10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

 OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2018

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

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

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

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

Yes [ ]    No [X]

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common Stock, $4 Par Value,

23,896,962 shares outstanding at June 30, 2018

All of the common stock of Wisconsin Public Service Corporation is owned by Integrys Holding, Inc., a wholly owned subsidiary of WEC Energy Group, Inc.

WISCONSIN PUBLIC SERVICE CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2018

TABLE OF CONTENTS

				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Notes to Condensed Consolidated Financial Statements			6
			Page
	Note 1	General Information	6
	Note 2	Acquisition	6
	Note 3	Operating Revenues	6
	Note 4	Property, Plant, and Equipment	9
	Note 5	Common Equity	10
	Note 6	Short-Term Debt and Lines of Credit	10
	Note 7	Materials, Supplies, and Inventories	11
	Note 8	Income Taxes	11
	Note 9	Fair Value Measurements	11
	Note 10	Derivative Instruments	13
	Note 11	Guarantees	14
	Note 12	Employee Benefits	14
	Note 13	Goodwill and Other Intangible Assets	15
	Note 14	Segment Information	16
	Note 15	Related Parties	17
	Note 16	Commitments and Contingencies	19
	Note 17	Supplemental Cash Flow Information	22
	Note 18	Regulatory Environment	23
	Note 19	New Accounting Pronouncements	23
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			25
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			38
ITEM 4.	CONTROLS AND PROCEDURES			39
PART II.	OTHER INFORMATION			40
ITEM 1.	LEGAL PROCEEDINGS			40
ITEM 1A.	RISK FACTORS			40
ITEM 6.	EXHIBITS			41
SIGNATURE				42

06/30/2018 Form 10-Q i 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
Bluewater	Bluewater Natural Gas Holding, LLC
Integrys	Integrys Holding, Inc.
UMERC	Upper Michigan Energy Resources Corporation
WBS	WEC Business Services LLC
WEC Energy Group	WEC Energy Group, Inc.
WE	Wisconsin Electric Power Company
WG	Wisconsin Gas LLC
WPSI	WPS Investments, LLC
WRPC	Wisconsin River Power Company
Federal and State Regulatory Agencies
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ASU	Accounting Standards Update
FASB	Financial Accounting Standards Board
GAAP	United States Generally Accepted Accounting Principles
OPEB	Other Postretirement Employee Benefits
Environmental Terms
CAA	Clean Air Act
CO2	Carbon Dioxide
CPP	Clean Power Plan
GHG	Greenhouse Gas
NOV	Notice of Violation
WPDES	Wisconsin Pollution Discharge Elimination System
Measurements
Dth	Dekatherm
MW	Megawatt
MWh	Megawatt-hour
Other Terms and Abbreviations
D.C. Circuit Court of Appeals	United States Court of Appeals for the District of Columbia Circuit
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Markets
ROE	Return on Equity
SMRP	System Modernization and Reliability Project
Supreme Court	United States Supreme Court
Tax Legislation	Tax Cuts and Jobs Act of 2017

06/30/2018 Form 10-Q ii 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 Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, 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 risk factors as set forth in this report and our 2017 Annual Report on Form 10-K, and those identified below:

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

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

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

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

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

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

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

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

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

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

• The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or 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;

06/30/2018 Form 10-Q 1 Wisconsin Public Service Corporation

• 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;

• 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 attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns;

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

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

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

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

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

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

• The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities;

• 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.

06/30/2018 Form 10-Q 2 Wisconsin Public Service Corporation

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended						Six Months Ended
	June 30						June 30
(in millions)	2018			2017			2018			2017
Operating revenues	$	350.1		$	341.6		$	743.7		$	731.2
Operating expenses
Cost of sales	128.6			130.5			304.4			295.4
Other operation and maintenance	105.4			108.8			208.1			216.0
Depreciation and amortization	33.6			34.4			69.5			68.8
Property and revenue taxes	10.1			9.8			20.1			19.9
Total operating expenses	277.7			283.5			602.1			600.1
Operating income	72.4			58.1			141.6			131.1
Other income, net	8.8			5.9			18.1			11.6
Interest expense	13.2			13.6			26.0			27.5
Other expense	(4.4		)	(7.7		)	(7.9		)	(15.9		)
Income before income taxes	68.0			50.4			133.7			115.2
Income tax expense	25.3			19.7			41.2			45.2
Net income	$	42.7		$	30.7		$	92.5		$	70.0

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

06/30/2018 Form 10-Q 3 Wisconsin Public Service Corporation

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)	June 30,		December 31,
(in millions, except share and per share amounts)	2018		2017
Assets
Current assets
Cash and cash equivalents	$	1.8	$	7.9
Accounts receivable and unbilled revenues, net of reserves of $4.0	186.6		205.0
Receivables from related parties	17.2		4.4
Materials, supplies, and inventories	108.8		107.0
Prepaid taxes	38.8		52.7
Other	12.2		13.0
Current assets	365.4		390.0
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $1,740.1 and $1,633.3, respectively	4,022.1		3,823.0
Regulatory assets	362.1		382.8
Goodwill	36.4		36.4
Pension and OPEB assets	70.2		62.0
Other	64.0		54.5
Long-term assets	4,554.8		4,358.7
Total assets	$	4,920.2	$	4,748.7
Liabilities and Shareholder's Equity
Current liabilities
Short-term debt	$	317.2	$	293.1
Current portion of long-term debt	250.0		250.0
Accounts payable	122.8		130.4
Payables to related parties	59.7		30.0
Other	65.7		66.4
Current liabilities	815.4		769.9
Long-term liabilities
Long-term debt	916.6		916.2
Deferred income taxes	521.1		512.7
Deferred investment tax credits	6.5		6.7
Regulatory liabilities	699.2		689.3
Environmental remediation liabilities	99.4		99.6
Pension and OPEB obligations	24.1		24.0
Payables to related parties	3.2		3.5
Other	115.2		109.5
Long-term liabilities	2,385.3		2,361.5
Commitments and contingencies (Note 16)
Shareholder's equity
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	1,065.8		996.1
Retained earnings	558.1		525.6
Shareholder's equity	1,719.5		1,617.3
Total liabilities and shareholder's equity	$	4,920.2	$	4,748.7

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

06/30/2018 Form 10-Q 4 Wisconsin Public Service Corporation

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Six Months Ended
	June 30
(in millions)	2018			2017
Operating Activities
Net income	$	92.5		$	70.0
Reconciliation to cash provided by operating activities
Depreciation and amortization	69.5			68.8
Deferred income taxes and investment tax credits, net	15.7			18.2
Contributions and payments related to pension and OPEB plans	(0.4		)	(66.2		)
Cash received for pension plan assets transferred	—			161.9
Change in –
Accounts receivable and unbilled revenues	5.6			10.6
Materials, supplies, and inventories	(1.5		)	13.3
Prepaid taxes	13.9			10.9
Other current assets	7.7			(2.5		)
Accounts payable	50.0			(14.6		)
Other current liabilities	1.0			0.3
Other, net	(1.6		)	9.7
Net cash provided by operating activities	252.4			280.4
Investing Activities
Capital expenditures	(193.4		)	(144.3		)
Acquisition of Forward Wind Energy Center	(77.1		)	—
Payments for assets transferred from WBS	(23.7		)	(9.2		)
Other, net	1.6			1.4
Net cash used in investing activities	(292.6		)	(152.1		)
Financing Activities
Change in short-term debt	24.1			(44.8		)
Payment of dividends to parent	(60.0		)	(135.0		)
Equity contribution from parent	70.0			75.0
Net cash provided by (used in) financing activities	34.1			(104.8		)
Net change in cash and cash equivalents	(6.1		)	23.5
Cash and cash equivalents at beginning of period	7.9			3.1
Cash and cash equivalents at end of period	$	1.8		$	26.6

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

06/30/2018 Form 10-Q 5 Wisconsin Public Service Corporation

WISCONSIN PUBLIC SERVICE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

June 30, 2018

NOTE 1—GENERAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2—ACQUISITION

Acquisition of a Wind Energy Generation Facility in Wisconsin

On April 2, 2018, we, along with two other unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129 MW. The aggregate purchase price was $172.9 million of which our proportionate share was 44.6%, or $77.1 million. Since 2008 and up until the acquisition, we purchased 44.6% of the facility’s energy output under a power purchase agreement.

The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base.

(in millions)
Current assets	$	0.2
Net property, plant, and equipment	76.9
Total purchase price	$	77.1

Under a joint ownership agreement with the two other utilities, we are entitled to our share of generating capability and output of the facility equal to our ownership interest. We are also paying our ownership share of additional construction costs and operating expenses.

NOTE 3—OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

06/30/2018 Form 10-Q 6 Wisconsin Public Service Corporation

We adopted the following practical expedients and optional exemptions for the implementation of this standard:

• We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.

• When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.

• We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.

• We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.

• We elected to apply this standard only to contracts that are not completed as of the date of initial application.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.

	Wisconsin Public Service Consolidated
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Electric utility	$	292.5	$	574.6
Natural gas utility	56.9		167.5
Total revenues from contracts with customers	349.4		742.1
Other operating revenues	0.7		1.6
Total operating revenues	$	350.1	$	743.7

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

	Electric Utility Operating Revenues
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	90.9	$	185.1
Small commercial and industrial	88.4		177.2
Large commercial and industrial	64.9		115.9
Other	2.2		4.3
Total retail revenues	246.4		482.5
Wholesale	35.3		68.9
Resale	8.0		18.1
Other utility revenues	2.8		5.1
Total electric utility revenues	$	292.5	$	574.6

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the

06/30/2018 Form 10-Q 7 Wisconsin Public Service Corporation

customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Natural Gas Utility Operations
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	26.5	$	97.2
Commercial and industrial	15.3		59.3
Total retail revenues	41.8		156.5
Transport	4.0		12.0
Other utility revenues *	11.1		(1.0		)
Total natural gas utility operating revenues	$	56.9	$	167.5

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

06/30/2018 Form 10-Q 8 Wisconsin Public Service Corporation

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Operating Revenues

Other operating revenues consist primarily of the following:

(in millions)	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Late payment charges	$	0.8		$	1.7
Leases	0.1			0.1
Alternative revenues *	(0.2		)	(0.2		)
Total other operating revenues	$	0.7		$	1.6

* Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

NOTE 4—PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have announced the retirement of the plants identified below. In addition, a severance liability in the amount of $3.6 million was recorded in other current liabilities on our balance sheets related to these announced plant retirements.

06/30/2018 Form 10-Q 9 Wisconsin Public Service Corporation

Pulliam Power Plant

In connection with the MISO ruling received in June 2018, Pulliam Units 7 and 8 will be retired on or before October 31, 2018. Retirement of the Pulliam generating units remained probable at June 30, 2018. The carrying value of the Pulliam units was $42.3 million at June 30, 2018. This amount included the net book value of $62.1 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $19.8 million cost of removal reserve related to the Pulliam units was recorded as a regulatory liability at June 30, 2018. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information.

Edgewater Unit 4

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, retirement of the Edgewater 4 generating unit remained probable at June 30, 2018. The plant must be retired by September 30, 2018. The carrying value of the Edgewater 4 generating unit was $12.3 million at June 30, 2018. This amount included the net book value of our ownership share of this generating unit of $14.2 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $1.9 million cost of removal reserve related to the Edgewater 4 generating unit was recorded as a regulatory liability at June 30, 2018. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information regarding the Consent Decree.

NOTE 5—COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to the sole holder of our common stock, Integrys, in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their subsidiaries. See Note 9, Common Equity, in our 2017 Annual Report on Form 10-K for additional information on these and other restrictions.

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

NOTE 6—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	June 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	317.2		$	293.1
Weighted-average interest rate on amounts outstanding	2.31		%	1.72		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2018, was $278.6 million with a weighted-average interest rate during the period of 2.07%.

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

(in millions)	Maturity	June 30, 2018
Revolving credit facility	October 2022	$	400.0
Less:
Letters of credit issued inside credit facility		$	1.3
Commercial paper outstanding		317.2
Available capacity under existing agreement		$	81.5

06/30/2018 Form 10-Q 10 Wisconsin Public Service Corporation

NOTE 7—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	June 30, 2018		December 31, 2017
Fossil fuel	$	46.5	$	43.8
Materials and supplies	48.2		40.8
Natural gas in storage	14.1		22.4
Total	$	108.8	$	107.0

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

NOTE 8—INCOME TAXES

The effective tax rates of 37.2% and 30.8% for the three and six months ended June 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the accounting treatment of the PSCW's order regarding the benefits associated with the Tax Legislation, in addition to state income taxes. See Note 18, Regulatory Environment, for more information on the Tax Legislation.

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

NOTE 9—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 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

06/30/2018 Form 10-Q 11 Wisconsin Public Service Corporation

inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.

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

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:

	June 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.4	$	—	$	—	$	1.4
Petroleum product contracts	0.1		—		—		0.1
FTRs	—		—		8.0		8.0
Coal contracts	—		0.1		—		0.1
Total derivative assets	$	1.5	$	0.1	$	8.0	$	9.6
Derivative liabilities
Natural gas contracts	$	0.5	$	—	$	—	$	0.5
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	0.5	$	0.3	$	—	$	0.8

	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.8	$	—	$	—	$	0.8
Petroleum product contracts	0.3		—		—		0.3
FTRs	—		—		2.0		2.0
Coal contracts	—		0.4		—		0.4
Total derivative assets	$	1.1	$	0.4	$	2.0	$	3.5
Derivative liabilities
Natural gas contracts	$	2.3	$	—	$	—	$	2.3
Coal contracts	—		0.5		—		0.5
Total derivative liabilities	$	2.3	$	0.5	$	—	$	2.8

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

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

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of period	$	0.7		$	0.6		$	2.0		$	2.0
Purchases	9.0			6.9			9.0			6.9
Settlements	(1.7		)	(1.7		)	(3.0		)	(3.1		)
Balance at the end of period	$	8.0		$	5.8		$	8.0		$	5.8

06/30/2018 Form 10-Q 12 Wisconsin Public Service Corporation

Fair Value of Financial Instruments

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

	June 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,166.6	$	1,232.2	$	1,166.2	$	1,302.4

The fair values of long-term debt are categorized within Level 2 of the fair value hierarchy.

NOTE 10—DERIVATIVE INSTRUMENTS

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

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

The following table shows our derivative assets and derivative liabilities:

	June 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.3	$	0.4	$	0.8	$	1.9
Petroleum products contracts	0.1		—		0.3		—
FTRs	8.0		—		2.0		—
Coal contracts	—		0.3		—		0.5
Total other current *	$	9.4	$	0.7	$	3.1	$	2.4
Other long-term
Natural gas contracts	$	0.1	$	0.1	$	—	$	0.4
Coal contracts	0.1		—		0.4		—
Total other long-term *	$	0.2	$	0.1	$	0.4	$	0.4
Total	$	9.6	$	0.8	$	3.5	$	2.8

* On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

Realized gains (losses) on derivative instruments are primarily included in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:

	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains
Natural gas contracts	8.3 Dth	$	(0.3	)	— Dth	$	—
Petroleum products contracts	0.6 gallons	0.1			— gallons	—
FTRs	2.0 MWh	3.0			2.1 MWh	0.2
Total		$	2.8			$	0.2

06/30/2018 Form 10-Q 13 Wisconsin Public Service Corporation

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	21.3 Dth	$	(2.0	)	5.1 Dth	$	(0.5	)
Petroleum products contracts	1.3 gallons	0.2			— gallons	—
FTRs	4.4 MWh	5.9			4.3 MWh	0.7
Total		$	4.1			$	0.2

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2018 and December 31, 2017, we had posted cash collateral of $0.8 million and $4.9 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets.

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

	June 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	9.6		$	0.8		$	3.5		$	2.8
Gross amount not offset on the balance sheet	(0.5		)	(0.5		)	(1.1		)	(2.3		)	*
Net amount	$	9.1		$	0.3		$	2.4		$	0.5

* Includes cash collateral posted of $1.2 million.

NOTE 11—GUARANTEES

As of June 30, 2018, we had $20.6 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

NOTE 12—EMPLOYEE BENEFITS

Through December 31, 2016, we participated in the Integrys Energy Group Retirement Plan, a noncontributory, qualified pension plan sponsored by WBS. We were responsible for our share of the plan assets and obligations. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. As a result, assets were transferred out of our plan in January 2017. See Note 15, Related Parties, for more information.

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	2.6		$	1.9		$	5.2		$	4.5
Interest cost	6.5			6.6			13.0			13.4
Expected return on plan assets	(11.9		)	(11.7		)	(24.1		)	(23.2		)
Amortization of net actuarial loss	5.5			4.3			10.5			8.6
Net periodic benefit cost	$	2.7		$	1.1		$	4.6		$	3.3

06/30/2018 Form 10-Q 14 Wisconsin Public Service Corporation

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.5		$	1.5		$	3.1		$	3.1
Interest cost	2.1			2.3			4.1			4.7
Expected return on plan assets	(4.5		)	(4.1		)	(8.9		)	(8.2		)
Amortization of prior service credit	(2.9		)	(2.3		)	(5.7		)	(4.6		)
Amortization of net actuarial loss	0.6			0.6			1.2			1.2
Net periodic benefit credit	$	(3.2	)	$	(2.0	)	$	(6.2	)	$	(3.8	)

During the six months ended June 30, 2018, we made contributions and payments of $0.3 million related to our pension plans and $0.1 million related to our OPEB plans. We expect to make contributions and payments of $0.4 million related to our pension plans and $0.1 million related to our OPEB plans during the remainder of 2018, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for thethree and six months ended June 30,2018and2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net.

The following table shows the non-service credit components of net benefit costs:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Non-service credit components	$	(3.8	)	$	(2.9	)	$	(8.3	)	$	(5.7	)

For the three and six months ended June 30, 2017, the net credits from the non-service components of net benefit cost were reclassified from other operation and maintenance to other income, net, on our income statements.

Under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, are presented as regulatory assets or liabilities rather than property, plant, and equipment.

NOTE 13—GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no changes to the carrying amount of goodwill during the six months ended June 30, 2018 and 2017.

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

	June 30, 2018							December 31, 2017
(in millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	8.3	$	(6.2	)	$	2.1	$	8.3	$	(5.6	)	$	2.7
Unamortized intangible assets	0.4		—			0.4		0.4		—			0.4
Total intangible assets	$	8.7	$	(6.2	)	$	2.5	$	8.7	$	(5.6	)	$	3.1

* 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 amortization period at June 30, 2018 was approximately two years.

06/30/2018 Form 10-Q 15 Wisconsin Public Service Corporation

NOTE 14—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2018, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in northeastern Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in northeastern Wisconsin.

The other segment includes non-utility activities, as well as equity earnings from our investment in WRPC.

The following tables show summarized financial information for the three and six months ended June 30, 2018 and 2017, related to our reportable segments:

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Three Months Ended June 30, 2018
Operating revenues	$	350.1	$	—		$	350.1
Other operation and maintenance	105.2		0.2			105.4
Depreciation and amortization	33.6		—			33.6
Operating income (loss)	72.6		(0.2		)	72.4
Other income, net	7.9		0.9			8.8
Interest expense	13.2		—			13.2

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Three Months Ended June 30, 2017
Operating revenues	$	341.6	$	—		$	341.6
Other operation and maintenance *	108.5		0.3			108.8
Depreciation and amortization	34.5		(0.1		)	34.4
Operating income (loss) *	58.3		(0.2		)	58.1
Other income, net *	4.5		1.4			5.9
Interest expense	13.6		—			13.6

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Six Months Ended June 30, 2018
Operating revenues	$	743.7	$	—		$	743.7
Other operation and maintenance	207.9		0.2			208.1
Depreciation and amortization	69.5		—			69.5
Operating income (loss)	141.9		(0.3		)	141.6
Other income, net	16.8		1.3			18.1
Interest expense	26.0		—			26.0

06/30/2018 Form 10-Q 16 Wisconsin Public Service Corporation

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Six Months Ended June 30, 2017
Operating revenues	$	731.2	$	—		$	731.2
Other operation and maintenance *	215.5		0.5			216.0
Depreciation and amortization	68.9		(0.1		)	68.8
Operating income (loss) *	131.5		(0.4		)	131.1
Other income, net *	9.8		1.8			11.6
Interest expense	27.5		—			27.5

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

NOTE 15—RELATED PARTIES

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

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.

Prior to January 1, 2017, we held a 10.37% investment in WPSI which held an approximate 34% interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our $67.2 million ownership interest in WPSI to another subsidiary of Integrys. In addition, during 2017 we transferred $41.9 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.

We provide services to WRPC under an operating agreement approved by the PSCW. We are also a party to a service agreement with WRPC where we are billed for services provided by WRPC. Services are billed to and from WRPC under these agreements at a fully allocated cost.

Our balance sheets included the following receivables and payables related to transactions entered into with certain related parties:

(in millions)	June 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	0.5	$	0.7
Accounts payable
Network transmission services from ATC	8.8		9.0
Liability related to income tax allocation
Integrys	3.8		4.1

06/30/2018 Form 10-Q 17 Wisconsin Public Service Corporation

The following table shows activity associated with our related party transactions:

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2018		2017		2018		2017
Transactions with WE (1)
Billings to WE	$	1.9	$	1.1	$	5.1	$	2.2
Billings from WE	4.3		5.2		7.3		7.7
Transactions with WBS (1)
Billings to WBS (2)	0.3		4.2		0.5		168.3
Billings from WBS (3)	32.5		35.3		85.0		68.2
Transactions with UMERC
Electric sales to UMERC	4.0		4.0		7.7		8.1
Natural gas sales to UMERC	0.3		0.5		1.5		1.6
Transactions with Bluewater (4)
Storage service fees	1.5		—		1.7		—
Transactions related to ATC
Charges to ATC for services and construction	1.5		1.4		3.0		2.8
Charges from ATC for network transmission services	26.5		26.9		53.0		53.9
Refund from ATC related to a FERC audit	6.6		—		6.6		—
Refund from ATC per FERC ROE order	—		—		—		8.9
Transactions with WRPC
Rental payments to WRPC (5)	0.4		0.4		0.7		0.5
Purchases of energy from WRPC (5)	—		—		—		0.5
Charges from WRPC for services	0.6		0.6		1.2		0.8
Charges to WRPC for operations	0.2		0.3		0.4		0.5

⁽¹⁾  Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

⁽²⁾  The six months ended June 30, 2017 included $161.9 million of cash received related to our transfer of pension trust assets in conjunction with the Integrys pension plan split. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017. There were no transfers of assets to WBS for the three and six months ended June 30, 2018, or for the three months ended June 30, 2017.

⁽³⁾  Includes $5.8 million and $29.1 million for the transfer of certain software assets from WBS for the three and six months ended June 30, 2018, respectively. The three and six months ended June 30, 2017 included $9.2 million for the transfer of certain software assets to us.

⁽⁴⁾  WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

⁽⁵⁾  In March 2017, we terminated our power purchase agreement with WRPC and entered into an agreement with WRPC to rent 50% of its hydroelectric power generation facilities.

Upper Michigan Energy Resources Corporation

In December 2016, both the Michigan Public Service Commission and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 9,000 retail electric customers and 5,300 natural gas customers to UMERC, along with approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of the net assets (including the related deferred income tax liabilities) transferred to UMERC from us in 2017 was $20.6 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WE.

06/30/2018 Form 10-Q 18 Wisconsin Public Service Corporation

WEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017.

NOTE 16—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2018, were $854.6 million.

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 sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territory were designated as partial nonattainment: Door, Manitowoc, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin) and other parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and, to the extent that further appellate review is sought, at the Supreme Court. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case.

In March 2017, President Trump issued an executive order that, among other things, specifically directed the EPA to review the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit

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input on whether it is appropriate to replace the CPP. The EPA is expected to issue a proposed CPP replacement rule, or decide to rescind the CPP without replacing it, during the third quarter of 2018.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. WEC Energy Group's plan, which includes us, is to work with its industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group's new long-term goal is to reduce CO₂ emissions by approximately 80% below 2005 levels by 2050. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO₂ reduction goals. Options considered include increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 308 MW of coal generation by 2020, including Pulliam power plant and the jointly-owned Edgewater Unit 4 generation units. See Note 4, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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, satisfy the IM BTA requirements. We will retire Pulliam Units 7 and 8 on or before October 31, 2018. See Note 4, Property, Plant, and Equipment, for more information. Therefore, the WPDES permit reissued by the WDNR on June 29, 2018, will not require us to make alterations to the existing water intake at Pulliam Units 7 and 8. Based on the reissued WPDES permit for Weston, 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. There has been an interim EM BTA determination made by the WDNR as part of the reissued WPDES permit for Weston Units 3 and 4, and we intend to extrapolate these results to assess Weston Unit 2. The entrainment study and other technical information will be used by the WDNR to make a final 316(b) determination during the next five year WPDES permit term. At this time, we expect that the WDNR will conclude that the existing cooling tower systems for Weston Units 3 and 4 are BTA for both impingement and entrainment reduction. In addition, the WDNR has initially indicated that based on the low capacity utilization of Weston Unit 2, impingement mortality reduction technology will not be required and further entrainment reduction will not be necessary.  Due to our plans to retire Pulliam Units 7 and 8, we do not believe that BTA determinations for EM will be necessary for these units.

We have also provided information to the WDNR about planned unit retirements. For Pulliam Units 7 and 8, in light of the pending facility retirement, the reissued WPDES permit included an interim BTA determination for the existing barrier net system. We will not be required to conduct monitoring for IM or EM or to submit additional 316(b) information until the next permit renewal application in December 2022.

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

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Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurizationwastewater requirements. This rule applies to wastewater discharges from our power plant processes in Wisconsin. In February 2018, the Center for Biological Diversity (CBD) filed suit in the U.S. District Court of Arizona challenging the Postponement Rule. In April 2018, the Utility Water Act Group filed a motion to dismiss the CBD suit for lack of subject matter jurisdiction. While the ELG compliance deadlines are postponed, the WDNR has indicated that it will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR has indicated that it will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate approximately $20 million would be required to design and install a dry bottom ash transport system for Weston Unit 3. This estimate reflects the planned retirements of certain of our generation plants as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach 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, we are coordinating the investigation and cleanup of some of these sites 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:

(in millions)	June 30, 2018		December 31, 2017
Regulatory assets	$	114.8	$	116.0
Reserves for future remediation	99.4		99.6

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Consent Decrees

Weston and Pulliam Power Plants Consent Decree

In November 2009, the EPA issued an 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 United States District Court for the Eastern District of Wisconsin in March 2013.

We will retire Pulliam Units 7 and 8 on or before October 31, 2018. See Note 4, Property, Plant, and Equipment, for more information about the retirement.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued an 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, WE (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, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, 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.

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit must be retired by September 30, 2018. See Note 4, Property, Plant, and Equipment, for more information about the retirement.

Enforcement and Litigation Matters

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

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(26.1	)	$	(27.5	)
Cash (paid) for income taxes, net	(8.6		)	(18.5		)
Significant noncash transactions:
Accounts payable related to construction costs	13.0			33.4
Accounts payable related to assets transferred from affiliates	5.5			—
Transfer of ownership in WPSI to another subsidiary of Integrys *	—			67.2
Transfer of net assets to UMERC *	—			21.1

* See Note 15, Related Parties, for more information on these transactions.

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NOTE 18—REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

We deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $444.7 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018, is also being deferred for return to ratepayers.

In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires our electric utility operations to use 40% of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 60% is to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce certain regulatory assets for our electric utility operations and is being deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes for our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. During the six months ended June 30, 2018, we reduced our regulatory assets by $13.0 million as a result of the PSCW order.

2018 and 2019 Wisconsin Rates

During April 2017, we, along with WE and WG, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for electric and natural gas customers. Based on the PSCW order, our authorized ROE remains at 10.0%, and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers. Additionally, the agreement allows us to extend, through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to our electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million.

Pursuant to the settlement agreement, we also agreed to adopt, beginning in 2018, the earnings sharing mechanism that has been in place for WE and WG since January 2016, and agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Proposed Solar Generation Projects

On May 31, 2018, we, along with an unaffiliated utility, filed an application with the PSCW to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. We will own 100 MW of the output of each project for a total of 200 MW. Our share of the cost of both projects is estimated to be $260 million.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, ASU 2018-10, Codification Improvements to Topic 842, Leases, and ASU 2018-11, Targeted Improvements. The main provision of ASU 2016-02 is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. In addition, this ASU expands the required quantitative and qualitative disclosures related to lease agreements. This guidance is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. This guidance must be adopted using a modified retrospective

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approach and provides for a number of optional transition practical expedients. We expect to apply the package of practical expedients allowed by this ASU which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2017.

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 in northeastern Wisconsin. We also provide wholesale electric service to numerous utilities and cooperatives for resale. We conduct our business primarily through our utility reportable segment. See Note 14, Segment Information, for more information on our reportable business segments.

Corporate Strategy

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

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group set a new long-term goal of reducing CO₂ emissions by approximately 80% below 2005 levels by 2050. WEC Energy Group expects to retire approximately 1,800 MW of coal generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. See Note 4, Property, Plant, and Equipment, for information related to the planned retirements of our Pulliam power plant and jointly-owned Edgewater Unit 4 as part of WEC Energy Group's plan.

Reliability

We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability.

We continue work on our SMRP, which involves modernizing parts of our electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service we provide to our customers. We also continue to upgrade our electric and natural gas distribution systems to enhance reliability.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

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

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Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Acquisition, for more information about our acquisition of a portion of a wind energy generation facility in Wisconsin.

Exceptional Customer Care

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

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

Safety

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2018

Consolidated Earnings

The following table compares our consolidated results for the second quarter of 2018 with the second quarter of 2017, including favorable or better, "B", and unfavorable or worse, "W", variances:

	Three Months Ended June 30
(in millions)	2018		2017		B (W)			Change Related to Tax Legislation			Remaining Change B (W)
Operating revenues	$	350.1	$	341.6	$	8.5		$	(1.2	)	$	9.7
Cost of sales	128.6		130.5		1.9			—			1.9
Other operation and maintenance	105.4		108.8		3.4			—			3.4
Depreciation and amortization	33.6		34.4		0.8			2.7			(1.9		)
Property and revenue taxes	10.1		9.8		(0.3		)	—			(0.3		)
Operating income	72.4		58.1		14.3			1.5			12.8
Other income, net	8.8		5.9		2.9			—			2.9
Interest expense	13.2		13.6		0.4			—			0.4
Income before income taxes	68.0		50.4		17.6			1.5			16.1
Income tax expense	25.3		19.7		(5.6		)	(1.5		)	(4.1		)
Net income	$	42.7	$	30.7	$	12.0		$	—		$	12.0

Our consolidated earnings for the three months ended June 30, 2018 were $42.7 million, compared to $30.7 million for the same quarter in 2017. The table above shows the income statement impact associated with the Tax Legislation signed into law in December 2017. As shown in the table above, the changes related to the Tax Legislation had no impact on net income. See Note 8,

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Income Taxes, and Note 18, Regulatory Environment, for more information. See below for additional information on the $12.0 millionincrease in consolidated earnings.

Non-GAAP Financial Measures

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

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the three months ended June 30, 2018 and 2017 was $72.6 million and $58.3 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the second quarter of 2018 with the same quarter of 2017, including favorable or better, "B", and unfavorable or worse, "W", variances.

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
Electric revenues	$	292.9	$	289.6	$	3.3
Fuel and purchased power	98.2		105.3		7.1
Total electric margins	194.7		184.3		10.4
Natural gas revenues	57.2		52.0		5.2
Cost of natural gas sold	30.4		25.2		(5.2		)
Total natural gas margins	26.8		26.8		—
Total electric and natural gas margins	221.5		211.1		10.4
Other operation and maintenance	105.2		108.5		3.3
Depreciation and amortization	33.6		34.5		0.9
Property and revenue taxes	10.1		9.8		(0.3		)
Operating income	$	72.6	$	58.3	$	14.3

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

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	60.6	$	63.1	$	2.5
Transmission (1)	36.6		37.2		0.6
Regulatory amortizations and other pass through expenses (2)	8.0		8.2		0.2
Total other operation and maintenance	$	105.2	$	108.5	$	3.3

⁽¹⁾  The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate

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proceeding. During the three months ended June 30, 2018 and 2017, $31.3 million and $37.4 million, respectively, of costs were billed to us by transmission providers.

⁽²⁾  Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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

	Three Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer class
Residential	658.8	605.4	53.4
Small commercial and industrial	1,009.8	965.5	44.3
Large commercial and industrial	1,022.5	1,012.4	10.1
Other	5.5	5.5	—
Total retail	2,696.6	2,588.8	107.8
Wholesale	633.4	674.6	(41.2	)
Resale	232.8	176.0	56.8
Total sales in MWh	3,562.8	3,439.4	123.4

	Three Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer class
Residential	38.6	32.2	6.4
Commercial and industrial	39.2	25.1	14.1
Total retail	77.8	57.3	20.5
Transport	99.6	96.2	3.4
Total sales in therms	177.4	153.5	23.9

	Three Months Ended June 30
	Degree Days
Weather *	2018	2017	B (W)
Heating (937 normal)	1,081	834	29.6	%
Cooling (133 normal)	215	125	72.0	%

* Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.

Electric Utility Margins

Electric utility margins increased $10.4 million during the second quarter of 2018, compared with the same quarter in 2017. The significant factors impacting the higher electric utility margins were:

• A $6.6 million increase related to higher retail sales volumes during the second quarter of 2018, primarily driven by favorable weather and higher overall use per retail customer. A colder than normal April and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the second quarter of 2018 was 29.6% colder than the same quarter in 2017. A measured by cooling degree days, the second quarter of 2018 was 72.0% warmer than the same quarter in 2017.

• A $5.9 million quarter-over-quarter positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

These increases in margins were partially offset by a $2.8 million decrease in wholesale margins driven both by lower sales volumes and reduced capacity rates reflecting the Tax Legislation.

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Natural Gas Utility Margins

Overall, natural gas utility margins did not change during the second quarter of 2018, compared with the same quarter in 2017. Natural gas utility margins decreased $1.7 million related to amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 8, Income Taxes, and Note 18, Regulatory Environment, for more information. This decrease was substantially offset by a $1.2 million increase in margins as a result of higher sales volumes, primarily driven by a colder than normal April in 2018, higher use per commercial and industrial customer, and customer growth.

Operating Income

Operating income at the utility segment increased$14.3 million during the second quarter of 2018, compared with the same quarter in 2017. The increase was driven by the $10.4 million increase in electric margins discussed above and a $3.9 milliondecrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes).

The significant factors impacting the decrease in operating expenses during the second quarter of 2018, compared with the same quarter in 2017, were:

• A $3.5 million decrease in electric and natural gas distribution expenses, primarily related to lower expenses incurred related to storm damage during the second quarter of 2018.

• A $1.6 million decrease in expenses at our plants, primarily related to the winding down of operations in anticipation of expected plant retirements later this year. This resulted in lower maintenance and labor costs during the second quarter of 2018. See Note 4, Property, Plant, and Equipment, for more information on the plant retirements.

These decreases in operating expenses were partially offset by a $1.7 million increase in benefit costs.

Other Segment Contribution to Operating Income

	Three Months Ended June 30
(in millions)	2018			2017			B (W)
Operating loss	$	(0.2	)	$	(0.2	)	$	—

Consolidated Other Income, Net

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
AFUDC – Equity	$	1.1	$	1.2	$	(0.1	)
Other, net	7.7		4.7		3.0
Other income, net	$	8.8	$	5.9	$	2.9

Other income, net increased $2.9 million during the second quarter of 2018, compared with the same quarter in 2017. The increase was driven by the 2018 deferral of costs related to the acquisition and ownership of the Forward Wind Energy Center and higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 12, Employee Benefits, for more information on our benefit costs.

Consolidated Interest Expense

	Three Months Ended June 30
(in millions)	2018		2017		B (W)
Interest expense	$	13.2	$	13.6	$	0.4

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Consolidated Income Tax Expense

	Three Months Ended June 30
	2018		2017		B (W)
Effective tax rate	37.2	%	39.1	%	1.9	%

Our effective tax rate decreased by 1.9% when compared with the second quarter of 2017, primarily due to the impact of the Tax Legislation. See Note 8, Income Taxes, and Note 18, Regulatory Environment, for more information.

SIX MONTHS ENDED JUNE 30, 2018

Consolidated Earnings

The following table compares our consolidated results for the six months ended June 30, 2018 with the six months ended June 30, 2017, including favorable or better, "B", and unfavorable or worse, "W", variances:

	Six Months Ended June 30
(in millions)	2018		2017		B (W)			Change Related to Tax Legislation			Remaining Change B (W)
Operating revenues	$	743.7	$	731.2	$	12.5		$	(10.6	)	$	23.1
Cost of sales	304.4		295.4		(9.0		)	—			(9.0		)
Other operation and maintenance	208.1		216.0		7.9			—			7.9
Depreciation and amortization	69.5		68.8		(0.7		)	2.7			(3.4		)
Property and revenue taxes	20.1		19.9		(0.2		)	—			(0.2		)
Operating income	141.6		131.1		10.5			(7.9		)	18.4
Other income, net	18.1		11.6		6.5			—			6.5
Interest expense	26.0		27.5		1.5			—			1.5
Income before income taxes	133.7		115.2		18.5			(7.9		)	26.4
Income tax expense	41.2		45.2		4.0			7.9			(3.9		)
Net income	$	92.5	$	70.0	$	22.5		$	—		$	22.5

Our consolidated earnings for the six months ended June 30, 2018 were $92.5 million, compared to $70.0 million for the same period in 2017. The table above shows the income statement impact associated with the Tax Legislation signed into law in December 2017. As shown in the table above, the changes related to the Tax Legislation had no impact on net income. See Note 8, Income Taxes, and Note 18, Regulatory Environment, for more information. See below for additional information on the $22.5 millionincrease in consolidated earnings.

Non-GAAP Financial Measures

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

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

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the six months ended June 30, 2018 and

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2017 was $141.9 million and $131.5 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the six months ended June 30, 2018, with the same period in 2017, including favorable or better, "B", and unfavorable or worse, "W", variances.

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
Electric revenues	$	575.6	$	577.2	$	(1.6	)
Fuel and purchased power	199.5		204.8		5.3
Total electric margins	376.1		372.4		3.7
Natural gas revenues	168.1		154.0		14.1
Cost of natural gas sold	104.9		90.6		(14.3		)
Total natural gas margins	63.2		63.4		(0.2		)
Total electric and natural gas margins	439.3		435.8		3.5
Other operation and maintenance	207.9		215.5		7.6
Depreciation and amortization	69.5		68.9		(0.6		)
Property and revenue taxes	20.0		19.9		(0.1		)
Operating income	$	141.9	$	131.5	$	10.4

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

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	118.0	$	124.9	$	6.9
Transmission (1)	73.5		73.1		(0.4		)
Regulatory amortizations and other pass through expenses (2)	16.4		17.5		1.1
Total other operation and maintenance	$	207.9	$	215.5	$	7.6

⁽¹⁾  The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the six months ended June 30, 2018 and 2017, $67.6 million and $64.3 million, respectively, of costs were billed to us by transmission providers.

⁽²⁾  Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

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

	Six Months Ended June 30
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer class
Residential	1,402.2	1,319.6	82.6
Small commercial and industrial	1,976.3	1,915.2	61.1
Large commercial and industrial	1,997.6	1,992.2	5.4
Other	13.3	13.4	(0.1	)
Total retail	5,389.4	5,240.4	149.0
Wholesale	1,238.8	1,334.4	(95.6	)
Resale	485.0	320.7	164.3
Total sales in MWh	7,113.2	6,895.5	217.7

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	Six Months Ended June 30
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	155.4	138.7	16.7
Commercial and industrial	121.0	97.0	24.0
Total retail	276.4	235.7	40.7
Transport	231.8	223.5	8.3
Total sales in therms	508.2	459.2	49.0

	Six Months Ended June 30
	Degree Days
Weather *	2018	2017	B (W)
Heating (4,561 normal)	4,717	4,107	14.9	%
Cooling (133 normal)	215	125	72.0	%

* Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.

Electric Utility Margins

Electric utility margins increased $3.7 million during the six months ended June 30, 2018, compared with the same period in 2017. The significant factors impacting the higher electric utility margins were:

• A $10.9 million increase related to higher retail sales volumes during the six months ended June 30, 2018, primarily driven by favorable weather and higher overall use per retail customer. Colder winter weather and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the six months ended June 30, 2018, were 14.9% colder than the same period in 2017. As measured by cooling degree days, the six months ended June 30, 2018, were 72.0% warmer than the same period in 2017.

• A $7.9 million period-over-period positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

These increases in margins were partially offset by:

• A $7.4 million decrease in margins related to amounts expected to be refunded to customers through refunds and bill credits, driven by the Tax Legislation. See Note 8, Income Taxes, and Note 18, Regulatory Environment, for more information.

• A $4.6 million decrease in wholesale margins driven both by lower sales volumes and reduced capacity rates reflecting the Tax Legislation.

Natural Gas Utility Margins

Natural gas utility margins decreased $0.2 million during the six months ended June 30, 2018, compared with the same period in 2017. The most significant factor impacting the lower natural gas utility margins was a $3.2 million decrease related to amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 8, Income Taxes, and Note 18, Regulatory Environment, for more information. This decrease was substantially offset by a $2.7 million increase in margins as a result of higher sales volumes, primarily driven by colder winter weather, higher use per commercial and industrial customer, and customer growth.

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Operating Income

Operating income at the utility segment increased$10.4 million during the six months ended June 30, 2018, compared with the same period in 2017. The increase was driven by $6.9 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes) and the $3.5 million net increase in margins discussed above.

The significant factor impacting the decrease in operating expenses during the six months ended June 30, 2018, compared with the same period in 2017, was an $8.7 million decrease in electric and natural gas distribution expenses, primarily driven by lower expenses incurred related to storm damage during the six months ended June 30, 2018. This decrease was partially offset by a $3.7 million increase in benefit costs.

Other Segment Contribution to Operating Income

	Six Months Ended June 30
(in millions)	2018			2017			B (W)
Operating loss	$	(0.3	)	$	(0.4	)	$	0.1

Consolidated Other Income, Net

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
AFUDC – Equity	$	2.2	$	2.1	$	0.1
Other, net	15.9		9.5		6.4
Other income, net	$	18.1	$	11.6	$	6.5

Other income, net increased $6.5 million during the six months ended June 30, 2018, compared with the same period in 2017. The increase was driven by the 2018 deferral of costs related to the acquisition and ownership of the Forward Wind Energy Center and higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 12, Employee Benefits, for more information on our benefit costs.

Consolidated Interest Expense

	Six Months Ended June 30
(in millions)	2018		2017		B (W)
Interest expense	$	26.0	$	27.5	$	1.5

Interest expense decreased $1.5 million during the six months ended June 30, 2018, compared with the same period in 2017, primarily due to lower long-term debt balances. This decrease was partially offset by higher short-term interest expense due to higher short-term debt balances and higher short-term interest rates.

Consolidated Income Tax Expense

	Six Months Ended June 30
	2018		2017		B (W)
Effective tax rate	30.8	%	39.2	%	8.4	%

Our effective tax rate decreased by 8.4% when compared with the six months ended June 30, 2017, primarily due to the impact of the Tax Legislation. See Note 8, Income Taxes, and Note 18, Regulatory Environment, for more information.

As a result of the accounting treatment of the PSCW's order regarding the benefits associated with the Tax Legislation, we now expect our 2018 annual effective tax rate to be between 30% and 31%.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the six months ended June 30:

(in millions)	2018			2017			Change in 2018 Over 2017
Cash provided by (used in):
Operating activities	$	252.4		$	280.4		$	(28.0	)
Investing activities	(292.6		)	(152.1		)	(140.5		)
Financing activities	34.1			(104.8		)	138.9

Operating Activities

Net cash provided by operating activities decreased $28.0 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by a $161.9 million decrease in cash related to cash received for net assets transferred out of our pension plan in the first quarter of 2017. See Note 15, Related Parties, for more information.

This decrease in net cash provided by operating activities was partially offset by:

• A $65.8 million decrease in contributions and payments to our pension and OPEB plans during the six months ended June 30, 2018, compared with the same period in 2017.

• A $49.8 million increase in cash from lower payments for other operation and maintenance costs. During the six months ended June 30, 2018, our payments were lower for accounts payable to related parties as well as for electric and natural gas distribution costs.

• A $20.5 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during the six months ended June 30, 2018, compared with the same period in 2017.

Investing Activities

Net cash used in investing activities increased $140.5 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by:

• The acquisition of Forward Wind Energy Center during April 2018 for $77.1 million. See Note 2, Acquisition, for more information.

• A $49.1 million increase in cash paid for capital expenditures during the six months endedJune 30, 2018, compared with the same period in 2017, which is discussed in more detail below.

• A $14.5 million increase in cash paid for software assets received from WBS during the six months endedJune 30, 2018, compared with the same period in 2017.

Capital Expenditures

Capital expenditures for the six months ended June 30 were as follows:

(in millions)	2018		2017		Change in 2018 Over 2017
Capital expenditures	$	193.4	$	144.3	$	49.1

The increase in cash paid for capital expenditures during the six months ended June 30, 2018 was driven by higher expenditures for the advanced metering infrastructure program and other upgrades to our electric distribution system.

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

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Financing Activities

Net cash related to financing activities increased $138.9 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by:

• A $75.0 million decrease in dividends paid to our parent during the six months ended June 30, 2018. We paid a special dividend to our parent to balance our capital structure during the first quarter of 2017, driven by cash received for assets transferred out of our pension plan in January 2017.

• A $68.9 million net increase in cash due to $24.1 million of net borrowings of commercial paper during the six months ended June 30, 2018, compared with $44.8 million of net repayments of commercial paper during the same period in 2017.

For more information on our short-term financing activities, see Note 6, Short-Term Debt and Lines of Credit.

Capital Resources and Requirements

Capital Resources

Liquidity

We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors, and equity contributions from our parent.

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

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 6, Short-Term Debt and Lines of Credit, for more information on our credit facility.

Working Capital

As of June 30, 2018, our current liabilities exceeded our current assets by $450.0 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We have certain agreements in the form of commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

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

Capital Requirements

Significant Capital Projects

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

(in millions)
2018	$	463.0
2019	391.5
2020	838.1
Total	$	1,692.6

We are continuing work on the SMRP. This project involves modernizing parts of our electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service that we provide to our customers. We expect to invest approximately $250 million between 2018 and 2021 on this project. We also continue to upgrade our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

Additionally, as part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar. We have partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. We will own 100 MW of the output of each project for a total of 200 MW. Our share of the cost of both projects is estimated to be $260 million. Commercial operation for both projects is targeted for the end of 2020. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

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 that 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. See Note 11, Guarantees, for more information.

Contractual Obligations

Due to our acquisition of Forward Wind Energy Center, our related power purchase agreement was terminated on April 2, 2018, which resulted in a reduction of our contractual obligations. See Note 2, Acquisition, for more information.

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2017 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2017 Annual Report on Form 10-K, which

06/30/2018 Form 10-Q 36 Wisconsin Public Service Corporation

provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the regulatory recovery risk described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2017 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory Recovery

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by the PSCW. Recovery of the deferred costs in future rates is subject to the review and approval by the PSCW. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by the PSCW, the costs would be charged to income in the current period. The PSCW 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.

We expect to request or have requested recovery of the costs related to the following projects discussed in our recent or pending rate proceedings and orders:

• In June 2016, the PSCW approved the deferral of costs related to our ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 18, Regulatory Environment, for more information. We will be required to obtain a separate approval for collection of these deferred costs in a future rate case.

• Prior to its acquisition by WEC Energy Group, Integrys initiated an information technology 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 June 30, 2018, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

See Note 18, Regulatory Environment, for more information regarding recent and pending rate proceedings and orders.

Environmental Matters

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

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. As a result, the PSCW issued a written order in May 2018 regarding how we should refund the tax savings from the Tax Legislation to our ratepayers. We are also working with the FERC to modify our formula rate tariffs for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariffs in 2019. See Note 18, Regulatory Environment, for more information.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2017 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, 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 2 of Part I of this report, as well as Note 9, Fair Value Measurements, Note 10, Derivative Instruments, and Note 11, Guarantees, in this report for information concerning our market risk exposures.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

During the first quarter of 2018, WEC Energy Group completed an enterprise resource planning (ERP) system integration project to bring all of its subsidiaries, including us, onto a consolidated ERP system. Accordingly, we are modifying the design and documentation of certain internal control processes and procedures related to the integrated ERP system. We do not believe that the implementation of the ERP system will have an adverse effect on our internal control over financial reporting.

With the exception of the ERP system implementation described above, there were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the second quarter of 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

06/30/2018 Form 10-Q 39 Wisconsin Public Service Corporation

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2017 Annual Report on Form 10-K. See Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in Note 16, Commitments and Contingencies, Note 18, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Environmental Matters

Sheboygan River Matter

We were contacted by the United States Department of Justice in March 2016 to commence discussions with the federal natural resource trustees to resolve our alleged liability for natural resources damages (NRD) in the Sheboygan River related to the former Camp Marina manufactured gas plant site. We were originally notified about this claim in September 2012, but the WDNR chose not to be a party to the NRD claim negotiation in February 2014. However, the National Oceanic and Atmospheric Administration has co-equal trusteeship with the WDNR over the impacted Sheboygan River natural resources and pursued the NRD claim. Substantial remediation of the uplands at the legacy Sheboygan Camp Marina manufactured gas plant site has already occurred. We entered into a settlement agreement to resolve this matter, which was approved by the United States District Court for the Eastern District of Wisconsin in April 2018. The terms of the settlement did not have a material impact on our financial statements. 

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2017. See Item 1A. Risk Factors in Part I of our 2017 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

06/30/2018 Form 10-Q 40 Wisconsin Public Service Corporation

ITEM 6. EXHIBITS

Number	Exhibit
12	Statements re Computation of Ratios
	12.1	Ratio of Earnings to Fixed Charges
31	Rule 13a-14(a) / 15d-14(a) Certifications
	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data File

06/30/2018 Form 10-Q 41 Wisconsin Public Service Corporation

SIGNATURE

Pursuant to the requirements 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
		(Registrant)
		/s/ WILLIAM J. GUC
Date:	August 3, 2018	William J. Guc
		Vice President and Controller
		(Duly Authorized Officer and Chief Accounting Officer)

06/30/2018 Form 10-Q 42 Wisconsin Public Service Corporation

EX-12.1

Exhibit 12.1

WISCONSIN PUBLIC SERVICE CORPORATION

STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Unaudited)	Six Months Ended June 30, 2018		Twelve Months Ended December 31
(in millions, except ratios)			2017		2016		2015		2014		2013
EARNINGS
Pre-tax income *	$	133.7	$	253.6	$	243.5	$	198.7	$	224.0	$	217.7
FIXED CHARGES
Interest expense	26.0		54.2		48.1		53.5		57.4		43.7
Capitalized interest	0.9		1.6		8.1		6.1		4.6		3.8
Estimated interest component of rentals	0.6		2.2		1.9		1.2		1.5		1.4
Total fixed charges as defined	27.5		58.0		58.1		60.8		63.5		48.9
Total earnings as defined	$	161.2	$	311.6	$	301.6	$	259.5	$	287.5	$	266.6
RATIO OF EARNINGS TO FIXED CHARGES	5.9x		5.4x		5.2x		4.3x		4.5x		5.5x

* Pre-tax income consists of income before income taxes less undistributed earnings of equity investees.

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, Gale E. Klappa, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q 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:	August 3, 2018
	/s/ GALE E. KLAPPA
	Gale E. Klappa
	Chairman of the Board 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, Scott J. Lauber, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q 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:	August 3, 2018
	/s/ SCOTT J. LAUBER
	Scott J. Lauber
	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 Quarterly Report of Wisconsin Public Service Corporation (the "Company") on Form 10-Q for the quarter ended June 30, 2018, as filed with the Securities and Exchange Commission on August 3, 2018 (the "Report"), I, Gale E. Klappa, Chairman of the Board 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/ GALE E. KLAPPA

Gale E. Klappa

Chairman of the Board and Chief Executive Officer

August 3, 2018

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 Quarterly Report of Wisconsin Public Service Corporation (the "Company") on Form 10-Q for the quarter ended June 30, 2018, as filed with the Securities and Exchange Commission on August 3, 2018 (the "Report"), I, Scott J. Lauber, 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/ SCOTT J. LAUBER

Scott J. Lauber

Executive Vice President and Chief Financial Officer

August 3, 2018

XML

DOCUMENT AND ENTITY INFORMATION	6 Months Ended
	Jun. 30, 2018 shares
Document Entity Information [Abstract]
Entity registrant name	WISCONSIN PUBLIC SERVICE CORP
Entity central index key	0000107833
Document type	10-Q
Document period end date	Jun. 30, 2018
Amendment flag	false
Current fiscal year end date	--12-31
Entity filer category	Non-accelerated Filer
Entity common stock, shares outstanding	23,896,962
Document fiscal year focus	2018
Document fiscal period focus	Q2

XML

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement [Abstract]
Operating revenues	$ 350.1	$ 341.6	$ 743.7	$ 731.2
Operating expenses
Cost of sales	128.6	130.5	304.4	295.4
Other operation and maintenance	105.4	108.8	208.1	216.0
Depreciation and amortization	33.6	34.4	69.5	68.8
Property and revenue taxes	10.1	9.8	20.1	19.9
Total operating expenses	277.7	283.5	602.1	600.1
Operating income	72.4	58.1	141.6	131.1
Other income, net	8.8	5.9	18.1	11.6
Interest expense	13.2	13.6	26.0	27.5
Other expense	(4.4)	(7.7)	(7.9)	(15.9)
Income before income taxes	68.0	50.4	133.7	115.2
Income tax expense	25.3	19.7	41.2	45.2
Net income	$ 42.7	$ 30.7	$ 92.5	$ 70.0

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 1.8	$ 7.9
Accounts receivable and unbilled revenues, net of reserves of $4.0	186.6	205.0
Receivables from related parties	17.2	4.4
Materials, supplies, and inventories	108.8	107.0
Prepaid taxes	38.8	52.7
Other	12.2	13.0
Current assets	365.4	390.0
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $1,740.1 and $1,633.3, respectively	4,022.1	3,823.0
Regulatory assets	362.1	382.8
Goodwill	36.4	36.4
Pension and OPEB assets	70.2	62.0
Other	64.0	54.5
Long-term assets	4,554.8	4,358.7
Total assets	4,920.2	4,748.7
Current liabilities
Short-term debt	317.2	293.1
Current portion of long-term debt	250.0	250.0
Accounts payable	122.8	130.4
Payables to related parties	59.7	30.0
Other	65.7	66.4
Current liabilities	815.4	769.9
Long-term liabilities
Long-term debt	916.6	916.2
Deferred income taxes	521.1	512.7
Deferred investment tax credits	6.5	6.7
Regulatory liabilities	699.2	689.3
Environmental remediation liabilities	99.4	99.6
Pension and OPEB obligations	24.1	24.0
Payables to related parties	3.2	3.5
Other	115.2	109.5
Long-term liabilities	2,385.3	2,361.5
Commitments and contingencies (Note 16)
Shareholder's equity
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	1,065.8	996.1
Retained earnings	558.1	525.6
Shareholder's equity	1,719.5	1,617.3
Total liabilities and shareholder's equity	$ 4,920.2	$ 4,748.7

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable, reserves (in dollars)	$ 4.0	$ 4.0
Property, plant, and equipment, accumulated depreciation (in dollars)	$ 1,740.1	$ 1,633.3
Common stock, par value (in dollars per share)	$ 4
Common stock, shares authorized	32,000,000
Common stock, shares, issued	23,896,962
Common stock, shares outstanding	23,896,962

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities
Net income	$ 92.5	$ 70.0
Reconciliation to cash provided by operating activities
Depreciation and amortization	69.5	68.8
Deferred income taxes and investment tax credits, net	15.7	18.2
Contributions and payments related to pension and OPEB plans	(0.4)	(66.2)
Cash received for pension plan assets transferred	0.0	161.9
Change in –
Accounts receivable and unbilled revenues	5.6	10.6
Materials, supplies, and inventories	(1.5)	13.3
Prepaid taxes	13.9	10.9
Other current assets	7.7	(2.5)
Accounts payable	50.0	(14.6)
Other current liabilities	1.0	0.3
Other, net	(1.6)	9.7
Net cash provided by operating activities	252.4	280.4
Investing Activities
Capital expenditures	(193.4)	(144.3)
Acquisition of Forward Wind Energy Center	(77.1)	0.0
Payments for assets transferred from WBS	(23.7)	(9.2)
Other, net	1.6	1.4
Net cash used in investing activities	(292.6)	(152.1)
Financing Activities
Change in short-term debt	24.1	(44.8)
Payment of dividends to parent	(60.0)	(135.0)
Equity contribution from parent	70.0	75.0
Net cash provided by (used in) financing activities	34.1	(104.8)
Net change in cash and cash equivalents	(6.1)	23.5
Cash and cash equivalents at beginning of period	7.9	3.1
Cash and cash equivalents at end of period	$ 1.8	$ 26.6

XML

GENERAL INFORMATION

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

GENERAL INFORMATION

GENERAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

XML

ACQUISITION

6 Months Ended

Jun. 30, 2018

Business Combinations [Abstract]

ACQUISITION

ACQUISITION

Acquisition of a Wind Energy Generation Facility in Wisconsin

On April 2, 2018, we, along with two other unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129 MW. The aggregate purchase price was $172.9 million of which our proportionate share was 44.6%, or $77.1 million. Since 2008 and up until the acquisition, we purchased 44.6% of the facility’s energy output under a power purchase agreement.

The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base.

(in millions)
Current assets	$	0.2
Net property, plant, and equipment	76.9
Total purchase price	$	77.1

Under a joint ownership agreement with the two other utilities, we are entitled to our share of generating capability and output of the facility equal to our ownership interest. We are also paying our ownership share of additional construction costs and operating expenses.

XML

OPERATING REVENUES

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

OPERATING REVENUES

OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

We adopted the following practical expedients and optional exemptions for the implementation of this standard:

• We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.

• When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.

• We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.

• We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.

• We elected to apply this standard only to contracts that are not completed as of the date of initial application.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.

	Wisconsin Public Service Consolidated
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Electric utility	$	292.5	$	574.6
Natural gas utility	56.9		167.5
Total revenues from contracts with customers	349.4		742.1
Other operating revenues	0.7		1.6
Total operating revenues	$	350.1	$	743.7

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

	Electric Utility Operating Revenues
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	90.9	$	185.1
Small commercial and industrial	88.4		177.2
Large commercial and industrial	64.9		115.9
Other	2.2		4.3
Total retail revenues	246.4		482.5
Wholesale	35.3		68.9
Resale	8.0		18.1
Other utility revenues	2.8		5.1
Total electric utility revenues	$	292.5	$	574.6

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Natural Gas Utility Operations
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	26.5	$	97.2
Commercial and industrial	15.3		59.3
Total retail revenues	41.8		156.5
Transport	4.0		12.0
Other utility revenues *	11.1		(1.0		)
Total natural gas utility operating revenues	$	56.9	$	167.5

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

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Operating Revenues

Other operating revenues consist primarily of the following:

(in millions)	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Late payment charges	$	0.8		$	1.7
Leases	0.1			0.1
Alternative revenues *	(0.2		)	(0.2		)
Total other operating revenues	$	0.7		$	1.6

* Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

XML

PROPERTY, PLANT, AND EQUIPMENT

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have announced the retirement of the plants identified below. In addition, a severance liability in the amount of $3.6 million was recorded in other current liabilities on our balance sheets related to these announced plant retirements.

Pulliam Power Plant

In connection with the MISO ruling received in June 2018, Pulliam Units 7 and 8 will be retired on or before October 31, 2018. Retirement of the Pulliam generating units remained probable at June 30, 2018. The carrying value of the Pulliam units was $42.3 million at June 30, 2018. This amount included the net book value of $62.1 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $19.8 million cost of removal reserve related to the Pulliam units was recorded as a regulatory liability at June 30, 2018. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information.

Edgewater Unit 4

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, retirement of the Edgewater 4 generating unit remained probable at June 30, 2018. The plant must be retired by September 30, 2018. The carrying value of the Edgewater 4 generating unit was $12.3 million at June 30, 2018. This amount included the net book value of our ownership share of this generating unit of $14.2 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $1.9 million cost of removal reserve related to the Edgewater 4 generating unit was recorded as a regulatory liability at June 30, 2018. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information regarding the Consent Decree.

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COMMON EQUITY

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

COMMON EQUITY

COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to the sole holder of our common stock, Integrys, in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their subsidiaries. See Note 9, Common Equity, in our 2017 Annual Report on Form 10-K for additional information on these and other restrictions.

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

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SHORT-TERM DEBT AND LINES OF CREDIT

6 Months Ended

Jun. 30, 2018

Short-term Debt [Abstract]

SHORT-TERM DEBT AND LINES OF CREDIT

SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)	June 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	317.2		$	293.1
Weighted-average interest rate on amounts outstanding	2.31		%	1.72		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2018, was $278.6 million with a weighted-average interest rate during the period of 2.07%.

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

(in millions)	Maturity	June 30, 2018
Revolving credit facility	October 2022	$	400.0
Less:
Letters of credit issued inside credit facility		$	1.3
Commercial paper outstanding		317.2
Available capacity under existing agreement		$	81.5

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MATERIALS, SUPPLIES, AND INVENTORIES

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

MATERIALS, SUPPLIES, AND INVENTORIES

MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:

(in millions)	June 30, 2018		December 31, 2017
Fossil fuel	$	46.5	$	43.8
Materials and supplies	48.2		40.8
Natural gas in storage	14.1		22.4
Total	$	108.8	$	107.0

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

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INCOME TAXES

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The effective tax rates of 37.2% and 30.8% for the three and six months ended June 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the accounting treatment of the PSCW's order regarding the benefits associated with the Tax Legislation, in addition to state income taxes. See Note 18, Regulatory Environment, for more information on the Tax Legislation.

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

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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 between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

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

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

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:

	June 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.4	$	—	$	—	$	1.4
Petroleum product contracts	0.1		—		—		0.1
FTRs	—		—		8.0		8.0
Coal contracts	—		0.1		—		0.1
Total derivative assets	$	1.5	$	0.1	$	8.0	$	9.6
Derivative liabilities
Natural gas contracts	$	0.5	$	—	$	—	$	0.5
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	0.5	$	0.3	$	—	$	0.8

	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.8	$	—	$	—	$	0.8
Petroleum product contracts	0.3		—		—		0.3
FTRs	—		—		2.0		2.0
Coal contracts	—		0.4		—		0.4
Total derivative assets	$	1.1	$	0.4	$	2.0	$	3.5
Derivative liabilities
Natural gas contracts	$	2.3	$	—	$	—	$	2.3
Coal contracts	—		0.5		—		0.5
Total derivative liabilities	$	2.3	$	0.5	$	—	$	2.8

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

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

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of period	$	0.7		$	0.6		$	2.0		$	2.0
Purchases	9.0			6.9			9.0			6.9
Settlements	(1.7		)	(1.7		)	(3.0		)	(3.1		)
Balance at the end of period	$	8.0		$	5.8		$	8.0		$	5.8

Fair Value of Financial Instruments

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

	June 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,166.6	$	1,232.2	$	1,166.2	$	1,302.4

The fair values of long-term debt are categorized within Level 2 of the fair value hierarchy.

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DERIVATIVE INSTRUMENTS

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

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

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

The following table shows our derivative assets and derivative liabilities:

	June 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.3	$	0.4	$	0.8	$	1.9
Petroleum products contracts	0.1		—		0.3		—
FTRs	8.0		—		2.0		—
Coal contracts	—		0.3		—		0.5
Total other current *	$	9.4	$	0.7	$	3.1	$	2.4
Other long-term
Natural gas contracts	$	0.1	$	0.1	$	—	$	0.4
Coal contracts	0.1		—		0.4		—
Total other long-term *	$	0.2	$	0.1	$	0.4	$	0.4
Total	$	9.6	$	0.8	$	3.5	$	2.8

* On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

Realized gains (losses) on derivative instruments are primarily included in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:

	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains
Natural gas contracts	8.3 Dth	$	(0.3	)	— Dth	$	—
Petroleum products contracts	0.6 gallons	0.1			— gallons	—
FTRs	2.0 MWh	3.0			2.1 MWh	0.2
Total		$	2.8			$	0.2

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	21.3 Dth	$	(2.0	)	5.1 Dth	$	(0.5	)
Petroleum products contracts	1.3 gallons	0.2			— gallons	—
FTRs	4.4 MWh	5.9			4.3 MWh	0.7
Total		$	4.1			$	0.2

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2018 and December 31, 2017, we had posted cash collateral of $0.8 million and $4.9 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets.

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

	June 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	9.6		$	0.8		$	3.5		$	2.8
Gross amount not offset on the balance sheet	(0.5		)	(0.5		)	(1.1		)	(2.3		)	*
Net amount	$	9.1		$	0.3		$	2.4		$	0.5

* Includes cash collateral posted of $1.2 million.

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GUARANTEES

6 Months Ended

Jun. 30, 2018

Guarantees [Abstract]

GUARANTEES

GUARANTEES

As of June 30, 2018, we had $20.6 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

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EMPLOYEE BENEFITS

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS

Through December 31, 2016, we participated in the Integrys Energy Group Retirement Plan, a noncontributory, qualified pension plan sponsored by WBS. We were responsible for our share of the plan assets and obligations. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. As a result, assets were transferred out of our plan in January 2017. See Note 15, Related Parties, for more information.

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	2.6		$	1.9		$	5.2		$	4.5
Interest cost	6.5			6.6			13.0			13.4
Expected return on plan assets	(11.9		)	(11.7		)	(24.1		)	(23.2		)
Amortization of net actuarial loss	5.5			4.3			10.5			8.6
Net periodic benefit cost	$	2.7		$	1.1		$	4.6		$	3.3

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.5		$	1.5		$	3.1		$	3.1
Interest cost	2.1			2.3			4.1			4.7
Expected return on plan assets	(4.5		)	(4.1		)	(8.9		)	(8.2		)
Amortization of prior service credit	(2.9		)	(2.3		)	(5.7		)	(4.6		)
Amortization of net actuarial loss	0.6			0.6			1.2			1.2
Net periodic benefit credit	$	(3.2	)	$	(2.0	)	$	(6.2	)	$	(3.8	)

During the six months ended June 30, 2018, we made contributions and payments of $0.3 million related to our pension plans and $0.1 million related to our OPEB plans. We expect to make contributions and payments of $0.4 million related to our pension plans and $0.1 million related to our OPEB plans during the remainder of 2018, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for thethree and six months ended June 30,2018and2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service components in other income, net.

The following table shows the non-service credit components of net benefit costs:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Non-service credit components	$	(3.8	)	$	(2.9	)	$	(8.3	)	$	(5.7	)

For the three and six months ended June 30, 2017, the net credits from the non-service components of net benefit cost were reclassified from other operation and maintenance to other income, net, on our income statements.

Under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, are presented as regulatory assets or liabilities rather than property, plant, and equipment.

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GOODWILL AND OTHER INTANGIBLE ASSETS

6 Months Ended

Jun. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL AND OTHER INTANGIBLE ASSETS

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no changes to the carrying amount of goodwill during the six months ended June 30, 2018 and 2017.

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

	June 30, 2018							December 31, 2017
(in millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	8.3	$	(6.2	)	$	2.1	$	8.3	$	(5.6	)	$	2.7
Unamortized intangible assets	0.4		—			0.4		0.4		—			0.4
Total intangible assets	$	8.7	$	(6.2	)	$	2.5	$	8.7	$	(5.6	)	$	3.1

* 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 amortization period at June 30, 2018 was approximately two years.

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SEGMENT INFORMATION

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2018, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in northeastern Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in northeastern Wisconsin.

The other segment includes non-utility activities, as well as equity earnings from our investment in WRPC.

The following tables show summarized financial information for the three and six months ended June 30, 2018 and 2017, related to our reportable segments:

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Three Months Ended June 30, 2018
Operating revenues	$	350.1	$	—		$	350.1
Other operation and maintenance	105.2		0.2			105.4
Depreciation and amortization	33.6		—			33.6
Operating income (loss)	72.6		(0.2		)	72.4
Other income, net	7.9		0.9			8.8
Interest expense	13.2		—			13.2

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Three Months Ended June 30, 2017
Operating revenues	$	341.6	$	—		$	341.6
Other operation and maintenance *	108.5		0.3			108.8
Depreciation and amortization	34.5		(0.1		)	34.4
Operating income (loss) *	58.3		(0.2		)	58.1
Other income, net *	4.5		1.4			5.9
Interest expense	13.6		—			13.6

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Six Months Ended June 30, 2018
Operating revenues	$	743.7	$	—		$	743.7
Other operation and maintenance	207.9		0.2			208.1
Depreciation and amortization	69.5		—			69.5
Operating income (loss)	141.9		(0.3		)	141.6
Other income, net	16.8		1.3			18.1
Interest expense	26.0		—			26.0

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Six Months Ended June 30, 2017
Operating revenues	$	731.2	$	—		$	731.2
Other operation and maintenance *	215.5		0.5			216.0
Depreciation and amortization	68.9		(0.1		)	68.8
Operating income (loss) *	131.5		(0.4		)	131.1
Other income, net *	9.8		1.8			11.6
Interest expense	27.5		—			27.5

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

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RELATED PARTIES

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

RELATED PARTIES

RELATED PARTIES

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

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.

Prior to January 1, 2017, we held a 10.37% investment in WPSI which held an approximate 34% interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our $67.2 million ownership interest in WPSI to another subsidiary of Integrys. In addition, during 2017 we transferred $41.9 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.

We provide services to WRPC under an operating agreement approved by the PSCW. We are also a party to a service agreement with WRPC where we are billed for services provided by WRPC. Services are billed to and from WRPC under these agreements at a fully allocated cost.

Our balance sheets included the following receivables and payables related to transactions entered into with certain related parties:

(in millions)	June 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	0.5	$	0.7
Accounts payable
Network transmission services from ATC	8.8		9.0
Liability related to income tax allocation
Integrys	3.8		4.1

The following table shows activity associated with our related party transactions:

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2018		2017		2018		2017
Transactions with WE (1)
Billings to WE	$	1.9	$	1.1	$	5.1	$	2.2
Billings from WE	4.3		5.2		7.3		7.7
Transactions with WBS (1)
Billings to WBS (2)	0.3		4.2		0.5		168.3
Billings from WBS (3)	32.5		35.3		85.0		68.2
Transactions with UMERC
Electric sales to UMERC	4.0		4.0		7.7		8.1
Natural gas sales to UMERC	0.3		0.5		1.5		1.6
Transactions with Bluewater (4)
Storage service fees	1.5		—		1.7		—
Transactions related to ATC
Charges to ATC for services and construction	1.5		1.4		3.0		2.8
Charges from ATC for network transmission services	26.5		26.9		53.0		53.9
Refund from ATC related to a FERC audit	6.6		—		6.6		—
Refund from ATC per FERC ROE order	—		—		—		8.9
Transactions with WRPC
Rental payments to WRPC (5)	0.4		0.4		0.7		0.5
Purchases of energy from WRPC (5)	—		—		—		0.5
Charges from WRPC for services	0.6		0.6		1.2		0.8
Charges to WRPC for operations	0.2		0.3		0.4		0.5

⁽¹⁾  Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

⁽²⁾  The six months ended June 30, 2017 included $161.9 million of cash received related to our transfer of pension trust assets in conjunction with the Integrys pension plan split. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017. There were no transfers of assets to WBS for the three and six months ended June 30, 2018, or for the three months ended June 30, 2017.

⁽³⁾  Includes $5.8 million and $29.1 million for the transfer of certain software assets from WBS for the three and six months ended June 30, 2018, respectively. The three and six months ended June 30, 2017 included $9.2 million for the transfer of certain software assets to us.

⁽⁴⁾  WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

⁽⁵⁾  In March 2017, we terminated our power purchase agreement with WRPC and entered into an agreement with WRPC to rent 50% of its hydroelectric power generation facilities.

Upper Michigan Energy Resources Corporation

In December 2016, both the Michigan Public Service Commission and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 9,000 retail electric customers and 5,300 natural gas customers to UMERC, along with approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of the net assets (including the related deferred income tax liabilities) transferred to UMERC from us in 2017 was $20.6 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WE.

WEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017.

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2018

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 matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2018, were $854.6 million.

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 sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territory were designated as partial nonattainment: Door, Manitowoc, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin) and other parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and, to the extent that further appellate review is sought, at the Supreme Court. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case.

In March 2017, President Trump issued an executive order that, among other things, specifically directed the EPA to review the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. The EPA is expected to issue a proposed CPP replacement rule, or decide to rescind the CPP without replacing it, during the third quarter of 2018.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. WEC Energy Group's plan, which includes us, is to work with its industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group's new long-term goal is to reduce CO₂ emissions by approximately 80% below 2005 levels by 2050. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO₂ reduction goals. Options considered include increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 308 MW of coal generation by 2020, including Pulliam power plant and the jointly-owned Edgewater Unit 4 generation units. See Note 4, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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, satisfy the IM BTA requirements. We will retire Pulliam Units 7 and 8 on or before October 31, 2018. See Note 4, Property, Plant, and Equipment, for more information. Therefore, the WPDES permit reissued by the WDNR on June 29, 2018, will not require us to make alterations to the existing water intake at Pulliam Units 7 and 8. Based on the reissued WPDES permit for Weston, 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. There has been an interim EM BTA determination made by the WDNR as part of the reissued WPDES permit for Weston Units 3 and 4, and we intend to extrapolate these results to assess Weston Unit 2. The entrainment study and other technical information will be used by the WDNR to make a final 316(b) determination during the next five year WPDES permit term. At this time, we expect that the WDNR will conclude that the existing cooling tower systems for Weston Units 3 and 4 are BTA for both impingement and entrainment reduction. In addition, the WDNR has initially indicated that based on the low capacity utilization of Weston Unit 2, impingement mortality reduction technology will not be required and further entrainment reduction will not be necessary.  Due to our plans to retire Pulliam Units 7 and 8, we do not believe that BTA determinations for EM will be necessary for these units.

We have also provided information to the WDNR about planned unit retirements. For Pulliam Units 7 and 8, in light of the pending facility retirement, the reissued WPDES permit included an interim BTA determination for the existing barrier net system. We will not be required to conduct monitoring for IM or EM or to submit additional 316(b) information until the next permit renewal application in December 2022.

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

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurizationwastewater requirements. This rule applies to wastewater discharges from our power plant processes in Wisconsin. In February 2018, the Center for Biological Diversity (CBD) filed suit in the U.S. District Court of Arizona challenging the Postponement Rule. In April 2018, the Utility Water Act Group filed a motion to dismiss the CBD suit for lack of subject matter jurisdiction. While the ELG compliance deadlines are postponed, the WDNR has indicated that it will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR has indicated that it will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate approximately $20 million would be required to design and install a dry bottom ash transport system for Weston Unit 3. This estimate reflects the planned retirements of certain of our generation plants as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach 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, we are coordinating the investigation and cleanup of some of these sites 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:

(in millions)	June 30, 2018		December 31, 2017
Regulatory assets	$	114.8	$	116.0
Reserves for future remediation	99.4		99.6

Consent Decrees

Weston and Pulliam Power Plants Consent Decree

In November 2009, the EPA issued an 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 United States District Court for the Eastern District of Wisconsin in March 2013.

We will retire Pulliam Units 7 and 8 on or before October 31, 2018. See Note 4, Property, Plant, and Equipment, for more information about the retirement.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued an 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, WE (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, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, 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.

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit must be retired by September 30, 2018. See Note 4, Property, Plant, and Equipment, for more information about the retirement.

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.

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SUPPLEMENTAL CASH FLOW INFORMATION

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(26.1	)	$	(27.5	)
Cash (paid) for income taxes, net	(8.6		)	(18.5		)
Significant noncash transactions:
Accounts payable related to construction costs	13.0			33.4
Accounts payable related to assets transferred from affiliates	5.5			—
Transfer of ownership in WPSI to another subsidiary of Integrys *	—			67.2
Transfer of net assets to UMERC *	—			21.1

* See Note 15, Related Parties, for more information on these transactions.

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REGULATORY ENVIRONMENT

6 Months Ended

Jun. 30, 2018

Regulated Operations [Abstract]

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

We deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $444.7 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018, is also being deferred for return to ratepayers.

In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires our electric utility operations to use 40% of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 60% is to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce certain regulatory assets for our electric utility operations and is being deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes for our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. During the six months ended June 30, 2018, we reduced our regulatory assets by $13.0 million as a result of the PSCW order.

2018 and 2019 Wisconsin Rates

During April 2017, we, along with WE and WG, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for electric and natural gas customers. Based on the PSCW order, our authorized ROE remains at 10.0%, and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers. Additionally, the agreement allows us to extend, through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to our electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million.

Pursuant to the settlement agreement, we also agreed to adopt, beginning in 2018, the earnings sharing mechanism that has been in place for WE and WG since January 2016, and agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Proposed Solar Generation Projects

On May 31, 2018, we, along with an unaffiliated utility, filed an application with the PSCW to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. We will own 100 MW of the output of each project for a total of 200 MW. Our share of the cost of both projects is estimated to be $260 million.

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NEW ACCOUNTING PRONOUCEMENTS

6 Months Ended

Jun. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, ASU 2018-10, Codification Improvements to Topic 842, Leases, and ASU 2018-11, Targeted Improvements. The main provision of ASU 2016-02 is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. In addition, this ASU expands the required quantitative and qualitative disclosures related to lease agreements. This guidance is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. This guidance must be adopted using a modified retrospective approach and provides for a number of optional transition practical expedients. We expect to apply the package of practical expedients allowed by this ASU which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

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GENERAL INFORMATION (Policies)

6 Months Ended

Jun. 30, 2018

Accounting policies

Consolidation

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation.

Basis of Accounting

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2018, are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

Fair Value Measurement

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 between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

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

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

Derivative Instruments

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

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

New Accounting Pronouncements

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This ASU was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, ASU 2018-10, Codification Improvements to Topic 842, Leases, and ASU 2018-11, Targeted Improvements. The main provision of ASU 2016-02 is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. In addition, this ASU expands the required quantitative and qualitative disclosures related to lease agreements. This guidance is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. This guidance must be adopted using a modified retrospective approach and provides for a number of optional transition practical expedients. We expect to apply the package of practical expedients allowed by this ASU which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We have not yet determined whether we will elect any other practical expedients upon transition. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

Electric

Disaggregation of Operating Revenues

Revenue Recognition

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural gas

Disaggregation of Operating Revenues

Revenue Recognition

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Alternative revenues

Disaggregation of Operating Revenues

Revenue Recognition

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

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ACQUISITION (Tables)

6 Months Ended

Jun. 30, 2018

Business Combinations [Abstract]

Allocation of purchase price

The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base.

(in millions)
Current assets	$	0.2
Net property, plant, and equipment	76.9
Total purchase price	$	77.1

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OPERATING REVENUES (Tables) - Utility segment

6 Months Ended

Jun. 30, 2018

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.

	Wisconsin Public Service Consolidated
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Electric utility	$	292.5	$	574.6
Natural gas utility	56.9		167.5
Total revenues from contracts with customers	349.4		742.1
Other operating revenues	0.7		1.6
Total operating revenues	$	350.1	$	743.7

Revenues from contracts with customers | Electric

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:

	Electric Utility Operating Revenues
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	90.9	$	185.1
Small commercial and industrial	88.4		177.2
Large commercial and industrial	64.9		115.9
Other	2.2		4.3
Total retail revenues	246.4		482.5
Wholesale	35.3		68.9
Resale	8.0		18.1
Other utility revenues	2.8		5.1
Total electric utility revenues	$	292.5	$	574.6

Revenues from contracts with customers | Natural gas

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

	Natural Gas Utility Operations
(in millions)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Residential	$	26.5	$	97.2
Commercial and industrial	15.3		59.3
Total retail revenues	41.8		156.5
Transport	4.0		12.0
Other utility revenues *	11.1		(1.0		)
Total natural gas utility operating revenues	$	56.9	$	167.5

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

Other operating revenues

Disaggregation of Operating Revenues

Operating revenues disaggregated by revenue source

Other Operating Revenues

Other operating revenues consist primarily of the following:

(in millions)	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Late payment charges	$	0.8		$	1.7
Leases	0.1			0.1
Alternative revenues *	(0.2		)	(0.2		)
Total other operating revenues	$	0.7		$	1.6

* Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

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SHORT-TERM DEBT AND LINES OF CREDIT (Tables)

6 Months Ended

Jun. 30, 2018

Short-term Debt [Abstract]

Schedule of short-term borrowings and weighted-average interest rates

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

(in millions, except percentages)	June 30, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	317.2		$	293.1
Weighted-average interest rate on amounts outstanding	2.31		%	1.72		%

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 available capacity under this facility:

(in millions)	Maturity	June 30, 2018
Revolving credit facility	October 2022	$	400.0
Less:
Letters of credit issued inside credit facility		$	1.3
Commercial paper outstanding		317.2
Available capacity under existing agreement		$	81.5

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MATERIALS, SUPPLIES, AND INVENTORIES (Tables)

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

Schedule of inventory

Our inventory consisted of:

(in millions)	June 30, 2018		December 31, 2017
Fossil fuel	$	46.5	$	43.8
Materials and supplies	48.2		40.8
Natural gas in storage	14.1		22.4
Total	$	108.8	$	107.0

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FAIR VALUE MEASUREMENTS (Tables)

6 Months Ended

Jun. 30, 2018

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:

	June 30, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.4	$	—	$	—	$	1.4
Petroleum product contracts	0.1		—		—		0.1
FTRs	—		—		8.0		8.0
Coal contracts	—		0.1		—		0.1
Total derivative assets	$	1.5	$	0.1	$	8.0	$	9.6
Derivative liabilities
Natural gas contracts	$	0.5	$	—	$	—	$	0.5
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	0.5	$	0.3	$	—	$	0.8

	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.8	$	—	$	—	$	0.8
Petroleum product contracts	0.3		—		—		0.3
FTRs	—		—		2.0		2.0
Coal contracts	—		0.4		—		0.4
Total derivative assets	$	1.1	$	0.4	$	2.0	$	3.5
Derivative liabilities
Natural gas contracts	$	2.3	$	—	$	—	$	2.3
Coal contracts	—		0.5		—		0.5
Total derivative liabilities	$	2.3	$	0.5	$	—	$	2.8

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:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Balance at the beginning of period	$	0.7		$	0.6		$	2.0		$	2.0
Purchases	9.0			6.9			9.0			6.9
Settlements	(1.7		)	(1.7		)	(3.0		)	(3.1		)
Balance at the end of period	$	8.0		$	5.8		$	8.0		$	5.8

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:

	June 30, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,166.6	$	1,232.2	$	1,166.2	$	1,302.4

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DERIVATIVE INSTRUMENTS (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative assets and derivative liabilities

The following table shows our derivative assets and derivative liabilities:

	June 30, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	1.3	$	0.4	$	0.8	$	1.9
Petroleum products contracts	0.1		—		0.3		—
FTRs	8.0		—		2.0		—
Coal contracts	—		0.3		—		0.5
Total other current *	$	9.4	$	0.7	$	3.1	$	2.4
Other long-term
Natural gas contracts	$	0.1	$	0.1	$	—	$	0.4
Coal contracts	0.1		—		0.4		—
Total other long-term *	$	0.2	$	0.1	$	0.4	$	0.4
Total	$	9.6	$	0.8	$	3.5	$	2.8

* On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

Estimated notional volumes and realized gain (losses)

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

	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains
Natural gas contracts	8.3 Dth	$	(0.3	)	— Dth	$	—
Petroleum products contracts	0.6 gallons	0.1			— gallons	—
FTRs	2.0 MWh	3.0			2.1 MWh	0.2
Total		$	2.8			$	0.2

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	21.3 Dth	$	(2.0	)	5.1 Dth	$	(0.5	)
Petroleum products contracts	1.3 gallons	0.2			— gallons	—
FTRs	4.4 MWh	5.9			4.3 MWh	0.7
Total		$	4.1			$	0.2

Offsetting Assets and Liabilities

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

	June 30, 2018						December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	9.6		$	0.8		$	3.5		$	2.8
Gross amount not offset on the balance sheet	(0.5		)	(0.5		)	(1.1		)	(2.3		)	*
Net amount	$	9.1		$	0.3		$	2.4		$	0.5

* Includes cash collateral posted of $1.2 million.

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EMPLOYEE BENEFITS (Tables)

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

Schedule of net benefit costs

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:

	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	2.6		$	1.9		$	5.2		$	4.5
Interest cost	6.5			6.6			13.0			13.4
Expected return on plan assets	(11.9		)	(11.7		)	(24.1		)	(23.2		)
Amortization of net actuarial loss	5.5			4.3			10.5			8.6
Net periodic benefit cost	$	2.7		$	1.1		$	4.6		$	3.3

	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Service cost	$	1.5		$	1.5		$	3.1		$	3.1
Interest cost	2.1			2.3			4.1			4.7
Expected return on plan assets	(4.5		)	(4.1		)	(8.9		)	(8.2		)
Amortization of prior service credit	(2.9		)	(2.3		)	(5.7		)	(4.6		)
Amortization of net actuarial loss	0.6			0.6			1.2			1.2
Net periodic benefit credit	$	(3.2	)	$	(2.0	)	$	(6.2	)	$	(3.8	)

Schedule of non-service components of net benefit costs [Table Text Block]

The following table shows the non-service credit components of net benefit costs:

	Three Months Ended June 30						Six Months Ended June 30
(in millions)	2018			2017			2018			2017
Non-service credit components	$	(3.8	)	$	(2.9	)	$	(8.3	)	$	(5.7	)

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GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)

6 Months Ended

Jun. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of identifiable intangible assets other than goodwill

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

	June 30, 2018							December 31, 2017
(in millions)	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Amortized intangible assets *	$	8.3	$	(6.2	)	$	2.1	$	8.3	$	(5.6	)	$	2.7
Unamortized intangible assets	0.4		—			0.4		0.4		—			0.4
Total intangible assets	$	8.7	$	(6.2	)	$	2.5	$	8.7	$	(5.6	)	$	3.1

* 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 amortization period at June 30, 2018 was approximately two years.

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SEGMENT INFORMATION (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of information related to reportable segments

The following tables show summarized financial information for the three and six months ended June 30, 2018 and 2017, related to our reportable segments:

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Three Months Ended June 30, 2018
Operating revenues	$	350.1	$	—		$	350.1
Other operation and maintenance	105.2		0.2			105.4
Depreciation and amortization	33.6		—			33.6
Operating income (loss)	72.6		(0.2		)	72.4
Other income, net	7.9		0.9			8.8
Interest expense	13.2		—			13.2

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Three Months Ended June 30, 2017
Operating revenues	$	341.6	$	—		$	341.6
Other operation and maintenance *	108.5		0.3			108.8
Depreciation and amortization	34.5		(0.1		)	34.4
Operating income (loss) *	58.3		(0.2		)	58.1
Other income, net *	4.5		1.4			5.9
Interest expense	13.6		—			13.6

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Six Months Ended June 30, 2018
Operating revenues	$	743.7	$	—		$	743.7
Other operation and maintenance	207.9		0.2			208.1
Depreciation and amortization	69.5		—			69.5
Operating income (loss)	141.9		(0.3		)	141.6
Other income, net	16.8		1.3			18.1
Interest expense	26.0		—			26.0

(in millions)	Utility		Other			Wisconsin Public Service Corporation Consolidated
Six Months Ended June 30, 2017
Operating revenues	$	731.2	$	—		$	731.2
Other operation and maintenance *	215.5		0.5			216.0
Depreciation and amortization	68.9		(0.1		)	68.8
Operating income (loss) *	131.5		(0.4		)	131.1
Other income, net *	9.8		1.8			11.6
Interest expense	27.5		—			27.5

* Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.

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RELATED PARTIES (Tables)

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

Schedule of related party transactions balance sheet information

Our balance sheets included the following receivables and payables related to transactions entered into with certain related parties:

(in millions)	June 30, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	0.5	$	0.7
Accounts payable
Network transmission services from ATC	8.8		9.0
Liability related to income tax allocation
Integrys	3.8		4.1

Schedule of activity associated with related party transactions

The following table shows activity associated with our related party transactions:

	Three Months Ended June 30				Six Months Ended June 30
(in millions)	2018		2017		2018		2017
Transactions with WE (1)
Billings to WE	$	1.9	$	1.1	$	5.1	$	2.2
Billings from WE	4.3		5.2		7.3		7.7
Transactions with WBS (1)
Billings to WBS (2)	0.3		4.2		0.5		168.3
Billings from WBS (3)	32.5		35.3		85.0		68.2
Transactions with UMERC
Electric sales to UMERC	4.0		4.0		7.7		8.1
Natural gas sales to UMERC	0.3		0.5		1.5		1.6
Transactions with Bluewater (4)
Storage service fees	1.5		—		1.7		—
Transactions related to ATC
Charges to ATC for services and construction	1.5		1.4		3.0		2.8
Charges from ATC for network transmission services	26.5		26.9		53.0		53.9
Refund from ATC related to a FERC audit	6.6		—		6.6		—
Refund from ATC per FERC ROE order	—		—		—		8.9
Transactions with WRPC
Rental payments to WRPC (5)	0.4		0.4		0.7		0.5
Purchases of energy from WRPC (5)	—		—		—		0.5
Charges from WRPC for services	0.6		0.6		1.2		0.8
Charges to WRPC for operations	0.2		0.3		0.4		0.5

⁽¹⁾  Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

⁽²⁾  The six months ended June 30, 2017 included $161.9 million of cash received related to our transfer of pension trust assets in conjunction with the Integrys pension plan split. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017. There were no transfers of assets to WBS for the three and six months ended June 30, 2018, or for the three months ended June 30, 2017.

⁽³⁾  Includes $5.8 million and $29.1 million for the transfer of certain software assets from WBS for the three and six months ended June 30, 2018, respectively. The three and six months ended June 30, 2017 included $9.2 million for the transfer of certain software assets to us.

⁽⁴⁾  WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

⁽⁵⁾  In March 2017, we terminated our power purchase agreement with WRPC and entered into an agreement with WRPC to rent 50% of its hydroelectric power generation facilities.

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COMMITMENTS AND CONTINGENCIES (Tables)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of regulatory assets and reserves related to manufactured gas plant sites

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

(in millions)	June 30, 2018		December 31, 2017
Regulatory assets	$	114.8	$	116.0
Reserves for future remediation	99.4		99.6

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of supplemental cash flow information

	Six Months Ended June 30
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(26.1	)	$	(27.5	)
Cash (paid) for income taxes, net	(8.6		)	(18.5		)
Significant noncash transactions:
Accounts payable related to construction costs	13.0			33.4
Accounts payable related to assets transferred from affiliates	5.5			—
Transfer of ownership in WPSI to another subsidiary of Integrys *	—			67.2
Transfer of net assets to UMERC *	—			21.1

* See Note 15, Related Parties, for more information on these transactions.

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ACQUISITION CONSIDERATION TRANSFERRED (Details) - Forward Wind Energy Center Acquisition $ in Millions	1 Months Ended
	Apr. 30, 2018 USD ($) utility	Apr. 02, 2018 wind_turbines MW
Business Acquisition [Line Items]
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility	2
Number of wind turbines at Forward Wind Energy Center | wind_turbines		86
Capacity of Foward Wind Energy Center | MW		129
Purchase price	$ 172.9
WPS
Business Acquisition [Line Items]
Purchase price	$ 77.1
WPS's share of Forward Wind Energy Center's purchase price	44.60%
Percentage of Forward Wind Energy Center's output purchased by WPS		44.60%

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ACQUISITION - PURCHASE PRICE ALLOCATION (Details) - Forward Wind Energy Center Acquisition - USD ($) $ in Millions	1 Months Ended
	Apr. 30, 2018	Apr. 02, 2018
Business Acquisition [Line Items]
Purchase price	$ 172.9
WPS
Business Acquisition [Line Items]
Current assets		$ 0.2
Net property, plant, and equipment		$ 76.9
Purchase price	$ 77.1

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OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 350.1	$ 341.6	$ 743.7	$ 731.2
Utility segment
Disaggregation of Operating Revenues
Operating revenues	350.1		743.7
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.7		1.6
Utility segment | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	349.4		742.1
Utility segment | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	292.5		574.6
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Operating revenues	$ 56.9		$ 167.5

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OPERATING REVENUES ELECTRIC UTILITY OPERATING REVENUES (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) contract performance_obligations	Jun. 30, 2017 USD ($)
Disaggregation of Operating Revenues
Operating revenues	$ 350.1	$ 341.6	$ 743.7	$ 731.2
Electric
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations			1
Number of contracts | contract			1
Number of days payment is due			30 days
Electric | Wholesale
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations			2
Utility segment
Disaggregation of Operating Revenues
Operating revenues	350.1		$ 743.7
Revenues from contracts with customers | Utility segment | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	349.4		742.1
Revenues from contracts with customers | Utility segment | Electric | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	292.5		574.6
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Operating revenues	90.9		185.1
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	88.4		177.2
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Large commercial and industrial customers
Disaggregation of Operating Revenues
Operating revenues	64.9		115.9
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Operating revenues	2.2		4.3
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Total retail
Disaggregation of Operating Revenues
Operating revenues	246.4		482.5
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Operating revenues	35.3		68.9
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Operating revenues	8.0		18.1
Revenues from contracts with customers | Utility segment | Electric | Transferred over time | Other utility
Disaggregation of Operating Revenues
Operating revenues	$ 2.8		$ 5.1

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OPERATING REVENUES NATURAL GAS UTILITY OPERATING REVENUS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 350.1	$ 341.6	$ 743.7	$ 731.2
Natural gas
Disaggregation of Operating Revenues
Number of days payment is due			30 days
Utility segment
Disaggregation of Operating Revenues
Operating revenues	350.1		$ 743.7
Revenues from contracts with customers | Utility segment | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	349.4		742.1
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Operating revenues	56.9		167.5
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Operating revenues	26.5		97.2
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Operating revenues	15.3		59.3
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Total retail
Disaggregation of Operating Revenues
Operating revenues	41.8		156.5
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Operating revenues	4.0		12.0
Revenues from contracts with customers | Utility segment | Natural gas | Transferred over time | Other utility
Disaggregation of Operating Revenues
Operating revenues	$ 11.1		$ (1.0)

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OPERATING REVENUES OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 350.1	$ 341.6	$ 743.7	$ 731.2
Utility segment
Disaggregation of Operating Revenues
Operating revenues	350.1		743.7
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.7		1.6
Utility segment | Other operating revenues | Late payment charges
Disaggregation of Operating Revenues
Operating revenues	0.8		1.7
Utility segment | Other operating revenues | Leases
Disaggregation of Operating Revenues
Operating revenues	0.1		0.1
Utility segment | Other operating revenues | Alternative revenues
Disaggregation of Operating Revenues
Operating revenues	$ (0.2)		$ (0.2)

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PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	Jun. 30, 2018 USD ($)
Edgewater Unit 4
Property, Plant and Equipment [Line Items]
Property, plant, and equipment, at carrying value	$ 12.3
Plant to be retired, net	14.2
Cost of removal reserve	1.9
Pulliam power plant
Property, Plant and Equipment [Line Items]
Property, plant, and equipment, at carrying value	42.3
Plant to be retired, net	62.1
Cost of removal reserve	19.8
Utility segment
Property, Plant and Equipment [Line Items]
Severance liability	$ 3.6

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SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Short-term borrowings
Commercial paper outstanding	$ 317.2	$ 293.1
Commercial paper
Short-term borrowings
Weighted-average interest rate on amounts outstanding	2.31%	1.72%
Average amount outstanding during the period	$ 278.6
Weighted-average interest rate during the period	2.07%

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SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Revolving credit facility
Letters of credit issued inside credit facility	$ 1.3
Commercial paper outstanding	317.2	$ 293.1
Available capacity under existing agreement	81.5
Credit facility maturing during October 2022
Revolving credit facility
Revolving credit facility	$ 400.0

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MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Fossil fuel	$ 46.5	$ 43.8
Materials and supplies	48.2	40.8
Natural gas in storage	14.1	22.4
Total	$ 108.8	$ 107.0

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INCOME TAXES (Details)	1 Months Ended	3 Months Ended	6 Months Ended
	Dec. 31, 2017	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage			21.00%	35.00%
Total income tax expense, percentage		37.20%	30.80%
Measurement period to complete accounting related to Tax Cuts and Jobs Act	1 year

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FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Assets
Derivative Asset	$ 9.6	$ 3.5
Liabilities
Derivative Liability	0.8	2.8
Fair value measurements on a recurring basis
Assets
Derivative Asset	9.6	3.5
Liabilities
Derivative Liability	0.8	2.8
Fair value measurements on a recurring basis | Level 1
Assets
Derivative Asset	1.5	1.1
Liabilities
Derivative Liability	0.5	2.3
Fair value measurements on a recurring basis | Level 2
Assets
Derivative Asset	0.1	0.4
Liabilities
Derivative Liability	0.3	0.5
Fair value measurements on a recurring basis | Level 3
Assets
Derivative Asset	8.0	2.0
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative Asset	1.4	0.8
Liabilities
Derivative Liability	0.5	2.3
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative Asset	1.4	0.8
Liabilities
Derivative Liability	0.5	2.3
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative Asset	0.0	0.0
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 | Petroleum products contracts
Assets
Derivative Asset	0.1	0.3
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative Asset	0.1	0.3
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative Asset	0.0	0.0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative Asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative Asset	8.0	2.0
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative Asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative Asset	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative Asset	8.0	2.0
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative Asset	0.1	0.4
Liabilities
Derivative Liability	0.3	0.5
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative Asset	0.0	0.0
Liabilities
Derivative Liability	0.0	0.0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative Asset	0.1	0.4
Liabilities
Derivative Liability	0.3	0.5
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative Asset	0.0	0.0
Liabilities
Derivative Liability	$ 0.0	$ 0.0

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FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Balance at the beginning of period	$ 0.7	$ 0.6	$ 2.0	$ 2.0
Purchases	9.0	6.9	9.0	6.9
Settlements	(1.7)	(1.7)	(3.0)	(3.1)
Balance at the end of the period	$ 8.0	$ 5.8	$ 8.0	$ 5.8

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FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Carrying Amount
Carrying value and estimated fair value of financial instruments
Long-term debt, including current portion	$ 1,166.6	$ 1,166.2
Fair Value
Carrying value and estimated fair value of financial instruments
Long-term debt, including current portion	$ 1,232.2	$ 1,302.4

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DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivative asset
Other current derivative assets	$ 9.4	$ 3.1
Other long-term derivative assets	0.2	0.4
Derivative Asset	9.6	3.5
Derivative liability
Other current derivative liabilities	0.7	2.4
Other long-term derivative liabilities	0.1	0.4
Derivative Liability	0.8	2.8
Natural gas contracts
Derivative asset
Other current derivative assets	1.3	0.8
Other long-term derivative assets	0.1	0.0
Derivative liability
Other current derivative liabilities	0.4	1.9
Other long-term derivative liabilities	0.1	0.4
Petroleum products contracts
Derivative asset
Other current derivative assets	0.1	0.3
Derivative liability
Other current derivative liabilities	0.0	0.0
FTRs
Derivative asset
Other current derivative assets	8.0	2.0
Derivative liability
Other current derivative liabilities	0.0	0.0
Coal contracts
Derivative asset
Other current derivative assets	0.0	0.0
Other long-term derivative assets	0.1	0.4
Derivative liability
Other current derivative liabilities	0.3	0.5
Other long-term derivative liabilities	$ 0.0	$ 0.0

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DERIVATIVE INSTRUMENTS - NOTIONAL VOLUMES and GAINS (LOSSES) (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($) MWh MMBTU gal	Jun. 30, 2017 USD ($) MWh MMBTU gal	Jun. 30, 2018 USD ($) MWh MMBTU gal	Jun. 30, 2017 USD ($) MWh MMBTU gal
Realized Gain (Loss)
Gain (Loss)	$ 2.8	$ 0.2	$ 4.1	$ 0.2
Natural gas contracts
Realized Gain (Loss)
Gain (Loss)	$ (0.3)	$ 0.0	$ (2.0)	$ (0.5)
Notional Volumes
Notional sales volumes | MMBTU	8.3	0.0	21.3	5.1
Petroleum products contracts
Realized Gain (Loss)
Gain (Loss)	$ 0.1	$ 0.0	$ 0.2	$ 0.0
Notional Volumes
Notional sales volumes (gallons) | gal	0.6	0.0	1.3	0.0
FTRs
Realized Gain (Loss)
Gain (Loss)	$ 3.0	$ 0.2	$ 5.9	$ 0.7
Notional Volumes
Notional sales volumes | MWh	2.0	2.1	4.4	4.3

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DERIVATIVE INSTRUMENTS - NETTING ARRANGEMENTS AND CASH COLLATERAL (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Cash collateral
Cash collateral in margin accounts	$ 0.8	$ 4.9
Assets
Gross amount recognized on the balance sheet	9.6	3.5
Gross amount not offset on the balance sheet	(0.5)	(1.1)
Net amount	9.1	2.4
Liabilities
Gross amount recognized on balance sheet	0.8	2.8
Gross amount not offset on balance sheet	(0.5)	(2.3)
Net amount	$ 0.3	0.5
Cash collateral posted		$ 1.2

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GUARANTEES (Details) $ in Millions	Jun. 30, 2018 USD ($)
Standby letters of credit
Guarantees
Guarantees with expiration over 3 years	$ 20.6

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EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Components of net periodic benefit cost
Contributions and payments related to pension and OPEB plans			$ 0.4	$ 66.2
Pension Costs
Components of net periodic benefit cost
Service cost	$ 2.6	$ 1.9	5.2	4.5
Interest cost	6.5	6.6	13.0	13.4
Expected return on plan assets	(11.9)	(11.7)	(24.1)	(23.2)
Amortization of net actuarial loss	5.5	4.3	10.5	8.6
Net periodic benefit cost (credit)	2.7	1.1	4.6	3.3
Contributions and payments related to pension and OPEB plans			0.3
Estimated future employer contributions for the remainder of the year	0.4		0.4
Other Postretirement Benefit Costs
Components of net periodic benefit cost
Service cost	1.5	1.5	3.1	3.1
Interest cost	2.1	2.3	4.1	4.7
Expected return on plan assets	(4.5)	(4.1)	(8.9)	(8.2)
Amortization of prior service credit	(2.9)	(2.3)	(5.7)	(4.6)
Amortization of net actuarial loss	0.6	0.6	1.2	1.2
Net periodic benefit cost (credit)	(3.2)	$ (2.0)	(6.2)	$ (3.8)
Contributions and payments related to pension and OPEB plans			0.1
Estimated future employer contributions for the remainder of the year	$ 0.1		$ 0.1

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EMPLOYEE BENEFITS-IMPACT OF ADOPTION OF ASU 2017-07 (Details) - Accounting Standards Update 2017-07 - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service credit components of net benefit cost	$ (3.8)		$ (8.3)
Impact of ASU 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service credit components of net benefit cost		$ (2.9)		$ (5.7)

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GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Goodwill and other intangible assets
Changes to the carrying amount of goodwill	$ 0.0	$ 0.0
Intangible assets other than goodwill
Amortized intangible assets, accumulated amortization	(6.2)		$ (5.6)
Unamortized intangible assets, carrying amount	0.4		0.4
Total intangible assets, gross carrying amount	8.7		8.7
Total intangible assets, net carrying amount	2.5		3.1
Contractual service agreements
Intangible assets other than goodwill
Amortized intangible assets, gross carrying amount	8.3		8.3
Amortized intangible assets, accumulated amortization	(6.2)		(5.6)
Amortized intangible assets, net carrying amount	$ 2.1		$ 2.7
Remaining amortization period	2 years

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SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) segment	Jun. 30, 2017 USD ($)
Segment Reporting [Abstract]
Number of reportable segments | segment			2
Segment reporting information
Operating revenues	$ 350.1	$ 341.6	$ 743.7	$ 731.2
Other operation and maintenance	105.4	108.8	208.1	216.0
Depreciation and amortization	33.6	34.4	69.5	68.8
Operating income (loss)	72.4	58.1	141.6	131.1
Other income, net	8.8	5.9	18.1	11.6
Interest expense	13.2	13.6	26.0	27.5
Regulated Segment | Utility
Segment reporting information
Operating revenues	350.1	341.6	743.7	731.2
Other operation and maintenance	105.2	108.5	207.9	215.5
Depreciation and amortization	33.6	34.5	69.5	68.9
Operating income (loss)	72.6	58.3	141.9	131.5
Other income, net	7.9	4.5	16.8	9.8
Interest expense	13.2	13.6	26.0	27.5
Unregulated Segment | Other
Segment reporting information
Operating revenues	0.0	0.0	0.0	0.0
Other operation and maintenance	0.2	0.3	0.2	0.5
Depreciation and amortization	0.0	(0.1)	0.0	(0.1)
Operating income (loss)	(0.2)	(0.2)	(0.3)	(0.4)
Other income, net	0.9	1.4	1.3	1.8
Interest expense	$ 0.0	$ 0.0	$ 0.0	$ 0.0

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RELATED PARTIES - OTHER TRANSACTIONS (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 01, 2017	Dec. 31, 2017	Jun. 30, 2018	Dec. 31, 2016
Integrys
Related parties
Liability related to income tax allocation		$ 4.1	$ 3.8
WPS Investments, LLC
Related parties
Equity method investment, ownership percentage				10.37%
ATC
Related parties
Equity method investment, ownership percentage			34.00%
Transfer of ownership in WPSI to another subsidiary of Integrys	$ 67.2
Transfer of deferred income tax related to ATC to affiliated company		41.9
Accounts receivable for services provided to ATC		0.7	$ 0.5
Accounts payable to ATC for network transmission services		$ 9.0	$ 8.8

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RELATED PARTIES (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Related parties
Proceeds from assets transferred to related party				$ (23.7)	$ (9.2)
ATC
Related parties
Charges to equity method investee for services, construction, and/or operations		$ 1.5	$ 1.4	3.0	2.8
Billings from related party for services, pass through costs, and other items		26.5	26.9	53.0	53.9
Refund from ATC related to a FERC audit		6.6	0.0	6.6	0.0
Refund from ATC per FERC ROE order		0.0	0.0	0.0	8.9
WRPC
Related parties
Charges to equity method investee for services, construction, and/or operations		0.2	0.3	0.4	0.5
Billings from related party for services, pass through costs, and other items		0.6	0.6	1.2	0.8
Equipment expense		0.4	0.4	0.7	0.5
Purchases from related party		$ 0.0	0.0	$ 0.0	0.5
Rental agreement with WRPC		50.00%		50.00%
WE
Related parties
Charges to equity method investee for services, construction, and/or operations		$ 1.9	1.1	$ 5.1	2.2
Billings from related party for services, pass through costs, and other items		4.3	5.2	7.3	7.7
WBS
Related parties
Charges to equity method investee for services, construction, and/or operations		0.3	4.2	0.5	168.3
Billings from related party for services, pass through costs, and other items		32.5	35.3	85.0	68.2
Proceeds from assets transferred to related party		0.0	0.0	0.0	161.9
Payments for assets received from WBS		5.8	0.0	29.1	9.2
Bluewater
Related parties
Billings from related party for services, pass through costs, and other items		1.5	0.0	1.7	0.0
Purchase price	$ 226.0
Electric | UMERC
Related parties
Sales to related party		4.0	4.0	7.7	8.1
Natural gas | UMERC
Related parties
Sales to related party		$ 0.3	$ 0.5	$ 1.5	$ 1.6

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RELATED PARTIES - UMERC (Details) - UMERC transfer $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Jan. 01, 2017 mile customer
Related parties
Miles of electric distribution lines | mile		600
Miles of natural gas distribution mains | mile		100
Transfer of net assets to UMERC | $	$ 20.6
Electric utility
Related parties
Number of customers | customer		9,000
Natural gas utility segment
Related parties
Number of customers | customer		5,300

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COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Jun. 30, 2018 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 854.6

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COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended	6 Months Ended
	Oct. 31, 2014 compliance_option	Jun. 30, 2018 USD ($) degreecelsius MW	Dec. 31, 2017 USD ($)
Climate Change | Electric
Air quality
Company goal for percentage of carbon dioxide emissions reduction by 2030		40.00%
Long-term company goal for percentage of carbon dioxide emissions reduction by 2050		80.00%
Coal generation capacity expected to be retired by 2020 | MW		308
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius		2
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of compliance options available to meet standard | compliance_option	7
Renewal period for facility permits		5 years
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Renewal period for facility permits		5 years
Expected cost to achieve required emissions reduction		$ 20.0
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Regulatory assets recorded for remediation of manufactured gas plant sites		114.8	$ 116.0
Reserves recorded for remediation of manufactured gas plant sites		$ 99.4	$ 99.6

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SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (26.1)	$ (27.5)
Cash (paid) for income taxes, net	(8.6)	(18.5)
Significant noncash transactions
Accounts payable related to construction costs	13.0	33.4
Transfer of assets from affiliates
Significant noncash transactions
Accounts payable related to assets transferred from affiliates	5.5	0.0
WPSI
Significant noncash transactions
Transfer of ownership in WPSI to another subsidiary of Integrys	0.0	67.2
UMERC
Significant noncash transactions
Transfer of net assets to UMERC	$ 0.0	$ 21.1

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REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended			6 Months Ended
	May 31, 2018 USD ($) MW solar_projects	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017
Regulatory environment
Corporate federal tax rate (as a percent)				21.00%	35.00%
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)			10.00%
Authorized revenue requirement for the ReACT project			$ 275.0
AFUDC			51.0
Estimated cost of the ReACT project, excluding AFUDC			$ 342.0
Percentage of first 50 basis points of additional utility earnings shared with customers			50.00%
Return on equity in excess of authorized amount (as a percent)			0.50%
Tax Cuts And Jobs Act Of 2017
Regulatory environment
Change in deferred taxes from tax legislation		$ 444.7
Electric rates | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce certain regulatory assets	40.00%
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	60.00%
Decrease in Regulatory Assets Related to PSCW Tax Legislation Ruling				$ 13.0
Natural gas rates | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	100.00%
Badger Hollow and Two Creeks Solar Farms [Member] | Public Service Commission of Wisconsin (PSCW)
Regulatory environment
Number of Solar Projects in WI that WPS Filed with the PSCW to Acquire an Interest In | solar_projects	2
WPS Ownership Interest in Badger Hollow and Two Creeks | MW	100
WPS Total Ownership Capacity in Badger Hollow and Two Creeks | MW	200
WPS Total Share of Cost of Badger Hollow and Two Creeks	$ 260.0