construction	$ 6.1	$ 4.6	$ 3.8
Allowance for equity funds used during construction	$ 15.1	$ 11.0	$ 9.9
Retail
AFUDC
Average AFUDC rate (as a percent)	7.92%	8.08%	8.61%
Wholesale
AFUDC
Average AFUDC rate (as a percent)	5.10%	6.99%	2.64%

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MERGER (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Merger
Severance expense	$ 4.6
Severance payments	4.3
Electric Utility
Merger
Severance expense	3.6
Natural Gas Utility
Merger
Severance expense	$ 1.0

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ACQUISITION (Details) $ in Millions		1 Months Ended	12 Months Ended
	Jan. 02, 2014	Mar. 31, 2013 USD ($) MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Acquisitions
Purchase price			$ 0.0	$ 0.0	$ 391.6
Fox Energy Company LLC
Acquisitions
Purchase price		$ 391.6
Capacity of Electric Generating Facility | MW		593
Assets acquired
Inventories - materials and supplies		$ 3.0
Other current assets		0.4
Property, plant, and equipment		374.4
Other long-term assets		15.6
Total assets acquired		393.4
Liabilities assumed
Accounts payable		1.8
Total liabilities assumed		$ 1.8
Contracted Capacity From Power Purchase Agreement | MW		500
Contract termination fee related to tolling arrangement		$ 50.0
Amortization Period of Regulatory Asset			9 years
Beginning of regulatory asset amortization period	Jan. 01, 2014

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RELATED PARTIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related parties
Notes payable to Integrys	$ 2.9	$ 5.4
Current portion of notes payable to Integrys	2.9	2.5
ATC
Related parties
Accounts receivable for services provided to ATC	0.5	0.9
Accounts payable to ATC for network transmission services	8.5	8.2
Charges from ATC for network transmission services	101.3	99.0	$ 98.4
Charges to equity method investee for services, construction, and/or operations	10.3	8.6	9.5
WRPC
Related parties
Purchases from related party	3.8	3.7	3.7
Charges to equity method investee for services, construction, and/or operations	1.1	1.4	0.9
WPS Investments, LLC
Related parties
Equity earnings from WPS Investments, LLC	$ 7.7	9.5	10.2
Equity method investment, ownership interest (as a percent)	10.83%
AMP Trillium LLC | Electric utility
Related parties
Sales to related party	$ 0.1	0.0	0.0
WBS
Related parties
Number of other significant changes from the Non-IBS affiliated interest agreement	0
Number of categories of services provided by WBS	15
Number of extensions available for affiliated interest agreement	1
Integrys
Related parties
Liability related to income tax allocation	$ 5.4	6.1
Integrys | WPS Leasing
Related parties
Notes payable to Integrys	2.9	5.4
Current portion of notes payable to Integrys	2.9	2.5
Interest expense related to notes payable with Integrys	0.3	0.5	0.5
UPPCO | Electric utility
Related parties
Sales to related party	0.0	15.3	22.8
ITF | Electric utility
Related parties
Sales to related party	0.0	0.1	0.0
Wisconsin Electric | Electric utility
Related parties
Sales to related party	0.1	0.0	0.0
Wisconsin Electric | Natural gas utility
Related parties
Sales to related party	0.4	0.0	0.0
IES | Natural gas utility
Related parties
Sales to related party	0.0	0.6	0.5
Purchases from related party	$ 0.0	$ 2.5	$ 0.9

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SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amount capitalized	$ 58.1	$ 56.8	$ 43.9
Cash paid for income taxes, net of refunds	14.5
Cash received for income taxes, net of refunds		(6.2)	(27.3)
Construction costs funded through accounts payable	$ 70.5	$ 54.0	$ 37.3

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REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory assets
Current assets	$ 0.2	$ 1.4
Long-term assets	462.5	457.1
Total regulatory assets	462.7	458.5
Other Disclosures
Regulatory assets not earning a return	21.0
Environmental remediation liabilities	83.5	86.3
Unrecognized pension and other postretirement benefit costs
Regulatory assets
Total regulatory assets	176.6	185.6
Environmental remediation costs
Regulatory assets
Total regulatory assets	104.4	103.8
Other Disclosures
Environmental remediation liabilities	83.5
Income tax related items
Regulatory assets
Total regulatory assets	40.8	32.7
Termination of a tolling agreement with Fox Energy Company LLC
Regulatory assets
Total regulatory assets	39.1	44.6
Crane Creek production tax credits
Regulatory assets
Total regulatory assets	$ 30.9	32.2
Other Disclosures
Period over which grant received will be reflected in income through reduction of depreciation and amortization expense	12 years
De Pere Energy Center
Regulatory assets
Total regulatory assets	$ 19.0	21.4
Energy costs recoverable through rate adjustments
Regulatory assets
Total regulatory assets	12.0	12.6
Other
Regulatory assets
Total regulatory assets	$ 39.9	$ 25.6

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REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities
Current liabilities	$ 3.6	$ 6.1
Long-term liabilities	290.0	318.4
Total regulatory liabilities	293.6	324.5
Removal costs
Regulatory Liabilities
Total regulatory liabilities	243.7	243.9
Energy costs refundable through rate adjustments
Regulatory Liabilities
Total regulatory liabilities	29.4	6.0
Crane Creek depreciation deferral
Regulatory Liabilities
Total regulatory liabilities	8.3	8.7
Unrecognized pension and other postretirement benefit costs
Regulatory Liabilities
Total regulatory liabilities	1.0	42.4
Decoupling
Regulatory Liabilities
Total regulatory liabilities	0.0	12.3
Other
Regulatory Liabilities
Total regulatory liabilities	$ 11.2	$ 11.2

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PROPERTY, PLANT, AND EQUIPMENT (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, plant and equipment
Less: Accumulated depreciation	$ 1,565.7	$ 1,542.5
Property, plant, and equipment, net	3,418.6	3,131.0
Utility operations
Property, plant and equipment
Property, plant, and equipment, gross	4,541.2	4,360.5
Less: Accumulated depreciation	1,559.6	1,495.9
Net property, plant, and equipment excluding construction work in progress	2,981.6	2,864.6
Construction work in progress	434.2	248.7
Plant to be retired, net	0.0	12.5
Property, plant, and equipment, net	3,415.8	3,125.8
Utility operations | Electric Utility
Property, plant and equipment
Property, plant, and equipment, gross	3,722.8	3,587.4
Utility operations | Natural Gas Utility
Property, plant and equipment
Property, plant, and equipment, gross	818.4	773.1
Nonutility operations | Other
Property, plant and equipment
Property, plant, and equipment, gross	8.9	15.2
Less: Accumulated depreciation	6.1	10.0
Property, plant, and equipment, net	$ 2.8	$ 5.2

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JOINTLY OWNED UTILITY FACILITIES (Details) $ in Millions	Dec. 31, 2015 USD ($) MW
Weston 4
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	70.00%
Our share of rated capacity (in megawatts) | MW	374.5
Utility plant	$ 591.5
Accumulated depreciation	(150.5)
Construction work in progress	$ 5.9
Columbia Energy Center Units 1 and 2
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	31.80%
Our share of rated capacity (in megawatts) | MW	352.9
Utility plant	$ 404.6
Accumulated depreciation	(122.6)
Construction work in progress	$ 23.4
Edgewater Unit 4
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	31.80%
Our share of rated capacity (in megawatts) | MW	96.3
Utility plant	$ 47.6
Accumulated depreciation	(30.6)
Construction work in progress	$ 0.4

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ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes to asset retirement obligations
Asset retirement obligations at beginning of period	$ 20.3	$ 18.0	$ 16.7
Accretion	1.2	1.0	0.9
Additions and Revisions to Estimated Cash Flows	11.4	1.5	0.5
Settlements	(0.2)	(0.2)	(0.1)
Asset retirement obligations at end of period	32.7	$ 20.3	$ 18.0
Hazardous and Solid Waste Management System Disposal of Coal Combustion Residuals [Member]
Changes to asset retirement obligations
AROs additions	$ 9.0

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GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Finite Lived And Indefinite Lived Intangible Assets [Line Items]
Changes in the carrying amount of goodwill	$ 0.0	$ 0.0
Goodwill impairment loss	0.0
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Contractual service agreements, accumulated amortization	(7.5)	(4.3)
Indefinite-Lived Intangible Assets (Excluding Goodwill)	0.4	0.0
Intangible Assets, Gross (Excluding Goodwill)	16.0	15.6
Intangible Assets, Net (Excluding Goodwill)	8.5	11.3
Contractual service agreements
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Contractual service agreements, gross carrying amount	15.6	15.6
Contractual service agreements, accumulated amortization	(7.5)	(4.3)
Contractual service agreements, net carrying amount	$ 8.1	$ 11.3
Weighted-average amortization period	3 years

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COMMON EQUITY - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 4.8	$ 11.1	$ 5.2
Deferred Income Tax Benefit	1.9	4.4	2.1
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0.0	1.0	0.7
Performance Stock Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of awards canceled due to WEC merger	1.5
Allocated Share-based Compensation Expense	1.3	6.3	1.1
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of awards canceled due to WEC merger	5.2
Allocated Share-based Compensation Expense	$ 3.5	$ 3.8	$ 3.4

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COMMON EQUITY - STOCK-BASED COMPENSATION UNITS ROLLFORWARD (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) shares
Stock Options
Stock Options [Roll Forward]
Outstanding, at the beginning of the period (in shares)	5,714
Granted (in shares)	0
Transferred (in shares)	0
Exercised (in shares)	(2,752)
Stock options settled due to WEC merger	(2,962)
Outstanding, at the end of the periods (in shares)	0
Performance Stock Rights
Performance Stock Rights and Restricted Stock Units [Roll Forward]
Outstanding at the beginning of the period (in shares)	13,937
Granted (in shares)	0
Transferred (in shares)	0
Distributed (in shares)	(2,229)
Awards settled due to WEC merger	(21,263)
Adjustment for performance stock rights distributed or settled	9,555
Outstanding at the end of the period (in shares)	0
Restricted Stock Units
Performance Stock Rights and Restricted Stock Units [Roll Forward]
Outstanding at the beginning of the period (in shares)	70,544
Granted (in shares)	30,174
Dividend equivalents (in shares)	1,267
Transferred (in shares)	(166)
Vested and released (in shares)	(28,428)
Awards settled due to WEC merger	(73,391)
Outstanding at the end of the period (in shares)	0
Intrinsic value of restricted stock units vested and released | $	$ 2.2

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COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Dividend Payment Restrictions
Retained Earnings, Appropriated	$ 528.5
Retained Earnings, Undistributed Earnings from Equity Method Investees	$ 32.3
Public Service Commission of Wisconsin (PSCW)
Dividend Payment Restrictions
Common equity ratio required to be maintained (as a percent)	51.00%

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PREFERRED STOCK (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2015	Dec. 31, 2014	Dec. 31, 2015	Nov. 13, 2015
Preferred stock
Par value (in dollars per share)		$ 100	$ 100
Authorized shares		1,000,000	1,000,000
Shares outstanding		511,882	0
Carrying value		$ 51.2	$ 0.0
Mandatorily redeemable shares				511,882
Preferred Stock Redemption Price				$ 52.7
5.00% preferred stock series
Preferred stock
Series (as a percent)	5.00%	5.00%
Shares outstanding		131,916
Preferred Stock, Redemption Price Per Share		$ 107.50
Carrying value		$ 13.2
Mandatorily redeemable shares				131,916
5.04% preferred stock series
Preferred stock
Series (as a percent)	5.04%	5.04%
Shares outstanding		29,983
Preferred Stock, Redemption Price Per Share		$ 102.81
Carrying value		$ 3.0
Mandatorily redeemable shares				29,983
5.08% preferred stock series
Preferred stock
Series (as a percent)	5.08%	5.08%
Shares outstanding		49,983
Preferred Stock, Redemption Price Per Share		$ 101.00
Carrying value		$ 5.0
Mandatorily redeemable shares				49,983
6.76% preferred stock series
Preferred stock
Series (as a percent)	6.76%	6.76%
Shares outstanding		150,000
Preferred Stock, Redemption Price Per Share		$ 103.35
Carrying value		$ 15.0
Mandatorily redeemable shares				150,000
6.88% preferred stock series
Preferred stock
Series (as a percent)	6.88%	6.88%
Shares outstanding		150,000
Preferred Stock, Redemption Price Per Share		$ 100.00
Carrying value		$ 15.0
Mandatorily redeemable shares				150,000

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SHORT-TERM DEBT AND LINES OF CREDIT OUTSTANDING (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Short-term borrowings
Short-term borrowings outstanding	$ 182.8	$ 145.1
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	$ 182.8	$ 145.1
Average interest rate on amounts outstanding (as a percent)	0.66%	0.32%
Average amount of short-term borrowings outstanding during the year	$ 145.0	$ 43.3

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SHORT-TERM DEBT AND LINES OF CREDIT CAPACITY (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) extension	Dec. 31, 2014 USD ($)
Short-term borrowings
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
Total short-term credit capacity	$ 250.0
Short-term borrowings outstanding	182.8	$ 145.1
Available capacity under existing agreements	67.2
Revolving credit facility maturing in December 2016 [Member]
Short-term borrowings
Total short-term credit capacity	$ 250.0
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	$ 182.8	$ 145.1

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LONG-TERM DEBT (Details) - USD ($) $ in Millions	1 Months Ended
	Dec. 31, 2015	Dec. 01, 2015	Nov. 30, 2015	Dec. 31, 2014
Long-term Debt, Fiscal Year Maturity
2016	$ 0.0
2017	125.0
2018	250.0
2019	0.0
2020	0.0
Later Years	925.0
Total	1,300.0			$ 1,175.1
Senior Notes 6.375 Percent, Due 2015
Long-term debt
Repayments of Debt	$ 125.0
Long Term Debt 1.65% Series, Due 2018
Long-term debt
Interest rate stated percentage	1.65%	1.65%
Proceeds from Issuance of Debt	$ 250.0
Long Term debt, 7.125% Series, Year Due, 2023
Long-term debt
First Mortgage Bonds	$ 0.0		$ 0.1	$ 0.1
Debt redemption price (percent)			100.00%
Interest rate stated percentage	7.125%
Senior Notes 6.375 Percent, Due 2015
Long-term debt
Repayments of Debt	$ 125.0
Interest rate stated percentage		6.375%

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INCOME TAXES INCOME TAXES PROVISION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Provision for income taxes
Total current provision	$ 31.4	$ (6.1)	$ 2.1
Total deferred provision	44.0	91.1	80.1
Investment tax credits	(0.4)	(0.3)	(0.3)
Income tax expense	$ 75.0	$ 84.7	$ 81.9

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INCOME TAXES RECONCILIATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement
Statutory federal income tax	$ 70,100,000	$ 78,900,000	$ 76,900,000
State income taxes, net	9,900,000	10,900,000	10,500,000
Income Tax Reconciliation Allowance For Funds Used During Construction Capitalized Cost Of Equity	(5,300,000)	(3,800,000)	(3,500,000)
Other differences, net	300,000	(1,300,000)	(2,000,000)
Income tax expense	$ 75,000,000	$ 84,700,000	$ 81,900,000
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement (as a percent)
Statutory federal income tax rate (as a percent)	35.00%	35.00%	35.00%
State income tax rate, net (as a percent)	5.00%	4.80%	4.80%
Effective Income Tax Rate Reconciliation Allowance For Funds Used During Construction Capitalized Cost Of Equity	(2.60%)	(1.70%)	(1.60%)
Other differences, net (as a percent)	0.10%	(0.50%)	(0.90%)
Effective income tax rate (as a percent)	37.50%	37.60%	37.30%
Unrecognized tax benefits, additional disclosures
Balance at the end of the period	$ 0	$ 0
Accrued interest related to unrecognized tax benefits	0	0
Accrued penalties related to unrecognized tax benefits	$ 0	$ 0.0

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INCOME TAXES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income taxes
Unrecognized Tax Benefits	$ 0.0	$ 0.0
Deferred income tax assets
Total deferred income tax assets	23.9	4.4
Deferred income tax liabilities
Plant-related	639.1	591.0
Employee benefits	91.7	83.9
Regulatory deferrals	52.0	42.4
Other	15.2	13.0
Total deferred income tax liabilities	798.0	730.3
Balance sheet presentation
Total net deferred income tax liabilities	774.1	$ 725.9
Income taxes, additional disclosures
Deferred tax credit carryforwards of alternative minimum tax credits	2.0
Deferred tax credit carryforwards of general business credits	3.0
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$ 16.1
General business credits
Income taxes, additional disclosures
Carryback period of general business tax credits	1 year
Carryforward period of general business tax credits	20 years

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GUARANTEES (Details) $ in Millions	Dec. 31, 2015 USD ($)
Guarantor Obligations
Total guarantees	$ 30.9
Guarantees expiring in less than one year	21.1
Guarantees expiring in one to three years	9.5
Guarantees expiring in over one year	0.3
Standby Letters of Credit
Guarantor Obligations
Total guarantees	9.5
Guarantees expiring in less than one year	0.0
Guarantees expiring in one to three years	9.5
Guarantees expiring in over one year	0.0
Surety Bonds
Guarantor Obligations
Total guarantees	1.1
Guarantees expiring in less than one year	1.1
Guarantees expiring in one to three years	0.0
Guarantees expiring in over one year	0.0
Other guarantees
Guarantor Obligations
Total guarantees	20.3
Guarantees expiring in less than one year	20.0
Guarantees expiring in one to three years	0.0
Guarantees expiring in over one year	0.3
Indemnification Agreement
Guarantor Obligations
Liability related to workers compensation coverage	0.3
ATC [Member] | Other guarantees
Guarantor Obligations
Total guarantees	$ 20.0

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EMPLOYEE BENEFIT PLANS - CHANGE IN BENEFIT OBLIGATIONS AND PLAN ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	$ 102.4	$ 128.9
Long-term liabilities	24.4	37.6
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Fair value of plan assets	0.0
Pension Benefits
Change in benefit obligation
Obligation at January 1	791.8	717.5
Service cost	10.7	8.6	$ 10.8
Interest cost	31.7	34.4	30.6
Plan amendments	0.0	0.0
Transfer to affiliates	(130.5)	(12.1)
Actuarial loss (gain), net	(36.4)	73.0
Participant contributions	0.0	0.0
Benefit payments	(33.3)	(29.6)
Federal subsidy on benefits paid	0.0	0.0
Plan curtailments	(0.1)	0.0
Obligation at December 31	633.9	791.8	717.5
Change in fair value of plan assets
Fair value of plan assets at January 1	897.4	839.1
Actual return on plan assets	(29.4)	53.1
Employer contributions	1.1	46.9
Participant contributions	0.0	0.0
Benefit payments	(33.3)	(29.6)
Transfer to affiliates	(116.8)	(12.1)
Fair value of plan assets at December 31	719.0	897.4	839.1
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	93.8	128.9
Current liabilities	0.0	1.5
Long-term liabilities	8.7	21.8
Total net assets (liabilities)	85.1	105.6
Accumulated benefit obligation	569.6	717.4
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Projected benefit obligation	8.7	23.3
Accumulated benefit obligation	8.5	21.5
OPEB
Change in benefit obligation
Obligation at January 1	252.5	292.7
Service cost	8.7	7.7	10.6
Interest cost	10.4	11.5	13.4
Plan amendments	0.0	(74.4)
Transfer to affiliates	0.0	0.0
Actuarial loss (gain), net	(31.7)	24.0
Participant contributions	0.3	0.5
Benefit payments	(8.6)	(10.4)
Federal subsidy on benefits paid	0.0	0.9
Plan curtailments	0.0	0.0
Obligation at December 31	231.6	252.5	292.7
Change in fair value of plan assets
Fair value of plan assets at January 1	236.6	236.5
Actual return on plan assets	(5.1)	7.4
Employer contributions	1.3	2.6
Participant contributions	0.3	0.5
Benefit payments	(8.6)	(10.4)
Transfer to affiliates	0.0	0.0
Fair value of plan assets at December 31	224.5	236.6	$ 236.5
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	8.6	0.0
Current liabilities	0.0	0.1
Long-term liabilities	15.7	15.8
Total net assets (liabilities)	$ (7.1)	$ (15.9)

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EMPLOYEE BENEFIT PLANS - NET PERIODIC BENEFIT COST (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Net regulatory assets
Net actuarial losses	$ 61.2	$ 178.7
Prior service cost (credit)	0.0	1.8
Total	61.2	180.5
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	10.7	8.6	$ 10.8
Interest cost	31.7	34.4	30.6
Expected return on plan assets	(64.8)	(64.1)	(57.2)
Loss on plan settlement	0.1	0.4	0.0
Amortization of prior service cost (credit)	0.2	0.6	3.6
Amortization of net actuarial loss	21.0	15.0	24.0
Net periodic benefit cost	(1.1)	(5.1)	11.8
OPEB
Net regulatory assets
Net actuarial losses	5.2	41.0
Prior service cost (credit)	0.0	(78.3)
Total	5.2	(37.3)
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	8.7	7.7	10.6
Interest cost	10.4	11.5	13.4
Expected return on plan assets	(16.0)	(16.0)	(14.8)
Loss on plan settlement		0.0	0.0
Amortization of prior service cost (credit)	(9.3)	(8.0)	(2.1)
Amortization of net actuarial loss	3.7	2.8	7.5
Net periodic benefit cost	$ (2.5)	$ (2.0)	$ 14.6

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EMPLOYEE BENEFIT PLANS - ASSUMPTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Weighted average assumptions used
Discount rate	4.49%	4.08%
Rate of compensation increase	4.00%	4.23%
Discount rate	4.08%	4.92%	4.07%
Expected return on plan assets	7.75%	8.00%	8.00%
Rate of compensation increase	4.23%	4.25%	4.26%
Pension Benefits | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	60.00%	70.00%
Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	40.00%	30.00%
OPEB
Weighted average assumptions used
Discount rate	4.46%	4.11%
Assumed medical cost trend rate (as a percent)	7.50%	6.00%
Ultimate trend rate (as a percent)	5.00%	5.00%
Year ultimate trend rate is reached	2021	2023
Discount rate	4.11%	4.78%	4.01%
Expected return on plan assets	7.75%	8.00%	8.00%
Expected return on assets during next fiscal year	7.25%
Effects of a one-percentage-point change in assumed health care cost trend rates
Effect of one-percentage-point increase on total of service and interest cost components of net periodic postretirement health care benefit cost	$ 3.8
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(2.9)
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation	31.9
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation	$ (25.7)
OPEB | Under age 65
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	6.00%	6.50%	7.00%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2023	2019		2019
OPEB | Over age 65
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	6.00%	6.50%	7.00%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2023	2019		2019
OPEB | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	70.00%
OPEB | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	30.00%

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EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTRETIREMENT PLAN ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan Assets
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	$ 728.9	$ 904.7
401(h) other benefit plan assets invested as pension assets	(8.1)	(8.8)
Total	720.8	895.9
Pension Plan Assets | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	27.4	25.6
Pension Plan Assets | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	201.4	251.1
Pension Plan Assets | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	219.6	280.3
Pension Plan Assets | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	224.6	303.1
Pension Plan Assets | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	55.9	44.6
Pension Plan Assets | Level 1
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	85.8	149.3
401(h) other benefit plan assets invested as pension assets	(0.9)	(1.5)
Total	84.9	147.8
Pension Plan Assets | Level 1 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.3
Pension Plan Assets | Level 1 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	39.2	53.3
Pension Plan Assets | Level 1 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	40.3	54.4
Pension Plan Assets | Level 1 | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	6.3	41.3
Pension Plan Assets | Level 1 | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
Pension Plan Assets | Level 2
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	643.1	755.4
401(h) other benefit plan assets invested as pension assets	(7.2)	(7.3)
Total	635.9	748.1
Pension Plan Assets | Level 2 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	27.4	25.3
Pension Plan Assets | Level 2 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	162.2	197.8
Pension Plan Assets | Level 2 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	179.3	225.9
Pension Plan Assets | Level 2 | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	218.3	261.8
Pension Plan Assets | Level 2 | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	55.9	44.6
Pension Plan Assets | Level 3
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0	$ 2.0
401(h) other benefit plan assets invested as pension assets	0.0	0.0
Total	0.0	0.0
Pension Plan Assets | Level 3 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
Pension Plan Assets | Level 3 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
Pension Plan Assets | Level 3 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
Pension Plan Assets | Level 3 | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0	0.7
Pension Plan Assets | Level 3 | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0	$ 1.3
OPEB Plan Assets
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	216.6	227.8
401(h) other benefit plan assets invested as pension assets	8.1	8.8
Total	224.7	236.6
OPEB Plan Assets | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	5.6	4.9
OPEB Plan Assets | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	71.9	77.0
OPEB Plan Assets | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	74.0	83.1
OPEB Plan Assets | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	65.1	62.8
OPEB Plan Assets | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
OPEB Plan Assets | Level 1
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	97.1	98.4
401(h) other benefit plan assets invested as pension assets	0.9	1.5
Total	98.0	99.9
OPEB Plan Assets | Level 1 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	4.6	3.4
OPEB Plan Assets | Level 1 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	11.9	14.6
OPEB Plan Assets | Level 1 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	15.5	17.6
OPEB Plan Assets | Level 1 | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	65.1	62.8
OPEB Plan Assets | Level 1 | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
OPEB Plan Assets | Level 2
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	119.5	129.4
401(h) other benefit plan assets invested as pension assets	7.2	7.3
Total	126.7	136.7
OPEB Plan Assets | Level 2 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	1.0	1.5
OPEB Plan Assets | Level 2 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	60.0	62.4
OPEB Plan Assets | Level 2 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	58.5	65.5
OPEB Plan Assets | Level 2 | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
OPEB Plan Assets | Level 2 | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
OPEB Plan Assets | Level 3
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0	0.0
401(h) other benefit plan assets invested as pension assets	0.0	0.0
Total	0.0	$ 0.0
OPEB Plan Assets | Level 3 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0
OPEB Plan Assets | Level 3 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0
OPEB Plan Assets | Level 3 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0
OPEB Plan Assets | Level 3 | United States bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0.0
OPEB Plan Assets | Level 3 | International bonds
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	$ 0.0

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EMPLOYEE BENEFIT PLANS - CHANGES IN THE FAIR VALUE OF PLAN ASSETS (Details) - Pension Benefits - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	$ 904,700,000
Net realized and unrealized losses	(29,400,000)	$ 53,100,000
Ending balance at December 31	728,900,000	904,700,000
Level 3
Employee Benefit Plans
Defined benefit plan change in fair value	0
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0	2,000,000
Net realized and unrealized losses	200,000
Sales	(2,200,000)
Ending balance at December 31	0	0
International bonds
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	44,600,000
Ending balance at December 31	55,900,000	44,600,000
International bonds | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0	1,300,000
Net realized and unrealized losses	100,000
Sales	(1,400,000)
Ending balance at December 31	0	0
United States bonds
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	303,100,000
Ending balance at December 31	224,600,000	303,100,000
United States bonds | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0	700,000
Net realized and unrealized losses	100,000
Sales	(800,000)
Ending balance at December 31	$ 0	$ 0

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EMPLOYEE BENEFIT PLANS - DEFINED CONTRIBUTION BENEFIT PLANS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Contribution Benefit Plans
Total costs incurred for defined contribution benefit plans	$ 9.7	$ 8.6	$ 8.2
Pension Benefits
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	1.4
Expected payments, reflecting expected future service
2016	46.9
2017	29.6
2018	29.1
2019	32.6
2020	33.7
2021 through 2025	172.4
OPEB
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	2.1
Expected payments, reflecting expected future service
2016	9.6
2017	10.5
2018	11.4
2019	12.2
2020	13.0
2021 through 2025	$ 73.7

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COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Dec. 31, 2015 USD ($)
Minimum future commitments for purchase obligations
Total Amounts Committed	$ 1,129.1
2016	226.6
2017	142.9
2018	142.1
2019	95.7
2020	74.4
Later Years	447.4
Purchased power | Electric utility
Minimum future commitments for purchase obligations
Total Amounts Committed	732.6
2016	85.5
2017	53.5
2018	56.2
2019	57.5
2020	59.8
Later Years	420.1
Coal supply and transportation | Electric utility
Minimum future commitments for purchase obligations
Total Amounts Committed	198.4
2016	97.3
2017	46.5
2018	43.5
2019	11.1
2020	0.0
Later Years	0.0
Natural gas utility supply and transportation | Natural gas utility
Minimum future commitments for purchase obligations
Total Amounts Committed	198.1
2016	43.8
2017	42.9
2018	42.4
2019	27.1
2020	14.6
Later Years	$ 27.3

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COMMITMENTS AND CONTINGENCIES - OPERATING LEASES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Rental expense attributable to operating leases	$ 1.4	$ 1.6	$ 2.3
Minimum future payments under noncancelable operating leases
2016	0.4
2017	0.8
2018	0.6
2019	0.4
2020	0.5
Later years	12.3
Total	$ 15.0

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COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions	1 Months Ended				12 Months Ended
	Jan. 31, 2016 USD ($)	Aug. 31, 2014	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2015 USD ($) T	Dec. 31, 2014 USD ($) T	Jun. 01, 2015 USD ($)
Natural gas utility
Manufactured Gas Plant Remediation
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites					$ 83.5	$ 86.3
Mercury and other hazardous air pollutants | Electric utility
Air Quality
Percentage mercury emission reduction required by the State of Wisconsin's mercury rule					90.00%
Term of MATS compliance extension					1 year
Climate Change | Electric utility
Air Quality
Percentage greenhouse gas emission reduction nationwide					32.00%
Percentage greenhouse gas emission reduction for retirement of a nuclear plant					10.00%
Carbon dioxide emissions | T					5.7	6.2
Climate Change | Natural gas utility
Air Quality
Carbon dioxide emissions | T					3.5	3.9
Clean Water Act Cooling Water Intake Structure Rule | Electric utility
Water Quality
Number of compliance options available to meet standard		7
Steam Electric Effluent Guidelines | Electric utility | Subsequent event
Water Quality
Renewal period for facility permits	5 years
Steam Electric Effluent Guidelines | Electric utility | Minimum | Subsequent event
Water Quality
Expected environmental costs to achieve required emission reductions	$ 10.0
Steam Electric Effluent Guidelines | Electric utility | Maximum | Subsequent event
Water Quality
Expected environmental costs to achieve required emission reductions	$ 20.0
Renewables, efficiency, and conservation | Electric utility
Renewables, Efficiency, and Conservation
Percent goal of electricity consumption					10.00%
Renewable energy percent required					9.74%
Percent of annual operating revenues					1.20%
Manufactured gas plant remediation | Natural gas utility
Manufactured Gas Plant Remediation
Regulatory assets recorded for cash and estimated future remediation expenditures					$ 104.4	$ 102.3
Weston and Pulliam Consent Decree | Electric utility
Consent Decrees
Beneficial environmental project amount				$ 6.0
Civil penalty				$ 1.2
Regulatory asset for undepreciated book value of retired plants							$ 11.5
Joint Ownership Power Plants Consent Decree - Columbia and Edgewater | Electric utility
Consent Decrees
Beneficial environmental project amount			$ 1.3
Civil penalty			$ 0.4
WISCONSIN | Climate Change | Electric utility
Air Quality
Percentage greenhouse gas emission reduction Wisconsin					41.00%

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FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Derivative Asset	$ 2.3	$ 2.3
Liabilities
Derivative Liability	6.1	7.0
Fair value measurements on a recurring basis | Level 1
Assets
Derivative Asset	0.3	0.0
Liabilities
Derivative Liability	1.4	3.3
Fair value measurements on a recurring basis | Level 2
Assets
Derivative Asset	0.0	0.1
Liabilities
Derivative Liability	4.7	1.2
Fair value measurements on a recurring basis | Level 3
Assets
Derivative Asset	2.0	2.2
Liabilities
Derivative Liability	0.0	2.5
Fair value measurements on a recurring basis | Total
Assets
Derivative Asset	2.3	2.3
Liabilities
Derivative Liability	6.1	7.0
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative Asset	0.3	0.0
Liabilities
Derivative Liability	0.9	2.2
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative Asset	0.0	0.1
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative Asset	0.0	0.0
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Natural gas contracts | Total
Assets
Derivative Asset	0.3	0.1
Liabilities
Derivative Liability	0.9	2.2
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative Asset	0.0	0.0
Liabilities
Derivative Liability		0.0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative Asset	0.0	0.0
Liabilities
Derivative Liability		0.0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative Asset	2.0	2.2
Liabilities
Derivative Liability		0.3
Fair value measurements on a recurring basis | FTRs | Total
Assets
Derivative Asset	2.0	2.2
Liabilities
Derivative Liability		0.3
Fair value measurements on a recurring basis | Petroleum product contracts | Level 1
Liabilities
Derivative Liability	0.5	1.1
Fair value measurements on a recurring basis | Petroleum product contracts | Level 2
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Petroleum product contracts | Level 3
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Petroleum product contracts | Total
Liabilities
Derivative Liability	0.5	1.1
Fair value measurements on a recurring basis | Coal contracts | Level 1
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Liabilities
Derivative Liability	4.7	1.2
Fair value measurements on a recurring basis | Coal contracts | Level 3
Liabilities
Derivative Liability	0.0	2.2
Fair value measurements on a recurring basis | Coal contracts | Total
Liabilities
Derivative Liability	$ 4.7	$ 3.4

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FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at the beginning of period	$ (0.3)	$ (1.3)	$ (5.4)
Net realized and unrealized gains (losses)	(10.7)	(1.0)	3.3
Purchases	9.8	4.3	3.2
Sales	(0.1)	0.0	(0.2)
Settlements	(1.4)	(3.5)	(2.2)
Net transfers out of Level 3	4.7	1.2	0.0
Balance at the end of the period	$ 2.0	$ (0.3)	$ (1.3)

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FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying value and estimated fair value of financial instruments
Long-term debt	$ 1,289.4	$ 1,165.1
Long-term debt to parent	2.9	5.4
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively	0.0	51.2
Carrying Amount
Carrying value and estimated fair value of financial instruments
Long-term debt	1,289.4	1,165.1
Long-term debt to parent	2.9	5.4
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively	0.0	51.2
Fair Value
Carrying value and estimated fair value of financial instruments
Long-term debt	1,350.4	1,286.2
Long-term debt to parent	3.0	5.7
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively	$ 0.0	$ 52.0

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DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Derivative Asset	$ 2.3	$ 2.3
Derivative Liability [Abstract]
Derivative Liability	6.1	7.0
Not Designated as Hedging Instrument
Derivative Asset [Abstract]
Other current derivative assets	2.3	2.3
Other long-term derivative assets	0.0	0.0
Derivative Asset	2.3	2.3
Derivative Liability [Abstract]
Other current liabilities from risk management activities	4.7	5.9
Other long-term liabilities from risk management activities	1.4	1.1
Derivative Liability	6.1	7.0
Not Designated as Hedging Instrument | Natural gas contracts
Derivative Asset [Abstract]
Other current derivative assets	0.3	0.1
Other long-term derivative assets	0.0	0.0
Derivative Liability [Abstract]
Other current liabilities from risk management activities	0.9	2.1
Other long-term liabilities from risk management activities	0.0	0.1
Not Designated as Hedging Instrument | FTRs
Derivative Asset [Abstract]
Other current derivative assets	2.0	2.2
Derivative Liability [Abstract]
Other current liabilities from risk management activities	0.0	0.3
Not Designated as Hedging Instrument | Petroleum product contracts
Derivative Asset [Abstract]
Other current derivative assets	0.0	0.0
Derivative Liability [Abstract]
Other current liabilities from risk management activities	0.5	1.1
Not Designated as Hedging Instrument | Coal contracts
Derivative Asset [Abstract]
Other current derivative assets	0.0	0.0
Other long-term derivative assets	0.0	0.0
Derivative Liability [Abstract]
Other current liabilities from risk management activities	3.3	2.4
Other long-term liabilities from risk management activities	$ 1.4	$ 1.0

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DERIVATIVE INSTRUMENTS - NOTIONAL VOLUMES/ GAINS AND LOSSES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Risk management activities
Gain (Loss)	$ (3.3)	$ 3.7	$ 4.2
Natural gas contracts
Risk management activities
Volume Of Derivative Instruments	22.9 Dth	20.0 Dth	15.5 Dth
Gain (Loss)	$ (4.9)	$ 0.6	$ (0.8)
Petroleum product contracts
Risk management activities
Volume Of Derivative Instruments	6.1 gallons	5.3 gallons	2.8 gallons
Gain (Loss)	$ (1.7)	$ (0.1)	$ (0.1)
FTRs
Risk management activities
Volume Of Derivative Instruments	9.0 MWh	8.7 MWh	9.1 MWh
Gain (Loss)	$ 3.3	$ 3.2	$ 5.1

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DERIVATIVE INSTRUMENTS - NETTING ARRANGEMENTS AND CASH COLLATERAL (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Gross amount recognized on the balance sheet	$ 2.3	$ 2.3
Gross amount not offset on the balance sheet	(0.3)	(0.4)
Net Amount	2.0	1.9
Liabilities
Gross amount recognized on balance sheet	6.1	7.0
Gross amount not offset on balance sheet	(1.4)	(3.6)
Net Amount	4.7	3.4
Cash collateral
Cash Collateral	17.6	6.6
Cash collateral not offset	$ 1.1	$ 3.2

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REGULATORY ENVIRONMENT (Details) - USD ($) $ in Millions	1 Months Ended					12 Months Ended
	Dec. 31, 2015	Apr. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2015
Regulatory environment
Percent fuel costs can vary from the rate case approved costs before deferral is required						2.00%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates
Regulatory environment
Approved return on equity (as a percent)	10.00%
Approved common equity component average (as a percent)	51.00%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)	$ (7.9)
Approved annual rate increase (decrease), percentage	(0.80%)
Authorized revenue requirement for ReACT	$ 275.0
Percent fuel costs can vary from the rate case approved costs before deferral is required	2.00%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)	$ (6.2)
Approved annual rate increase (decrease), percentage	(2.10%)
Public Service Commission of Wisconsin (PSCW) | 2015 Rates
Regulatory environment
Approved return on equity (as a percent)			10.20%
Approved common equity component average (as a percent)			50.28%
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)			$ 24.6
Percent fuel costs can vary from the rate case approved costs before deferral is required			2.00%
Increase in cost of fuel for electric generation			$ 42.0
Year-over-year positive (negative) change in decoupling refunded to or collected from customers			9.0
Customer recoveries (refunds) related to decoupling			(4.0)
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)			15.4
Year-over-year positive (negative) change in decoupling refunded to or collected from customers			(16.0)
Customer recoveries (refunds) related to decoupling			(8.0)
Public Service Commission of Wisconsin (PSCW) | 2014 Rates
Regulatory environment
Approved return on equity (as a percent)				10.20%
Approved common equity component average (as a percent)				50.14%
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)				$ (12.8)
Customer recoveries (refunds) related to decoupling			(13.0)
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)				$ 4.0
Customer recoveries (refunds) related to decoupling			$ 8.0
Public Service Commission of Wisconsin (PSCW) | 2013 Rates
Regulatory environment
Approved return on equity (as a percent)					10.30%
Approved common equity component average (as a percent)					51.61%
Recovery of income tax amounts previously expensed due to the Federal Health Care Reform Act					$ 5.9
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)					28.5
Fuel refund					20.5
Deferral related to pension and other employee benefit costs					7.3
Annual decoupling mechanism cap					14.0
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)					(3.4)
Deferral related to pension and other employee benefit costs					2.1
Annual decoupling mechanism cap					$ 8.0
Michigan Public Service Commission (MPSC) | 2015 Rates | Electric rates
Regulatory environment
Approved return on equity (as a percent)		10.20%
Approved common equity component average (as a percent)		50.48%
Approved annual rate increase (decrease)		$ 4.0
Period of rate implementation		3 years

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SEGMENTS INFORMATION (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) segment	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Segment reporting information
Number of reportable segments | segment									3
Revenues	$ 337.2	$ 390.8	$ 330.3	$ 425.0	$ 397.7	$ 370.9	$ 359.0	$ 556.0	$ 1,483.3	$ 1,683.6	$ 1,580.5
Other operation and maintenance									493.4	499.7	470.4
Depreciation and amortization									121.0	116.8	109.4
Operating income	25.5	$ 88.5	$ 44.2	$ 69.9	56.2	$ 77.7	$ 36.3	$ 87.4	228.1	257.6	240.0
Other income, net									25.6	25.2	23.5
Interest expense									53.5	57.4	43.7
Capital expenditures									371.0	322.0	627.7
Total assets	4,505.1				4,269.3				4,505.1	4,269.3	3,951.6
Intersegment revenues
Segment reporting information
Revenues									0.0	0.0	0.0
Reconciling Eliminations
Segment reporting information
Revenues									0.0	0.0	0.0
Other operation and maintenance									(0.8)	0.0	0.0
Depreciation and amortization									0.0	(0.5)	(0.5)
Operating income									0.0	0.0	0.0
Other income, net									0.0	0.0	0.0
Interest expense									0.0	0.0	0.0
Capital expenditures									0.0	0.0	0.0
Total assets	0.0				0.0				0.0	0.0	0.0
Reconciling Eliminations | Intersegment revenues
Segment reporting information
Revenues									(11.5)	(13.8)	(12.3)
Utility operations
Segment reporting information
Revenues									1,483.3	1,683.6	1,580.5
Other operation and maintenance									493.9	499.3	470.1
Depreciation and amortization									120.7	116.7	109.3
Operating income									228.0	257.2	239.5
Other income, net									16.0	12.3	10.1
Interest expense									53.2	55.3	41.5
Capital expenditures									371.0	322.0	627.7
Total assets	4,416.8				4,183.9				4,416.8	4,183.9	3,865.9
Utility operations | Intersegment revenues
Segment reporting information
Revenues									10.7	12.4	10.9
Utility operations | Electric Utility
Segment reporting information
Revenues									1,187.8	1,223.7	1,243.0
Other operation and maintenance									424.3	425.8	405.0
Depreciation and amortization									103.7	100.5	93.7
Operating income									194.0	204.8	189.5
Other income, net									15.6	11.7	9.9
Interest expense									43.0	45.1	33.0
Capital expenditures									319.4	272.7	590.3
Total assets	3,718.9				3,503.0				3,718.9	3,503.0	3,233.6
Utility operations | Electric Utility | Intersegment revenues
Segment reporting information
Revenues									0.0	0.0	0.0
Utility operations | Natural Gas Utility
Segment reporting information
Revenues									295.5	459.9	337.5
Other operation and maintenance									69.6	73.5	65.1
Depreciation and amortization									17.0	16.2	15.6
Operating income									34.0	52.4	50.0
Other income, net									0.4	0.6	0.2
Interest expense									10.2	10.2	8.5
Capital expenditures									51.6	49.3	37.4
Total assets	697.9				680.9				697.9	680.9	632.3
Utility operations | Natural Gas Utility | Intersegment revenues
Segment reporting information
Revenues									10.7	12.4	10.9
Nonutility operations | Other
Segment reporting information
Revenues									0.0	0.0	0.0
Other operation and maintenance									0.3	0.4	0.3
Depreciation and amortization									0.3	0.6	0.6
Operating income									0.1	0.4	0.5
Other income, net									9.6	12.9	13.4
Interest expense									0.3	2.1	2.2
Capital expenditures									0.0	0.0	0.0
Total assets	$ 88.3				$ 85.4				88.3	85.4	85.7
Nonutility operations | Other | Intersegment revenues
Segment reporting information
Revenues									$ 0.8	$ 1.4	$ 1.4

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QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 337.2	$ 390.8	$ 330.3	$ 425.0	$ 397.7	$ 370.9	$ 359.0	$ 556.0	$ 1,483.3	$ 1,683.6	$ 1,580.5
Operating income	25.5	88.5	44.2	69.9	56.2	77.7	36.3	87.4	228.1	257.6	240.0
Net income attributed to common shareholder	$ 10.6	$ 50.3	$ 22.6	$ 39.0	$ 28.0	$ 42.2	$ 17.1	$ 50.3	$ 122.5	$ 137.6	$ 134.8

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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for doubtful accounts
Balance at beginning of year	$ 3.2	$ 2.5	$ 2.5
Charged to expense	6.7	7.3	5.2
Deductions	7.4	6.6	5.2
Balance at end of year	$ 2.5	$ 3.2	$ 2.5