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 SeptemberJune 30, 20162017

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, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," and "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
September June 30, 20162017

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.

 

Table of Contents

WISCONSIN PUBLIC SERVICE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended SeptemberJune 30, 20162017
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
Common Equity
6
 
 
Note 3
Short-Term Debt and Lines of Credit
7
 
 
Note 4
Materials, Supplies, and Inventories
7
Note 5
Fair Value Measurements
7
 
 
Note 56
Derivative Instruments
9
 
 
Note 67
Guarantees
10
 
 
Note 78
Employee Benefits
11
 
 
Note 89
Goodwill and Other Intangible Assets
11
 
 
Note 910
Segment Information
12
 
 
Note 1011
Related Parties
13
 
 
Note 1112
Commitments and Contingencies
14
Note 12
Supplemental Cash Flow Information
1815
 
 
Note 13
Regulatory EnvironmentSupplemental Cash Flow Information
1819
 
 
Note 14
Regulatory Environment
19
Note 15
New Accounting Pronouncements
1920
 
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2122
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
3135
ITEM 4.
CONTROLS AND PROCEDURES
3236
PART II.
OTHER INFORMATION
3337
ITEM 1.
LEGAL PROCEEDINGS
3337
ITEM 1A.
RISK FACTORS
3337
ITEM 6.
EXHIBITS
3438
SIGNATURE
3539


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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates
ATC American Transmission Company LLC
BluewaterBluewater Natural Gas Holding, LLC
Integrys Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
UMERC Upper Michigan Energy Resources Corporation
WBS WEC Business Services LLC
WEC Energy Group WEC Energy Group, Inc. (previously known as Wisconsin Energy Corporation)
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
MPSC Michigan Public Service 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
AIAAffiliated Interest Agreement
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
CAIR
CO2
 Clean Air Interstate RuleCarbon Dioxide
CSAPR Cross-State Air Pollution Rule
GHG Greenhouse Gas
MATSMercury and Air Toxics Standards
NAAQS National Ambient Air Quality Standards
NOV Notice of Violation
NOx Nitrogen Oxide
SO2
 Sulfur Dioxide
   
Measurements
BtuBritish Thermal Units
Dth Dekatherm(s) (One Dth equals one million Btu)
MWMegawatt (One MW equals one million Watts)Dekatherm
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
SSRSystem Support Resource
Supreme Court United States Supreme Court


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, 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 Annual Report on Form 10-K for the year ended December 31, 2015,2016, 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 adjustmentsthe ability to our ROE,earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;

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

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

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

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

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

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

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

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


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

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

The investment performance of 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 termstiming, costs, and conditions ofanticipated benefits associated with the governmental and regulatory approvals ofremaining integration efforts relating to Wisconsin Energy Corporation's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;

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

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

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

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

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


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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) Three Months Ended Nine Months Ended Three Months Ended Six Months Ended
 September 30 September 30 June 30 June 30
(in millions) 2016 2015 2016 2015 2017 2016 2017 2016
Operating revenues $381.0
 $390.8
 $1,087.2
 $1,146.1
 $341.6
 $331.5
 $731.2
 $706.2
                
Operating expenses                
Cost of sales 124.8
 141.4
 380.7
 466.3
 130.5
 113.5
 295.4
 255.9
Other operation and maintenance 110.1
 120.3
 359.3
 356.0
 105.9
 134.1
 210.3
 249.2
Depreciation and amortization 30.7
 30.4
 91.7
 90.5
 34.4
 30.2
 68.8
 61.0
Property and revenue taxes 10.1
 10.2
 29.9
 30.7
 9.8
 10.3
 19.9
 19.8
Total operating expenses 275.7
 302.3
 861.6
 943.5
 280.6
 288.1
 594.4
 585.9
                
Operating income 105.3
 88.5
 225.6
 202.6
 61.0
 43.4
 136.8
 120.3
                
Other income, net 8.9
 6.7
 25.7
 19.8
 3.0
 8.9
 5.9
 16.8
Interest expense 11.7
 13.2
 35.3
 40.3
 13.6
 11.7
 27.5
 23.6
Other expense (2.8) (6.5) (9.6) (20.5) (10.6) (2.8) (21.6) (6.8)
                
Income before income taxes 102.5
 82.0
 216.0
 182.1
 50.4
 40.6
 115.2
 113.5
Income tax expense 37.8
 31.0
 80.5
 67.9
 19.7
 14.3
 45.2
 42.7
Net income 64.7
 51.0
 135.5
 114.2
 $30.7
 $26.3
 $70.0
 $70.8
        
Preferred stock dividend requirements —
 (0.7) —
 (2.3)
Net income attributed to common shareholder $64.7
 $50.3
 $135.5
 $111.9

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


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WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, June 30, December 31,
(in millions, except share and per share amounts) 2016 2015 2017 2016
Assets  
  
  
  
Current assets        
Cash and cash equivalents $3.9
 $6.1
 $26.6
 $3.1
Collateral on deposit 19.2
 17.6
 21.2
 16.1
Accounts receivable and unbilled revenues, net of reserves of $3.7 and $2.5, respectively 165.7
 164.0
Accounts receivable and unbilled revenues, net of reserves of $4.0 and $3.0, respectively 177.0
 194.7
Receivables from related parties 3.5
 3.1
 5.6
 3.0
Materials, supplies, and inventories  
   112.4
 125.3
Fuel and gas 90.0
 104.5
Materials and supplies, at average cost 42.5
 40.5
Prepaid taxes 28.7
 48.1
 46.4
 57.3
Other current assets 7.5
 9.4
Other 8.4
 8.4
Current assets 361.0
 393.3
 397.6
 407.9
        
Long-term assets        
Property, plant, and equipment, net of accumulated depreciation of $1,582.4 and $1,565.7, respectively 3,553.3
 3,418.6
Property, plant, and equipment, net of accumulated depreciation of $1,624.7 and $1,595.1, respectively 3,695.8
 3,662.0
Regulatory assets 443.6
 462.5
 453.5
 465.8
Goodwill 36.4
 36.4
 36.4
 36.4
Pension and OPEB assets 113.4
 102.4
 26.8
 114.8
Other long-term assets 121.3
 91.9
Other 54.8
 121.3
Long-term assets 4,268.0
 4,111.8
 4,267.3
 4,400.3
Total assets $4,629.0
 $4,505.1
 $4,664.9
 $4,808.2
        
Liabilities and Shareholder's Equity  
    
  
Current liabilities        
Short-term debt $148.5
 $182.8
 $131.9
 $176.8
Current portion of long-term debt to parent —
 2.9
Current portion of long-term debt 125.0
 125.0
Accounts payable 111.8
 181.8
 115.5
 165.4
Payables to related parties 20.2
 35.6
 23.8
 21.6
Accrued taxes 50.0
 3.1
Accrued interest 20.2
 6.8
Other current liabilities 40.5
 40.3
Other 64.0
 64.2
Current liabilities 391.2
 453.3
 460.2
 553.0
        
Long-term liabilities        
Long-term debt 1,289.9
 1,289.4
 1,165.7
 1,165.3
Deferred income taxes 859.6
 774.1
 898.7
 929.5
Deferred investment tax credits 7.1
 7.4
 6.9
 7.0
Regulatory liabilities 278.2
 290.0
 303.3
 291.3
Environmental remediation liabilities 82.2
 83.5
 96.3
 97.2
Pension and OPEB obligations 24.3
 24.4
 27.2
 25.4
Payables to related parties 4.3
 4.8
 3.8
 4.1
Other long-term liabilities 104.7
 92.3
Other 109.9
 107.2
Long-term liabilities 2,650.3
 2,565.9
 2,611.8
 2,627.0
        
Commitments and contingencies (Note 11) 

 

Commitments and contingencies (Note 12) 

 

        
Shareholder's equity        
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding 95.6
 95.6
 95.6
 95.6
Additional paid in capital 916.8
 861.8
 996.6
 966.9
Retained earnings 575.1
 528.5
 500.7
 565.7
Shareholder's equity 1,587.5
 1,485.9
 1,592.9
 1,628.2
Total liabilities and shareholder's equity $4,629.0
 $4,505.1
 $4,664.9
 $4,808.2

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

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WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended Six Months Ended
 September 30 June 30
(in millions) 2016 2015 2017 2016
Operating Activities  
  
  
  
Net income $135.5
 $114.2
 $70.0
 $70.8
Reconciliation to cash provided by operating activities  
  
  
  
Depreciation and amortization 93.2
 91.9
 68.8
 62.0
Deferred income taxes and investment tax credits, net 76.9
 36.8
 18.2
 50.4
Contributions and payments related to pension and OPEB plans (66.2) (1.0)
Cash received for pension plan assets transferred 161.9
 —
Change in –  
    
  
Accounts receivable and unbilled revenues (5.4) 40.9
 10.6
 (3.3)
Materials, supplies, and inventories 13.0
 (4.1) 13.3
 29.5
Prepaid taxes 19.4
 34.7
 10.9
 10.4
Other current assets 0.5
 (13.0) (2.5) 0.4
Accounts payable (54.0) (5.4) (14.6) (27.4)
Accrued taxes 46.9
 15.8
 0.7
 30.2
Other current liabilities 16.8
 9.1
 (0.4) (4.5)
Other, net (14.3) (0.9) 9.7
 15.9
Net cash provided by operating activities 328.5
 320.0
 280.4
 233.4
        
Investing Activities  
  
  
  
Capital expenditures (235.0) (268.3) (144.3) (154.1)
Proceeds from (payments for) assets transferred to (from) WBS (9.2) 7.3
Other, net 4.2
 (1.6) 1.4
 (2.6)
Net cash used in investing activities (230.8) (269.9) (152.1) (149.4)
        
Financing Activities  
  
  
  
Change in short-term debt (34.3) (43.0) (44.8) (50.2)
Repayment of loan (28.6) —
 —
 (28.6)
Preferred stock dividend requirements —
 (2.3)
Repayment of long-term debt to parent (2.9) (2.4) —
 (2.9)
Payment of dividends to parent (88.9) (86.3) (135.0) (59.3)
Equity contribution from parent 55.0
 85.0
 75.0
 55.0
Other, net (0.2) (3.6) —
 (0.1)
Net cash used in financing activities (99.9) (52.6) (104.8) (86.1)
        
Net change in cash and cash equivalents (2.2) (2.5) 23.5
 (2.1)
Cash and cash equivalents at beginning of period 6.1
 5.4
 3.1
 6.1
Cash and cash equivalents at end of period $3.9
 $2.9
 $26.6
 $4.0

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


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WISCONSIN PUBLIC SERVICE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
SeptemberJune 30, 20162017

NOTE 1—GENERAL INFORMATION

On June 29, 2015, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group, Inc. In this report, when we refer to the "WEC Merger," we are referring to this acquisition.

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",Company," "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation and its former subsidiary, WPS Leasing, Inc., which was dissolved in July 2016.

Prior to January 1, 2017, we held a 10.37% investment in WPSI, which was accounted for as an equity method investment. WPSI holds 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 ownership interest in WPSI to another subsidiary of Integrys. See Note 11, Related Parties, for more information on the transfer.

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. UMERC holds the electric and natural gas distribution assets, previously held by WE and us, located in the Upper Peninsula of Michigan. See Note 11, Related Parties, and Note 14, Regulatory Environment, for more information on UMERC.

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, 2015.2016. 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 ninesix months ended SeptemberJune 30, 2016,2017, are not necessarily indicative of expected results for 20162017 due to seasonal variations and other factors.

Our balance sheets reflect the historical basis of our assets and liabilities, as WEC Energy Group did not elect pushdown accounting for the WEC Merger. This is consistent with how our financial statements are viewed by our regulators.

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

Reclassifications

As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC Energy Group. On the income statements for the nine months ended September 30, 2015, we reclassified$3.9 million from other operation and maintenance to cost of sales. This reclassification was made to be consistent with the current year presentation. There were no reclassifications for the three months ended September 30, 2015.

During the second quarter of 2016, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 9, Segment Information, for more information on our business segments.

NOTE 2—COMMON EQUITY

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. As we did not have any excess tax benefits that had not been recognized in prior years, we were not required to record a cumulative-effect adjustment to retained earnings as a result of the adoption of this ASU.

This ASU also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. We have elected to apply this provision on a prospective basis. As allowed under the ASU, we have also elected to account for forfeitures as they occur, rather than estimating expected forfeitures and recording them over the vesting period.

As we were not required to record a cumulative-effect adjustment to retained earnings, and we did not record any excess tax benefits in 2017, adoption of this ASU had no impact on our financial statements.

Restrictions

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

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making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their subsidiaries. See Note 11,10, Common Equity, in our 20152016 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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NOTE 3—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) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Commercial paper        
Amount outstanding $148.5
 $182.8
 $131.9
 $176.8
Weighted-average interest rate on amounts outstanding 0.68% 0.66% 1.32% 1.01%

Our average amount of commercial paper borrowings based on daily outstanding balances during the ninesix months ended SeptemberJune 30, 2016,2017, was $140.8$137.9 million with a weighted-average interest rate during the period of 0.58%1.04%.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility:
(in millions) Maturity September 30, 2016 Maturity June 30, 2017
Revolving credit facility December 2020 $250.0
 December 2020 $250.0
    
Less: commercial paper outstanding   $148.5
   $131.9
Available capacity under existing agreement   $101.5
   $118.1

NOTE 4—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:
(in millions) June 30, 2017 December 31, 2016
Fossil fuel $55.6
 $66.7
Materials and supplies 40.8
 37.5
Natural gas in storage 16.0
 21.1
Total $112.4
 $125.3

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

NOTE 4—5—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.


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

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

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

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


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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:
 September 30, 2016 June 30, 2017
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Derivative assets  
  
  
  
  
  
  
  
Natural gas contracts $0.7
 $—
 $—
 $0.7
 $0.3
 $—
 $—
 $0.3
Petroleum product contracts 0.1
 —
 —
 0.1
FTRs —
 —
 3.8
 3.8
 —
 —
 5.8
 5.8
Total derivative assets $0.7
 $—
 $3.8
 $4.5
 $0.4
 $—
 $5.8
 $6.2
                
Derivative liabilities  
  
  
  
  
  
  
  
Natural gas contracts $0.1
 $—
 $—
 $0.1
 $0.6
 $—
 $—
 $0.6
Coal contracts —
 2.2
 —
 2.2
 —
 1.1
 —
 1.1
Total derivative liabilities $0.1
 $2.2
 $—
 $2.3
 $0.6
 $1.1
 $—
 $1.7

 December 31, 2015 December 31, 2016
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Derivative assets                
Natural gas contracts $0.3
 $—
 $—
 $0.3
 $0.1
 $0.1
 $—
 $0.2
FTRs —
 —
 2.0
 2.0
 —
 —
 2.0
 2.0
Coal contracts —
 0.1
 —
 0.1
Total derivative assets $0.3
 $—
 $2.0
 $2.3
 $0.1
 $0.2
 $2.0
 $2.3
                
Derivative liabilities                
Natural gas contracts $0.9
 $—
 $—
 $0.9
Petroleum products contracts 0.5
 —
 —
 0.5
Coal contracts —
 4.7
 —
 4.7
 $—
 $1.4
 $—
 $1.4
Total derivative liabilities $1.4
 $4.7
 $—
 $6.1

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

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The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended June 30 Six Months Ended June 30
(in millions) 2016 2015 2016 2015 2017 2016 2017 2016
Balance at the beginning of period $5.9
 $(1.3) $2.0
 $(0.3) $0.6
 $0.5
 $2.0
 $2.0
Net realized and unrealized gains (losses) —
 0.2
 (0.2) (11.2)
Net realized and unrealized losses —
 —
 —
 (0.2)
Purchases —
 —
 7.1
 9.8
 6.9
 7.1
 6.9
 7.1
Sales —
 —
 (0.2) —
 —
 (0.1) —
 (0.2)
Settlements (2.1) (1.0) (4.9) (0.4) (1.7) (1.6) (3.1) (2.8)
Balance at the end of period $3.8
 $(2.1) $3.8
 $(2.1) $5.8
 $5.9
 $5.8
 $5.9

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


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Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
  September 30, 2016 December 31, 2015
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt $1,289.9
 $1,474.6
 $1,289.4
 $1,350.4
Long-term debt to parent, including current portion * —
 —
 2.9
 3.0
  June 30, 2017 December 31, 2016
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current portion $1,290.7
 $1,398.9
 $1,290.3
 $1,373.4

*Our former consolidated subsidiary, WPS Leasing, Inc., had a note payable to our parent company, Integrys, that was paid off in May 2016.

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings,debt, the carrying amount for each such item approximates fair value. The fair valuesvalue of our long-term debt including the current portion of long-term debt, areis estimated based on the quoted market prices for the same or similar issues. The fair value of our long-term debtissues and is categorized within Level 2 of the fair value hierarchy.

NOTE 5—6—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. RegulatedOur regulated hedging programs are approved by the PSCW and the MPSC.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, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.


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The following table shows our derivative assets and derivative liabilities:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current *        
Other current        
Natural gas contracts $0.7
 $0.1
 $0.3
 $0.9
 $0.3
 $0.5
 $0.2
 $—
Petroleum products contracts —
 —
 —
 0.5
 0.1
 —
 —
 —
FTRs 3.8
 —
 2.0
 —
 5.8
 —
 2.0
 —
Coal contracts —
 1.4
 —
 3.3
 —
 0.8
 —
 0.9
Total other current 4.5
 1.5
 2.3
 4.7
Total other current * $6.2
 $1.3
 $2.2
 $0.9
                
Other long-term *        
Other long-term        
Natural gas contracts $—
 $0.1
 $—
 $—
Coal contracts —
 0.8
 —
 1.4
 —
 0.3
 0.1
 0.5
Total other long-term * $—
 $0.4
 $0.1
 $0.5
Total $4.5
 $2.3
 $2.3
 $6.1
 $6.2
 $1.7
 $2.3
 $1.4

*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.


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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 September 30, 2016 Three Months Ended September 30, 2015 Three Months Ended June 30, 2017 Three Months Ended June 30, 2016
(in millions) Volumes Gains Volumes Gains (Losses) Volumes Gains Volumes Gains (Losses)
Natural gas contracts 6.0 Dth $0.5
 3.7 Dth $(0.7) — Dth $—
 2.1 Dth $—
Petroleum products contracts 1.0 gallons —
 1.5 gallons (0.4)       — gallons —
 1.0 gallons (0.2)
FTRs 2.2 MWh 2.6
 2.5 MWh 1.6
 2.1 MWh 0.2
 1.7 MWh 1.1
Total   $3.1
   $0.5
   $0.2
   $0.9
    
 Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 20.0 Dth $(1.3) 14.9 Dth $(3.2)
Petroleum products contracts 3.4 gallons (0.6) 4.7 gallons (1.4)
FTRs 6.3 MWh 4.9
 6.8 MWh 1.4
Total   $3.0
   $(3.2)

  Six Months Ended June 30, 2017
Six Months Ended June 30, 2016
(in millions) Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts 5.1 Dth $(0.5) 14.0 Dth $(1.8)
Petroleum products contracts — gallons —
 2.4 gallons (0.6)
FTRs 4.3 MWh 0.7
 4.1 MWh 2.3
Total   $0.2
   $(0.1)

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 SeptemberJune 30, 2016,2017 and December 31, 2015,2016, we had posted cash collateral of $19.2$21.2 million and $17.6$16.1 million, respectively, in our margin accounts. These amounts primarily relate to cash collateral posted with MISO.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on theour balance sheet:sheets:
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Gross amount recognized on the balance sheet $4.5
 $2.3
 $2.3
 $6.1
 $6.2
 $1.7
 $2.3
 $1.4
Gross amount not offset on the balance sheet * (0.1) (0.1) (0.3) (1.4)
Gross amount not offset on the balance sheet (0.4) (0.6)*—
 —
Net amount $4.4
 $2.2
 $2.0
 $4.7
 $5.8
 $1.1
 $2.3
 $1.4

*Includes cash collateral posted of $1.1 million at December 31, 2015. There was no cash collateral included at September 30, 2016.$0.2 million.

NOTE 6—7—GUARANTEES

The following table shows our outstanding guarantees:
  Total Amounts Committed at Expiration
(in millions) September 30, 2016 Less Than 1 Year Over 3 Years
Standby letters of credit (1)
 $9.4
 $9.4
 $—
Surety bonds (2)
 1.3
 1.3
 —
Other guarantee (3)
 0.6
 —
 0.6
Total guarantees $11.3
 $10.7
 $0.6

(1)
At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts areAs of June 30, 2017, we had a $1.9 million standby letter of credit, due in January 2018, that was issued by a financial institution for the benefit of a third party that extended credit to us. This amount is not reflected on our balance sheets.

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

(3)
Consists of $0.6 million reflected on our balance sheet related to workers compensation.


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NOTE 7—8—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. Assets were transferred out of our plan in January 2017, however we made additional contributions to the plan as discussed below. See Note 11, Related Parties, for more information.

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:
 Pension Costs Pension Costs
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended June 30 Six Months Ended June 30
(in millions) 2016 2015 2016 2015 2017 2016 2017 2016
Service cost $2.3
 $2.6
 $6.9
 $8.0
 $1.9
 $2.1
 $4.5
 $4.6
Interest cost 6.9
 8.0
 20.7
 23.8
 6.6
 7.0
 13.4
 13.8
Expected return on plan assets (12.9) (16.3) (38.9) (48.7) (11.7) (13.2) (23.2) (26.0)
Gain (loss) on plan settlement (0.1) —
 3.1
 0.1
Amortization of prior service cost —
 0.1
 —
 0.2
Loss on plan settlement —
 3.2
 —
 3.2
Amortization of net actuarial loss 4.3
 5.3
 13.0
 15.8
 4.3
 4.5
 8.6
 8.7
Net periodic benefit cost (credit) $0.5
 $(0.3) $4.8
 $(0.8)
Net periodic benefit cost $1.1
 $3.6
 $3.3
 $4.3

 OPEB Costs OPEB Costs
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended June 30 Six Months Ended June 30
(in millions) 2016 2015 2016 2015 2017 2016 2017 2016
Service cost $1.8
 $2.2
 $5.5
 $6.5
 $1.5
 $1.9
 $3.1
 $3.7
Interest cost 2.6
 2.6
 7.9
 7.8
 2.3
 2.7
 4.7
 5.3
Expected return on plan assets (3.9) (4.0) (11.9) (12.0) (4.1) (4.0) (8.2) (8.0)
Amortization of prior service credit (1.9) (2.3) (5.6) (6.9) (2.3) (1.9) (4.6) (3.7)
Amortization of net actuarial loss 0.7
 0.8
 1.9
 2.7
 0.6
 0.6
 1.2
 1.2
Net periodic benefit credit $(0.7) $(0.7) $(2.2) $(1.9) $(2.0) $(0.7) $(3.8) $(1.5)

We did not make any contributions to our qualified pension plans during the first nine months of 2016. During the ninesix months ended SeptemberJune 30, 2016,2017, we made payments of $1.2$65.4 million related to our non-qualified pension plans. We did not make any paymentsplans and $0.8 million to our OPEB plans during the nine months ended September 30, 2016.plans. We expect to make payments of $0.2$0.3 million related to our non-qualified pension plans and $0.1 million related to our OPEB plans during the remainder of 2016,2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to contribute to the OPEB plans during the remainder of 2017.

NOTE 8—9—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 ninesix months ended SeptemberJune 30, 2016,2017 and 2015.

Due to the WEC Merger, we changed the date of our annual goodwill impairment test from April 1 to July 1. Since no more than 12 months is allowed to elapse between impairment tests, we performed a step zero qualitative impairment test as of April 1, 2016, and a quantitative impairment test as of July 1, 2016. No impairments resulted from these tests.

The identifiable intangible assets other than goodwill listed below are classified as other long-term assets on our balance sheets.
 September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
(in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount
Amortized intangible assets * $15.6
 $(9.9) $5.7
 $15.6
 $(7.5) $8.1
 $8.3
 $(5.0) $3.3
 $15.6
 $(10.7) $4.9
Unamortized intangible assets 0.4
 —
 0.4
 0.4
 —
 0.4
 0.4
 —
 0.4
 0.4
 —
 0.4
Total intangible assets $16.0
 $(9.9) $6.1
 $16.0
 $(7.5) $8.5
 $8.7
 $(5.0) $3.7
 $16.0
 $(10.7) $5.3

*Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at SeptemberJune 30, 2016,2017, was approximately three years.


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NOTE 9—10—SEGMENT INFORMATION

During the second quarter of 2016, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation.

We use operating income to measure segment profitability and to allocate resources to our businesses. At SeptemberJune 30, 2016,2017, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in northeastern Wisconsin and the Upper Peninsula of Michigan.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 WisconsinWisconsin. Effective January 1, 2017, we transferred our customers and electric and natural gas distribution assets located in the Upper Peninsula of Michigan.Michigan to UMERC. See Note 11, Related Parties, and Note 14, Regulatory Environment, for more information.

TheDuring 2017, the other segment includesincluded non-utility activities, as well as equity earnings from our investment in WRPC. During 2016, the other segment included non-utility activities as well as equity earnings from our investments in WRPC and WPSI, which holds 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, we transferred our 10.37% ownership interest in WPSI to another subsidiary of Integrys. See Note 11, Related Parties, for more information.

The following tables show summarized financial information related to our reportable segments for the three and ninesix months ended SeptemberJune 30, 20162017 and 2015:2016:
(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Three Months Ended September 30, 2016        
Three Months Ended June 30, 2017        
External revenues $381.0
 $—
 $—
 $381.0
 $341.6
 $—
 $—
 $341.6
Intersegment revenues —
 0.1
 (0.1) —
Other operation and maintenance 110.0
 0.2
 (0.1) 110.1
 105.6
 0.3
 —
 105.9
Depreciation and amortization 30.7
 —
 —
 30.7
 34.5
 (0.1) —
 34.4
Operating income (loss) 105.5
 (0.2) —
 105.3
 61.2
 (0.2) —
 61.0
Other income, net 6.3
 2.6
 —
 8.9
 1.6
 1.4
 —
 3.0
Interest expense 11.7
 —
 —
 11.7
 13.6
 —
 —
 13.6

(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Three Months Ended September 30, 2015  
  
    
Three Months Ended June 30, 2016  
  
    
External revenues $390.8
 $—
 $—
 $390.8
 $331.5
 $—
 $—
 $331.5
Intersegment revenues —
 0.2
 (0.2) —
 —
 0.1
 (0.1) —
Other operation and maintenance 120.8
 0.1
 (0.6) 120.3
 134.3
 (0.1) (0.1) 134.1
Depreciation and amortization 30.3
 0.1
 —
 30.4
 30.3
 (0.1) —
 30.2
Operating income 88.4
 0.1
 —
 88.5
 43.1
 0.3
 —
 43.4
Other income, net 4.3
 2.4
 —
 6.7
 6.8
 2.1
 —
 8.9
Interest expense 13.1
 0.1
 —
 13.2
 11.7
 —
 —
 11.7

(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Nine months ended September 30, 2016        
Six Months Ended June 30, 2017        
External revenues $1,087.2
 $—
 $—
 $1,087.2
 $731.2
 $—
 $—
 $731.2
Intersegment revenues —
 0.4
 (0.4) —
Other operation and maintenance 359.5
 0.2
 (0.4) 359.3
 209.8
 0.5
 —
 210.3
Depreciation and amortization 91.7
 —
 —
 91.7
 68.9
 (0.1) —
 68.8
Operating income 225.5
 0.1
 —
 225.6
Operating income (loss) 137.2
 (0.4) —
 136.8
Other income, net 18.5
 7.2
 —
 25.7
 4.1
 1.8
 —
 5.9
Interest expense 35.2
 0.1
 —
 35.3
 27.5
 —
 —
 27.5


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(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Nine months ended September 30, 2015  
  
    
Six Months Ended June 30, 2016  
  
    
External revenues $1,146.1
 $—
 $—
 $1,146.1
 $706.2
 $—
 $—
 $706.2
Intersegment revenues —
 0.6
 (0.6) —
 —
 0.3
 (0.3) —
Other operation and maintenance 356.4
 0.2
 (0.6) 356.0
 249.5
 —
 (0.3) 249.2
Depreciation and amortization 90.2
 0.3
 —
 90.5
 61.0
 —
 —
 61.0
Operating income 202.6
 —
 —
 202.6
 120.0
 0.3
 —
 120.3
Other income, net 11.1
 8.7
 —
 19.8
 12.2
 4.6
 —
 16.8
Interest expense 40.1
 0.2
 —
 40.3
 23.5
 0.1
 —
 23.6

NOTE 10—11—RELATED PARTIES

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

A new AIA took effect January 1, 2016, we, along with2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. In June 2017, the PSCW approved modifications to the new AIA to incorporate WEC Energy Group, filedGroup's acquisition of Bluewater, which is discussed in more detail below. The proposal to incorporate Bluewater into the AIA is pending before the Minnesota Public Utilities Commission.

Prior to January 1, 2017, we held a new agreement10.37% investment in WPSI, which was accounted for approval withas an equity method investment. WPSI holds 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, we transferred $43.1 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 all other relevant state commissions that would replace our current affiliated interest agreements. The PSCW approvedtherefore, did not result in the new agreement in August 2016. We are awaiting approval in one other state before the new agreement will be implemented.recognition of a gain or loss.

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

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

The table below includes information summarizingOur balance sheets included the following receivables and payables related to transactions entered into with related parties:
(in millions) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Accounts receivable        
Services provided to ATC $0.6
 $0.5
 $0.3
 $1.1
Note payable, current portion *  
  
Integrys —
 2.9
Accounts payable  
  
  
  
Network transmission services from ATC 9.2
 8.5
 9.0
 8.8
Liability related to income tax allocation    
    
Integrys 4.9
 5.4
 4.4
 4.8

*WPS Leasing, Inc., our former consolidated subsidiary, had a note payable to our parent company, Integrys, that was paid off in May 2016.


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The following table shows activity associated with our related party transactions:
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended June 30 Six Months Ended June 30
(in millions) 2016 2015 2016 2015 2017 2016 2017 2016
Transactions with equity method investees  
  
    
Transactions with WE (1)
        
Billings to WE $1.1
 $0.6
 $2.2
 $1.0
Billings from WE 5.2
 1.9
 7.7
 2.9
Transactions with WBS (1)
        
Billings to WBS (2)
 4.2
 3.9
 168.3
 13.3
Billings from WBS (3)
 35.3
 45.7
 68.2
 82.4
Transactions with UMERC (4)
        
Electric sales to UMERC 4.0
 —
 8.1
 —
Billings from UMERC (1)
 5.1
 —
 6.7
 —
Transactions related to ATC    
    
Charges from ATC for network transmission services $27.8
 $25.3
 $83.2
 $76.0
 26.9
 27.7
 53.9
 55.4
Charges to ATC for services and construction 2.2
 2.9
 6.2
 7.5
 1.4
 2.0
 2.8
 4.0
Purchases of energy from WRPC 1.0
 1.0
 2.9
 3.1
Refund from ATC per FERC ROE order —
 —
 (8.9) —
Transactions with equity-method investees        
Lease payments to WRPC (5)
 0.4
 —
 0.5
 —
Purchases of energy from WRPC (5)
 —
 0.9
 0.5
 1.9
Charges from WRPC for services 0.6
 —
 0.8
 —
Charges to WRPC for operations 0.2
 0.5
 0.5
 1.0
 0.3
 0.2
 0.5
 0.3
Equity earnings from WPSI (1)
 2.3
 2.5
 6.4
 6.8
        
Transactions with WE        
Billings to WE 1.4
 0.1
 1.9
 0.1
Billings from WE 4.1
 3.4
 7.0
 3.4
        
Transactions with WBS        
Billings to WBS (2)
 4.5
 1.7
 17.8
 6.1
Billings from WBS (3)
 52.8
 31.8
 135.2
 102.3
Equity earnings from WPSI —
 1.8
 —
 4.1

(1) 
WPSI is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by IntegrysIncludes amounts billed for services, pass through costs, and us. WPSI holds an approximate 34% ownership interestother items in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. At September 30, 2016, we had a 10.53% interest in WPSI accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPSI.accordance with approved AIAs.

(2) 
IncludedIncludes $161.9 million of cash received related to our transfer of pension trust assets in conjunction with the amount of billings to WBSIntegrys pension plan split for the ninesix months ended SeptemberJune 30, 20162017. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was $7.3 million forsplit into six separate plans. As a result, we now have our own pension plan. While the transfersplit did not impact our pension benefit obligation, federal regulations required a different allocation of certain software to WBS.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 months ended SeptemberJune 30, 2016.2017. The three and six months ended June 30, 2016, included $0.9 million and $7.3 million, respectively, for the transfer of certain software assets to WBS.

(3) 
Included in the amount of billings from WBS, for the three and nine months ended September 30, 2016, was $12.3Includes $9.2 million and $18.2 million, respectively, for the transfer of certain benefit-related liabilitiessoftware assets to WBS.us for the three and six months ended June 30, 2017. There were no transfers of software assets to us for the three and six months ended June 30, 2016.

(4)
UMERC became operational effective January 1, 2017. See below for more information.

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

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 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 as of January 1, 2017, was $21.1 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 obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WE.


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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 will provide for some of our current storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement with Bluewater to take the allocated storage. See Note 14, Regulatory Environment, for more information.

NOTE 11—12—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.

Energy Related Purchased Power AgreementsUnconditional 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 SeptemberJune 30, 2016,2017, were $940.6$903.0 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 that may potentially affectaffecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

Cross-State Air Pollution Rule 

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the CAIR.Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation plan and allowance trading scheme. The rule was to become effectiveplan. After several lawsuits and related appeals, in January 2012.

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However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit Court of Appeals, and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the Supreme Court. In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I emissions budgetsof the rule applied in 2015 and also apply in 2016, while the Phase II emissions budgets discussed below will apply to 2017 and beyond.

In December 2015, theThe EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015, and issued the final rule in September 2016. Starting in 2017,We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule requires reductions in the ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOxozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We are currently evaluating compliance options that include using our banked allowances, purchasing allowances, implementing natural gas co-firing at certain of our coal plants, and other NOx control optimizations.rule.

Sulfur Dioxide National Ambient Air Quality Standards

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

In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, we believe the WDNR will recommend by January 2017 thatprovided final modeling to the EPA demonstrating the area around the Weston Power Plant to be designated attainment.in compliance. We expect that the EPA will consider the WDNR's recommendation and finalize its recommendationdesignation by the end of 2017.

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


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8-Hour Ozone National Ambient Air Quality Standards

TheSheboygan County is currently designated as nonattainment with the 2008 ozone standard. Wisconsin has prepared a draft attainment plan for Sheboygan County, which is out for public comment and is expected to submit a final plan to the EPA completedfor approval this summer. A final EPA action regarding Wisconsin's attainment plan is expected later in 2017.

After completing its review of the 2008 8-hour ozone standard, in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released thea final rule in October 2015, which lowered the limit for ground-level ozone.ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment designations for someWisconsin's Lake Michigan shoreline counties in Wisconsin(or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 20202020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

Although we are still in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

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

We believe that our fleet is well positioned to comply with this regulation. Controls for acid gasesmeet the ozone standard and mercury are already in operation at the Pulliam units, and our compliance plans currently include capital projects for our jointly owned plantsdo not expect to achieve the required reductions for MATS. Construction of the ReACTTM multi-pollutant control system at Weston Unit 3 is complete and testing was completed on schedule. We are currently in compliance with both MATS and the WPS Consent Decree emission requirements.incur significant costs to comply.

Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for

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modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units,CPP, numerous states (including Wisconsin), trade associations, and privateother parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the ruleCPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The D.C. Circuit Court of Appeals heard theone case in September 2016.2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

The final rule for existing fossil-fueled generating unitsCPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would have been required to submit final plans by September 2018, either alone or in conjunction with other states. The time lines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, may be changed due to the stay and subsequent legal proceedings.

The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin of 41% below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to determine each state'sreview, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction requirements include a combinationgoals and all other aspects of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. Wethe CPP are inuncertain. In April 2017, the process of reviewingEPA withdrew the finalproposed rule for existing fossil-fueled generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants,a federal plan and could have a material adverse impact on our operating costs. We are evaluating potential actions to prepare for compliance with the Clean Power Plan based on current information available, including the implementation of co-firing of natural gas in certain of our coal-fired power plants.

Draft Federal Plan and Model Trading Rulesmodel trading rules that were also published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In December 2015,addition, the stateGovernor of Wisconsin submitted petitions for reconsiderationissued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

Notwithstanding the uncertain future of the EPA's final standardsCPP, 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. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO2 reduction goal, such as increased use of existing as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards fornatural gas combined cycle units, co-firing or switching to natural gas in existing generatingcoal-fired units, was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013reduced operation or retirement of the Kewaunee Power Station, which could lower the state's carbon dioxideequivalent reduction goal by about 10%. In May 2016, the EPA denied the stateexisting coal-fired units, addition of Wisconsin's petition for reconsideration related to new modified,renewable energy resources (wind, solar), and reconstructed generating units. The EPA has not issued decisions yet regarding the above referenced petitions for reconsiderationconsideration of the final EPA standards for existing generating units.supply and demand-side energy efficiency and distributed generation.


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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment.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 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

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


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During 2016–2017 and 2018, we will be completingcontinue to complete studies and evaluatingevaluate options to address the EM BTA requirements at ourthese plants. With the exception of Weston Units 3 and 4 (which have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at ourthe facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. EntrainmentWe expect to submit entrainment studies are currently being conducted at Pulliam Units 7 and 8.8 to the WDNR by June 2018.

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 limitations guidelines (ELG) rule took effect in January 2016 and2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In June 2017, the EPA issued a proposed rule to codify this stay. This rule applies to wastewater discharges of wastewater from our power plant processes in Wisconsin. Unless pending challenges toWhile the final guidelinesELG compliance deadlines are successful,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. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standardsas 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 phaseswould phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. The rule also requireswould 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 willwould be required at Pulliam Units 7 and 8 and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $25 million to $35 million for these advanced treatment and bottom ash transport systems.


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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) September 30, 2016 December 31, 2015 June 30, 2017 December 31, 2016
Regulatory assets $101.5
 $104.4
 $114.0
 $116.0
Reserves for future remediation 82.2
 83.5
 96.3
 97.2

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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Consent Decrees

Weston and Pulliam Consent Decree

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

The Consent Decree contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6. In March 2016, we submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. These proposed revisions were approved by the EPA in May 2016. The revisions to the environmental projects are not expected to materially impact the overall cost required of $6.0 million.

We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, we recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, we received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of a $1.2 million civil penalty.

Also, in May 2010, we received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of SeptemberJune 30, 2016.2017. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater

In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, 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.

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

NOTE 12—13—SUPPLEMENTAL CASH FLOW INFORMATION
 Nine Months Ended September 30 Six Months Ended June 30
(in millions) 2016 2015 2017 2016
Cash (paid) for interest, net of amount capitalized $(27.5) $(29.2) (27.5) (27.2)
Cash received for income taxes, net 48.8
 13.2
Cash (paid) received for income taxes, net (18.5) 43.0
Significant noncash transactions:        
Accounts payable related to construction costs 42.2
 74.9
 33.4
 37.0
Transfer of ownership in WPSI to another subsidiary of Integrys * 67.2
 —
Transfer of net assets to UMERC * 21.1
 —

*See Note 11, Related Parties, for more information on these transactions.

NOTE 13—14—REGULATORY ENVIRONMENT

20162018 and 2019 Wisconsin Rate OrderRates

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 this proposed settlement agreement, we agreed to keep electric and natural gas base rates frozen for our customers through 2019. In addition, we agreed to extend and expand the electric real-time pricing options for large commercial and industrial customers. Deferral of the revenue requirement impacts of any federal corporate tax reform enacted in 2017, or during the rate freeze period, was included in the agreement as well. 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. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million. The agreement also included an extension, through 2019, of other deferrals related to our electric real-time pricing program and network transmission expenses.

Pursuant to the settlement agreement, we also agreed to adopt, beginning in 2018, the earnings sharing mechanism currently in place for WE and WG, and all three utilities 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.

In April 2015,July 2017, the PSCW staff issued a commission memorandum in response to the settlement agreement, and we initiatedexpect the PSCW to issue a final order on the agreement during the third quarter of 2017. If the PSCW rejects the proposed settlement agreement, we expect we will file a traditional rate proceedingproceeding.

Natural Gas Storage Facilities in Michigan

In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide some of the current storage needs for our natural gas distribution service customers. As a result of this agreement, we, along with WE and WG, filed a request with the PSCW.PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In December 2015,the filing, we requested that the PSCW issued a final written order, effective January 1, 2016. The order, which reflects a 10.0% ROEreview and a common equity component averageconfirm the reasonableness and prudency of 51.0%, authorized a net retailour potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. See Note 11, Related Parties, for more information.


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electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, we would have realized an electric rate increase. Based on the order, the PSCW will continue to allow us to escrow ATC and MISO network transmission expenses through 2016. In addition, future SSR payments will continue to be escrowed until a future rate proceeding. The order directs us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which requires us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.

In March 2016, we requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, we also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of our current large commercial and industrial customers who entered into a service agreement with us under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. The amounts deferred related to these items as of September 30, 2016, were not material.

Upper Michigan Energy Resources Corporation

Formation of Upper Michigan Energy Resources Corporation

In JuneDecember 2016, WEC Energy Group filed a proposal withboth the MPSC and the PSCW for approval to operateapproved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alonestand-alone utility in the Upper Peninsula of Michigan.Michigan, and UMERC became operational effective January 1, 2017. This utility will include our and WE'sholds the electric and natural gas distribution assets, located in the Upper Peninsula. The proposal was filed pursuant to the MPSC's approval of the WEC Merger, whereby WEC Energy Group agreed to form a separate Michigan utility company. In October 2016, we reached a unanimous settlement agreement with all parties in Michigan, including the MPSC staff, the Michigan attorney general,previously held by WE and the Tilden Mining Company (Tilden), relating to WEC Energy Group's application to form UMERC. If the settlement agreement is approved by the MPSC, we anticipate that the new utility will become operational effective January 1, 2017.

In August 2016, WEC Energy Group entered into an agreement with Tilden under which it will purchase electric power from UMERC for 20 years. The agreement also calls for UMERC to construct and operate approximately 170 MW of natural gas generationus, located in the Upper Peninsula of Michigan. The estimated cost

2015 Michigan Rate Order

Prior to the formation of UMERC, in October 2014, we initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. As a result of the formation of UMERC, the terms and conditions of this project is $255 million, 50% of which is expectedrate order now apply to be recovered from Tilden, withUMERC, including the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to achieve commercial operation in 2019.related deferrals.

NOTE 14—15—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. This guidance is effective

We intend to adopt this standard for fiscal yearsinterim and interimannual periods beginning after December 15, 2017,January 1, 2018, as required, and can either be applied retrospectively or asplan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the datebeginning of adoption. 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

We are currently assessingreviewing our contracts with customers and related financial disclosures to evaluate the effects thisimpact of the amended guidance may have on our financial statements.existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition.

ClassificationRecognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, ClassificationRecognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We are currently assessingdo not believe the effectsadoption of this guidance maywill have a significant impact on our financial statements.


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Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP.  We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects
06/30/2017 Form 10-Q20Wisconsin Public Service Corporation
Table of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly withholding shares for tax purposes is classified as a financing activity. We are currently assessing the effects this guidance may have on our financial statements.Contents

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.

Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. 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, 2015.2016.

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 and the Upper Peninsula of Michigan.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 10, Segment Information, for more information on our reportable business segments.

Effective January 1, 2017, our customers and electric and natural gas distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility subsidiary of WEC Energy Group. See Note 11, Related Parties, for more information.

Effective January 1, 2017, we transferred our 10.37% ownership interest in WPSI, which holds an approximate 34% interest in ATC, to another subsidiary of Integrys. See Note 11, Related Parties, for more information.

Corporate Strategy

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

Reliability

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

We continue work on our SMRP, which involves modernizing parts of our electric distribution system, byincluding burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric lines that currently have the lowest reliability inservice we provide to our system, primarily in rural areas that are heavily forested. We are planning to expand the scope of this project with SMRP Phase II. If approved, SMRP Phase II will address areas of our service territory where reliability is sub-standard to a lesser degree than the areas addressed in the initial phase of the SMRP.customers.

Operating Efficiency

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

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

Financial Discipline

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

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

Exceptional Customer Care

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

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One example of how we have begun obtaining feedback from our customers is through "We Care" calls, where our employees contact customers after a completed service call. This program began many years ago at WE and WG. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we will use to gauge our performance in order to improve customer satisfactionsatisfaction.

Safety

We have a long-standing commitment to both workplace and minimize customer dissatisfaction.public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries.

RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2017

Consolidated Earnings

Our consolidated earnings for the three months ended June 30, 2017 were $30.7 million, compared to $26.3 million for the same quarter in 2016. See below for additional information on the $4.4 million increase 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, 2017 and 2016 was $61.2 million and $43.1 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.


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RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2016

Consolidated Earnings

Our consolidated earnings for the three months ended September 30, 2016 were $64.7 million, compared to $50.3 million for the same period in 2015. See below for additional information on the $14.4 million increase in earnings.

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the thirdsecond quarter of 20162017 with the thirdsecond quarter of 2015,2016, including favorable or better, "B", and unfavorable or worse, "W", variances:variances. Effective January 1, 2017, we transferred all of our electric and natural gas customers located in the Upper Peninsula of Michigan to UMERC. See Note 11, Related Parties, for more information.
 Three Months Ended September 30 Three Months Ended June 30
(in millions) 2016 2015 B (W) 2017 2016 B (W)
Electric revenues $340.0
 $346.5
 $(6.5) $289.6
 $282.3
 $7.3
Fuel and purchased power 108.4
 122.7
 14.3
 105.3
 91.3
 (14.0)
Total electric margins 231.6
 223.8
 7.8
 184.3
 191.0
 (6.7)
            
Natural gas revenues 41.0
 44.3
 (3.3) 52.0
 49.2
 2.8
Cost of natural gas sold 16.4
 18.3
 1.9
 25.2
 22.2
 (3.0)
Total natural gas margins 24.6
 26.0
 (1.4) 26.8
 27.0
 (0.2)
            
Total electric and natural gas margins 211.1
 218.0
 (6.9)
      
Other operation and maintenance 110.0
 120.8
 10.8
 105.6
 134.3
 28.7
Depreciation and amortization 30.7
 30.3
 (0.4) 34.5
 30.3
 (4.2)
Property and revenue taxes 10.0
 10.3
 0.3
 9.8
 10.3
 0.5
Operating income $105.5
 $88.4
 $17.1
 $61.2
 $43.1
 $18.1

The following table shows a breakdown of other operation and maintenance:
  Three Months Ended June 30
(in millions) 2017 2016 B (W)
Operation and maintenance not included in line items below $60.2
 $87.8
 $27.6
Transmission (1)
 37.2
 37.1
 (0.1)
Regulatory amortizations and other pass through expenses (2)
 8.2
 9.4
 1.2
Total other operation and maintenance $105.6
 $134.3
 $28.7

(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 three months ended June 30, 2017 and 2016, $37.4 million and $37.8 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 sales volumes by customer class and weather statistics:
  Three Months Ended September 30
  
MWh (in thousands)
Electric Sales Volumes 2016 2015 B (W)
Customer class  
  
  
Residential 845.0
 775.7
 69.3
Small commercial and industrial 1,099.8
 1,090.1
 9.7
Large commercial and industrial 1,082.3
 1,056.8
 25.5
Other 6.1
 6.2
 (0.1)
Total retail 3,033.2
 2,928.8
 104.4
Wholesale 717.5
 738.9
 (21.4)
Resale 110.1
 347.6
 (237.5)
Total sales in MWh 3,860.8
 4,015.3
 (154.5)
Electric Customer Choice * 6.9
 6.3
 0.6

*Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
  Three Months Ended September 30
  
Therms (in millions)
Natural Gas Sales Volumes 2016 2015 B (W)
Customer class  
  
  
Residential 13.3
 13.6
 (0.3)
Commercial and industrial 18.8
 17.7
 1.1
Total retail 32.1
 31.3
 0.8
Transport 84.1
 75.5
 8.6
Total sales in therms 116.2
 106.8
 9.4
  Three Months Ended June 30
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W)
Customer class  
  
  
Residential 605.4
 614.4
 (9.0)
Small commercial and industrial 965.5
 991.4
 (25.9)
Large commercial and industrial 1,012.4
 1,053.3
 (40.9)
Other 5.5
 5.7
 (0.2)
Total retail 2,588.8
 2,664.8
 (76.0)
Wholesale 674.6
 627.2
 47.4
Resale 176.0
 111.0
 65.0
Total sales in MWh 3,439.4
 3,403.0

36.4


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  Three Months Ended September 30
  Degree Days
Weather * 2016
2015 B (W)
Heating (208 Normal) 79
 120
 (41)
Cooling (352 Normal) 426
 396
 30
  Three Months Ended June 30
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W)
Customer class  
  
  
Residential 34.0
 37.2
 (3.2)
Commercial and industrial 23.3
 27.3
 (4.0)
Total retail 57.3
 64.5
 (7.2)
Transport 96.2
 95.8
 0.4
Total sales in therms 153.5
 160.3
 (6.8)

  Three Months Ended June 30
  Degree Days
Weather * 2017
2016 B (W)
Heating (958 normal) 834
 964
 (130)
Cooling (131 normal) 125
 142
 (17)

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

Electric Utility Margins

Electric utility margins are defined as electric revenues less fueldecreased $6.7 million during the second quarter of 2017, compared with the same quarter in 2016. The significant factors impacting the lower margins were:

A $5.6 million decrease related to lower retail sales volumes during the second quarter of 2017, primarily driven by the transfer of customers and purchased power costs. We believe that electric utility margins provide a more meaningful basis for evaluating electric utility operationstheir related sales to UMERC and the impact of warmer weather. As measured by heating degree days, the second quarter of 2017 was 13.5% warmer than electric revenues since the majoritysame quarter in 2016.

A $3.2 million negative impact from collections of prudently incurred fuel and purchased power costs are passed through to customerscompared with costs approved in current rates under enacted fuel rules.

Electric utility margins increased $7.8 million duringin the thirdsecond quarter of 2016,2017, as compared with the same periodquarter in 2015. The significant factors impacting2016. Under the higherWisconsin fuel rules, our electric utility margins were:are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

A $6.9Partially offsetting these decreases was a $1.8 million increase related toin wholesale margins driven by higher sales volumes during the thirdsecond quarter of 2016, driven by warmer weather and higher weather-normalized use per residential customer.

A $5.7 million increase as2017, primarily due to UMERC purchasing a resultportion of the PSCW rate order, effective January 1, 2016. See Note 13, Regulatory Environment, for more information.

These increases in margin were partially offset by a $2.0 million decrease in wholesale margins, driven by lower wholesale prices in the third quarter of 2016. The decrease in wholesale prices was primarily driven by lower operating expenses. Wholesale customers proportionally shared in the lower operating expenses through formula rates.its energy from us.

Natural Gas Utility Margins

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 16.75% quarter over quarter, which had no impact on margins.

Natural gas utility margins decreased $1.4$0.2 million during the thirdsecond quarter of 2016,2017, compared with the same periodquarter in 2015.2016. The decrease was primarilylower margins were driven by the PSCW rate order, effective January 1, 2016. See Note 13, Regulatory Environment, for more information. The third quarter is generally not a heating period,impact of warmer weather and therefore, it historically has the lowest natural gas marginstransfer of the year.customers and their related sales to UMERC.

Operating Income

Operating income at the utility segment increased $17.1$18.1 million during the thirdsecond quarter of 2016,2017, compared with the same periodquarter in 2015.2016. The increase was driven by a $10.7$25.0 million decrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenuesrevenue taxes) and, partially offset by the $6.4$6.9 million net increasedecrease in margins discussed above.

The utility segment experienced lower overall operating expenses related to synergy savings resulting from the acquisition of our parent company, Integrys, by WEC Energy Group. The significant factors impacting the decrease in operating expenses, was driven by an $11.5which were due in part to synergy savings, were:

A $14.1 million decrease in maintenance expenses at our generation plants.

Other Segment Contributionrelated to Operating Income
  Three Months Ended September 30
(in millions) 2016 2015 B (W)
Operating (loss) income $(0.2) $0.1
 $(0.3)
an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries, including us. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this project from WBS to us in 2017.


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A $5.8 million decrease in electric and natural gas distribution expenses, due in part to the transfer of customers and their related sales to UMERC.

A $5.7 million decrease in benefit costs, primarily driven by lower pension and OPEB costs.

These decreases in operating expenses were partially offset by a $4.2 million increase in depreciation and amortization expense, driven by the ReACTTM multi-pollutant control system at Weston Unit 3 going into service during the fourth quarter of 2016.

Other Segment Contribution to Operating Income
  Three Months Ended June 30
(in millions) 2017 2016 B (W)
Operating (loss) income $(0.2) $0.3
 $(0.5)

Consolidated Other Income, Net
 Three Months Ended September 30 Three Months Ended June 30
(in millions) 2016 2015 B (W) 2017 2016 B (W)
AFUDC – Equity $5.6
 $4.1
 $1.5
 $1.2
 $5.5
 $(4.3)
Earnings from equity method investments 2.4
 2.7
 (0.3) 0.3
 2.1
 (1.8)
Other, net 0.9
 (0.1) 1.0
 1.5
 1.3
 0.2
Other income, net $8.9
 $6.7
 $2.2
 $3.0
 $8.9
 $(5.9)

Other income, net increaseddecreased by $2.2$5.9 million when compared to the thirdsecond quarter of 2015,2016, primarily due to an increasea decrease in AFUDC driven by the construction of the ReACTTM emission control technology at Weston Unit 3.3 that went into service during the fourth quarter of 2016. Also contributing to the decrease were lower earnings from our equity method investments due to the transfer of our ownership interest in WPSI to another subsidiary of Integrys effective January 1, 2017. See Note 11, Related Parties, for more information.

Consolidated Interest Expense
 Three Months Ended September 30 Three Months Ended June 30
(in millions) 2016 2015 B (W) 2017 2016 B (W)
Interest expense $11.7
 $13.2
 $1.5
 $13.6
 $11.7
 $(1.9)

Interest expense decreasedincreased by $1.5$1.9 million, whenas compared to the thirdsecond quarter of 2015,2016, primarily due to a lower averagedecrease in capitalized interest rate on outstanding long-term debt, and an increase in AFUDC-Debt. AFUDC-Debt was higher largely due to the construction ofdriven by the ReACTTM emission control technology at Weston Unit 3.3 going into service during the fourth quarter of 2016.

Consolidated Income Tax Expense
  Three Months Ended September 30
  2016 2015 B (W)
Effective tax rate 36.9% 37.8% 0.9%
  Three Months Ended June 30
  2017 2016 B (W)
Effective tax rate 39.1% 35.2% (3.9)%

Our effective tax rate decreasedincreased by 0.9%3.9% when compared to the thirdsecond quarter of 2015,2016, primarily due to an increasea decrease in the projected 20162017 annual tax benefits associated with AFUDC – Equity, which is non-taxable.Equity.

NINESIX MONTHS ENDED SEPTEMBERJUNE 30, 20162017

Consolidated Earnings

Our consolidated earnings for the ninesix months ended SeptemberJune 30, 20162017 were $135.5$70.0 million, compared to $111.9$70.8 million for the same period in 2015.2016. See below for additional information on the $23.6$0.8 million increasedecrease in consolidated earnings.


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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, 2017 and 2016 was $137.2 million and $120.0 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 first ninesix months of 20162017 with the first ninesix months of 2015,2016, including favorable or better, "B", and unfavorable or worse, "W", variances:variances. Effective January 1, 2017, we transferred all of our electric and natural gas customers located in the Upper Peninsula of Michigan to UMERC. See Note 11, Related Parties, for more information.
 Nine Months Ended September 30 Six Months Ended June 30
(in millions) 2016 2015 B (W) 2017 2016 B (W)
Electric revenues $903.9
 $920.1
 $(16.2) $577.2
 $563.9
 $13.3
Fuel and purchased power 286.2
 333.0
 46.8
 204.8
 177.8
 (27.0)
Total electric margins 617.7
 587.1
 30.6
 372.4
 386.1
 (13.7)
            
Natural gas revenues 183.3
 226.0
 (42.7) 154.0
 142.3
 11.7
Cost of natural gas sold 94.5
 133.3
 38.8
 90.6
 78.1
 (12.5)
Total natural gas margins 88.8
 92.7
 (3.9) 63.4
 64.2
 (0.8)
            
Total electric and natural gas margins 435.8
 450.3
 (14.5)
      
Other operation and maintenance 359.5
 356.4
 (3.1) 209.8
 249.5
 39.7
Depreciation and amortization 91.7
 90.2
 (1.5) 68.9
 61.0
 (7.9)
Property and revenue taxes 29.8
 30.6
 0.8
 19.9
 19.8
 (0.1)
Operating income $225.5
 $202.6
 $22.9
 $137.2
 $120.0
 $17.2


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The following table shows a breakdown of other operation and maintenance:
  Six Months Ended June 30
(in millions) 2017 2016 B (W)
Operation and maintenance not included in line items below $119.2
 $159.9
 $40.7
Transmission (1)
 73.1
 74.1
 1.0
Regulatory amortizations and other pass through expenses (2)
 17.5
 15.5
 (2.0)
Total other operation and maintenance $209.8
 $249.5
 $39.7

(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, 2017 and 2016, $64.3 million and $75.7 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 sales volumes by customer class and weather statistics:
  Nine Months Ended September 30
  
MWh (in thousands)
Electric Sales Volumes 2016 2015 B (W)
Customer class  
  
  
Residential 2,194.9
 2,126.3
 68.6
Small commercial and industrial 3,058.5
 3,020.8
 37.7
Large commercial and industrial 3,148.0
 3,073.1
 74.9
Other 20.1
 20.1
 —
Total retail 8,421.5
 8,240.3
 181.2
Wholesale 1,957.3
 2,003.5
 (46.2)
Resale 348.3
 773.7
 (425.4)
Total sales in MWh 10,727.1
 11,017.5
 (290.4)
Electric Customer Choice * 19.2
 16.9
 2.3

*Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
  Nine Months Ended September 30
  
Therms (in millions)
Natural Gas Sales Volumes 2016 2015 B (W)
Customer Class  
  
  
Residential 162.1
 174.8
 (12.7)
Commercial and industrial 111.7
 117.7
 (6.0)
Total retail 273.8
 292.5
 (18.7)
Transport 305.6
 268.2
 37.4
Total sales in therms 579.4
 560.7
 18.7
  Six Months Ended June 30
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W)
Customer class  
  
  
Residential 1,319.6
 1,349.9
 (30.3)
Small commercial and industrial 1,915.2
 1,958.8
 (43.6)
Large commercial and industrial 1,992.2
 2,077.9
 (85.7)
Other 13.4
 14.0
 (0.6)
Total retail 5,240.4
 5,400.6
 (160.2)
Wholesale 1,334.4
 1,239.8
 94.6
Resale 320.7
 238.2
 82.5
Total sales in MWh 6,895.5
 6,878.6
 16.9

  Nine Months Ended September 30
  Degree Days
Weather * 2016
2015 B (W)
Heating (4,895 normal) 4,481
 4,906
 (425)
Cooling (483 normal) 568
 494
 74
  Six Months Ended June 30
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W)
Customer Class  
  
  
Residential 145.3
 148.8
 (3.5)
Commercial and industrial 90.4
 92.8
 (2.4)
Total retail 235.7
 241.6
 (5.9)
Transport 223.5
 221.5
 2.0
Total sales in therms 459.2
 463.1
 (3.9)

  Six Months Ended June 30
  Degree Days
Weather * 2017
2016 B (W)
Heating (4,609 normal) 4,107
 4,402
 (295)
Cooling (131 normal) 125
 142
 (17)

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

Electric Utility Margins

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

Electric utility margins increased $30.6decreased $13.7 million during the first ninesix months of 2016,2017, compared with the same period in 2015.2016. The significant factors impacting the higherlower electric utility margins were:

A $20.7An $8.7 million increase as a result of the PSCW rate order, effective January 1, 2016. See Note 13, Regulatory Environment, for more information.

A $9.9 million increasedecrease related to higherlower retail sales volumes primarily during the third quarterfirst six months of 2016,2017, primarily driven by higher weather-normalized use per residential customer.the transfer


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of customers and their related sales to UMERC, an additional day of sales during the same period in 2016 due to leap year, and the impact of warmer winter weather. As measured by heating degree days, the first six months of 2017 were 6.7% warmer than the same period in 2016.

A $7.9 million negative impact from collections of fuel and purchased power costs compared with costs approved in rates in the first six months of 2017, as compared with the same period in 2016. 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.

Partially offsetting these decreases was a $2.2 million increase in wholesale margins driven by higher sales volumes during the first six months of 2017, primarily due to UMERC purchasing a portion of its energy from us.

Natural Gas Utility Margins

We believe that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 24.4% period over period, which had no impact on margins.

Natural gas utility margins decreased $3.9$0.8 million during the first ninesix months of 2016,2017, compared with the same period in 2015.2016. The decrease waslower margins were primarily driven by the PSCW rate order, effective January 1, 2016. See Note 13, Regulatory Environment, for more information.transfer of customers and their related sales to UMERC.

Operating Income

Operating income at the utility segment increased $22.9$17.2 million during the first ninesix months of 2016,2017, compared with the same period in 2015.2016. The increase was driven by the $26.7a $31.7 million net increase in margins discussed above, partially offset by a $3.8 million increasedecrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes)., partially offset by the $14.5 million decrease in margins discussed above.

The increaseutility segment experienced lower overall operating expenses related to synergy savings resulting from the acquisition of our parent company, Integrys, by WEC Energy Group. The significant factors impacting the decrease in operating expenses, was driven by a $25.9which were due in part to synergy savings, were:

A $15.4 million increasedecrease in expenses related to various regulatory matters. Partially offsettingan information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries, including us. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this increase was a $12.3project from WBS to us in 2017.

A $10.7 million decrease in maintenance expenses at our generation plantsbenefit costs, primarily driven by lower pension and $9.0OPEB costs, lower employee medical costs, and a decrease in stock-based compensation expense.

An $8.0 million of lowerdecrease in electric and natural gas distribution expenses, due in part to the transfer of customers and their related sales to UMERC.

A $1.4 million decrease in operation and maintenance expenses related to our plants.

These decreases in operating expenses were partially offset by a $7.9 million increase in depreciation and amortization expense, driven by the ReACTTM multi-pollutant control system at Weston Unit 3 going into service during the first nine monthsfourth quarter of 2016.

Other Segment Contribution to Operating Income
  Nine Months Ended September 30
(in millions) 2016 2015 B (W)
Operating income $0.1
 $—
 $0.1

Consolidated Other Income, Net
  Nine Months Ended September 30
(in millions) 2016 2015 B (W)
AFUDC – Equity $16.3
 $10.4
 $5.9
Earnings from equity method investments 7.1
 7.6
 (0.5)
Other, net 2.3
 1.8
 0.5
Other income, net $25.7
 $19.8
 $5.9

Other income, net increased by $5.9 million when compared to the first nine months of 2015, primarily due to an increase in AFUDC driven by the construction of the ReACTTM emission control technology at Weston Unit 3.

Consolidated Interest Expense
  Nine Months Ended September 30
(in millions) 2016 2015 B (W)
Interest expense $35.3
 $40.3
 $5.0

Interest expense decreased by $5.0 million when compared to the first nine months of 2015, due to a lower average interest rate on outstanding long-term debt, and an increase in AFUDC-Debt. AFUDC-Debt was higher largely due to the construction of the ReACTTM emission control technology at Weston Unit 3.

Consolidated Income Tax Expense
  Nine Months Ended September 30
  2016 2015 B (W)
Effective tax rate 37.3% 37.3% —%

We expect our 2016 annual effective tax rate to be between 37.0% and 38.0%.
  Six Months Ended June 30
(in millions) 2017 2016 B (W)
Operating (loss) income $(0.4) $0.3
 $(0.7)


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Consolidated Other Income, Net
  Six Months Ended June 30
(in millions) 2017 2016 B (W)
AFUDC – Equity $2.1
 $10.7
 $(8.6)
Earnings from equity method investments 0.5
 4.7
 (4.2)
Other, net 3.3
 1.4
 1.9
Other income, net $5.9
 $16.8
 $(10.9)

Other income, net decreased by $10.9 million when compared to the first six months of 2016, primarily due to a decrease in AFUDC driven by the ReACTTM emission control technology at Weston Unit 3 that went into service during the fourth quarter of 2016. Also contributing to the decrease were lower earnings from our equity method investments due to the transfer of our ownership interest in WPSI to another subsidiary of Integrys effective January 1, 2017. See Note 11, Related Parties, for more information.

Consolidated Interest Expense
  Six Months Ended June 30
(in millions) 2017 2016 B (W)
Interest expense $27.5
 $23.6
 $(3.9)

Interest expense increased by $3.9 million, as compared to the first six months of 2016, primarily due to a decrease in capitalized interest driven by the ReACTTM emission control technology at Weston Unit 3 going into service during the fourth quarter of 2016.

Consolidated Income Tax Expense
  Six Months Ended June 30
  2017 2016 B (W)
Effective tax rate 39.2% 37.6% (1.6)%

Our effective tax rate increased by 1.6% when compared to the first six months of 2016, primarily due to a decrease in the projected 2017 annual tax benefits associated with AFUDC-Equity. We expect our 2017 annual effective tax rate to be between 39.0% and 40.0%.

LIQUIDITY AND CAPITAL RESOURCES
 
Cash Flows

The following summarizes our cash flows during the ninesix months ended SeptemberJune 30:
(in millions) 2016 2015 Change in 2016 Over 2015 2017 2016 Change in 2017 Over 2016
Cash provided by (used in):            
Operating activities $328.5
 $320.0
 $8.5
 $280.4
 $233.4
 $47.0
Investing activities (230.8) (269.9) 39.1
 (152.1) (149.4) (2.7)
Financing activities (99.9) (52.6) (47.3) (104.8) (86.1) (18.7)

Operating Activities

Net cash provided by operating activities increased $8.5$47.0 million during the ninefirst six months ended September 30,of 2017, compared with the same period in 2016, driven by:

A $92.7$161.9 million increase in cash related to cash received for assets transferred out of our pension plan in January 2017. See Note 11, Related Parties, for more information.

A $28.0 million increase in cash related to higher overall collections from customers, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 18.4% during the first six months of 2017, compared with the same period in 2016.

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A $25.6 million increase in cash from lower payments for operating and maintenance costs. During the first six months of 2017, our payments related to transmission, electric and natural gas distribution costs, and employee benefits decreased.

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

A $65.2 million increase in contributions and payments to our pension and OPEB plans during the first six months of 2017.

A $61.5 million net decrease in cash related to $18.5 million of cash paid for income taxes during the first six months of 2017, compared with $43.0 million of cash received during the same period in 2016. This decrease in cash was primarily the result of the extension of bonus depreciation in December 2015, resulting in a refund received during the first six months of 2016.

A $43.9 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, primarily due to lowerhigher commodity prices and warmer weather during the 2016 heating season.

A $35.6 million net increasefirst six months of 2017, compared with the same period in cash received from income taxes, primarily the result of the enactment of bonus depreciation later in 2015.

These increases were partially offset by:

A $113.1 million decrease in overall collections from customers because of lower commodity prices and warmer weather during the 2016 heating season.

A $12.3 million cash payment for transfers of certain benefit-related liabilities to WBS during the nine months ended September 30, 2016.

Investing Activities

Net cash used in investing activities decreased $39.1increased $2.7 million during the ninefirst six months ended September 30,of 2017, compared with the same period in 2016, driven by a $33.3$16.5 million net increase in cash used related to $9.2 million of cash paid for assets received from WBS during the first six months of 2017 compared with $7.3 million of cash received for assets transferred to WBS during the same period in 2016. This increase in cash used was partially offset by a $9.8 million decrease in cash paid for capital expenditures, which is discussed in more detail below.

Capital Expenditures

Capital expenditures for the ninesix months ended SeptemberJune 30 were as follows:
(in millions) 2016 2015 Change in 2016 Over 2015 2017 2016 Change in 2017 Over 2016
Capital expenditures $235.0
 $268.3
 $(33.3) $144.3
 $154.1
 $(9.8)

The decrease in cash paid for capital expenditures during the ninefirst six months ended September 30, 2016,of 2017 was driven by lower expenditures for the ReACTTM emission control technology project at Weston Unit 3 partially offset by higherand lower expenditures for a combustion turbine project at the Fox Energy Center.Center, partially offset by higher expenditures for the SMRP.

See Significant Capital Projects below for more information.

Financing Activities

Net cash used in financing activities increased $47.3$18.7 million during the ninefirst six months ended September 30,of 2017, compared with the same period in 2016, driven by:

A $30.0by a $75.7 million decrease increase in equity contributions fromdividends paid to our parent during the ninefirst six months ended September 30,of 2017. 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.

This increase in net cash used for financing activities was partially offset by:

A $28.6 million repayment of a loan during 2016.

A $20.0 million increase in equity contributions received from our parent related to balancing our capital structure.

For more information on our short-term financing activities, see Note 3, Short-Term Debt and Lines of Credit.


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A $28.6 million repayment of a loan during the nine months ended September 30, 2016.

These increases in net cash used for financing activities were partially offset by an $8.7 million decrease in the repayment of commercial paper during the nine months ended September 30, 2016.

For more information on our short-term borrowings, see Note 3, 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 3, Short-Term Debt and Lines of Credit, for more information abouton our credit facility.

Working Capital

As of SeptemberJune 30, 2016,2017, our current liabilities exceeded our current assets by approximately $30.2$62.6 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 can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.

Credit Rating Risk

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.

In June 2016,July 2017, Moody's Investors Service, among other actions,downgraded our senior unsecured rating to A2 from A1. Moody's affirmed our ratings (senior unsecured, A1;P-1 commercial paper P-1) and changed our rating outlook from stable to negative. The change in rating outlook was due to the absence of certain automatic recovery mechanisms in Wisconsin.rating. We do not believe this change in rating outlook will have a material impact on 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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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, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions)  
2016 $267.8
2017 321.7
2018 353.8
Total $943.3

We are constructing a multi-pollutant control technology known as ReACTTM as part of Weston Unit 3. The control technology will enable the plant to meet the requirements of a Consent Decree agreed to between us and the EPA. The cost of the project is estimated at approximately $345 million, excluding AFUDC, and it is expected to be placed in service in 2016.
(in millions)  
2017 $321.7
2018 353.8
2019 377.3
Total $1,052.8

We are also continuing work on the SMRP. This project includes converting more than 1,000 milesinvolves modernizing parts of overheadour electric distribution power linessystem, including burying or upgrading lines. The project focuses on constructing facilities to underground in northern Wisconsin and adding distribution automation equipment on 400 milesimprove the reliability of lines.electric service that we provide to our

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customers. We expect to invest approximately $45 million annually through 2018. Subject to regulatory review, Phase II of the SMRP will expand the scope and cost of the original SMRP and will consist of close to 1,000 miles of underground circuit installation. We expect to invest approximately $200$300 million between 20182017 and 2021 relatedon this project. We also continue to Phase II.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.

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 7, Guarantees, for more information.

Contractual Obligations

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 20152016 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 ofin our 20152016 Annual Report on Form 10-K, which 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 ofin our 20152016 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.


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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 our regulators.the PSCW. Recovery of thesethe deferred costs in future rates is subject to the review and approval by those regulators.the PSCW. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of thesethe deferred costs, including those referenced below, is not approved by our regulators,the PSCW, the costs would be charged to income in the current period. RegulatorsThe 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 April 2017, we requested an extension of this deferral through 2019 as part of a settlement agreement. We expect the PSCW to issue a final order on the settlement agreement during the third quarter of 2017. See Note 14, Regulatory Environment, for more information. We will be required to obtain a separate approval for collection of these deferred costs. See Significant Capital Projects for more information on ReACT™.costs in a future rate case.

Prior to the WEC Merger,its acquisition by Wisconsin Energy Corporation, 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

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technological benefits to the billing, call center, and credit collection functions. As of SeptemberJune 30, 20162017, we had not received noany 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 13,14, Regulatory Environment, for more information regarding recent and pending rate proceedings and orders.

Environmental Matters

See Note 11,12, 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

Presque Isle System Support Resource Costs

In August 2013, WE notified MISO of its intention to suspend the operation of Units 5 through 9 of its Presque Isle generating facility, starting February 1, 2014. MISO notified WE in October 2013 that the Presque Isle units are required for reliability and would be SSR-designated. In April 2014, WE notified MISO of its intention to retire the Presque Isle units, and, as of October 2014, the Presque Isle units were designated retirement SSR units. Under the terms of the SSR Tariff in exchange for keeping the units in service, MISO initially planned to compensate WE by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load-serving entities, including us, within the ATC footprint based on load ratio share. However, according to a February 2015 order issued by the FERC, MISO must allocate the SSR costs only to the load-serving entities within the ATC footprint requiring the operation of the SSR units for reliability purposes.

In February 2015, WE notified MISO of its intent to rescind its decision to retire the Presque Isle units and requested termination of the SSR agreement, effective February 1, 2015. This intent to rescind was driven by a settlement agreement related to the WEC Merger. In April 2015, the FERC approved the termination of the SSR agreement, effective February 1, 2015.

In May 2015, MISO made a compliance filing regarding the allocation of Presque Isle SSR costs incurred while the SSR was in effect, which did not allocate any of these SSR costs to us. In September 2015, the FERC approved MISO's cost allocation method. Several parties sought a rehearing of this FERC order, which the FERC denied in May 2016. Subsequently, several entities petitioned the D.C. Circuit Court of Appeals to review the FERC's order. In June 2016, MISO filed a refund report for the SSR costs, which the FERC approved in September 2016 while also suspending the SSR refund process currently in progress. At this time, we do not expect the petitions for review and refund process to have a material impact on us.


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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 Annual Report on Form 10-K for the year ended December 31, 2015.2016. 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 4,5, Fair Value Measurements, Note 5,6, Derivative Instruments, and Note 6,7, 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

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 thirdsecond quarter of 20162017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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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 20152016 Annual Report on Form 10-K. See Note 11,12, Commitments and Contingencies, in this report for more information on material legal proceedings and matters related to us.

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

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 is now pursuing the NRD claim. We are currently in settlement discussions with the Department of Justice, but we do not expect this matter to have a material impact on our financial statements. Substantial remediation of the uplands at the legacy Sheboygan Camp Marina manufactured gas plant site has already occurred. We agreed to settle this matter, subject to the approval of the United States District Court for the Eastern District of Wisconsin. The terms of the settlement, if approved, will 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, 2015.2016. See Item 1A. Risk Factors in Part I of our 20152016 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.


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ITEM 6. EXHIBITS
Number Exhibit
31 Rule 13a-14(a) / 15d-14(a) Certifications
    
  31.1Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
  31.2Certification 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
    
  32.1Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
  32.2Certification 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


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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:NovemberAugust 4, 20162017William J. Guc
  Vice President and Controller
   
  (Duly Authorized Officer and Chief Accounting Officer)


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