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 September 30, 2017
(Mark One)
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

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

For the transition period from ________________ to ___________________

Commission
File Number
Registrant; State of Incorporation;

Address; and Telephone Number
IRS Employer

Identification No.
1-3016001-03016WISCONSIN PUBLIC SERVICE CORPORATION39-0715160
(A Wisconsin Corporation)
700 North Adams Street
P.O. Box 19001
Green Bay, WI 54307-9001
800-450-7260

(A Wisconsin Corporation)
700 North Adams Street
P.O. Box 19001
Green Bay, WI 54307-9001
(800) 450-7260


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

None

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


Yes [X]☒    No [ ]☐


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


Yes [X]☒    No [ ]☐




Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer☐Accelerated filer☐
Non-accelerated filer☒Smaller reporting company☐
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’sissuer's classes of common stock, as of the latest practicable date:


Common Stock, $4 Par Value,par value,
23,896,962 shares outstanding at
September 30, 20172020


All of the common stock of Wisconsin Public Service Corporation is ownedheld 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 September 30, 20172020
TABLE OF CONTENTS


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Note 14
Commitments and Contingencies
1617
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2021
2122
2324
3639
3639
3740
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41
OTHER INFORMATION42
37
ITEM 6.
EXHIBITS
38
SIGNATURE
39



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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:
Affiliates
ATCAmerican Transmission Company LLC
IntegrysIntegrys Holding, Inc.
UMERCUpper Michigan Energy Resources Corporation
WEWisconsin Electric Power Company
WEC Energy GroupWEC Energy Group, Inc.
WGWisconsin Gas LLC
Subsidiaries and Affiliates
ATCAmerican Transmission Company LLC
BluewaterBluewater Natural Gas Holding, LLC
IntegrysIntegrys Holding, Inc.
UMERCUpper Michigan Energy Resources Corporation
WBSWEC Business Services LLC
WEC Energy GroupWEC Energy Group, Inc.
WEWisconsin Electric Power Company
WGWisconsin Gas LLC
WPSIWPS Investments, LLC
WRPCWisconsin River Power Company
Federal and State Regulatory Agencies
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
MPSCMichigan Public Service Commission
PSCW
PSCWPublic Service Commission of Wisconsin
SECUnited States Securities and Exchange Commission
WDNRWisconsin Department of Natural Resources
Accounting Terms
AFUDCAllowance for Funds Used During Construction
AIAASUAffiliated Interest Agreement
ASUAccounting Standards Update
FASBFinancial Accounting Standards Board
GAAPUnited States Generally Accepted Accounting Principles
OPEBOther Postretirement Employee Benefits
Environmental Terms
CAAACEAffordable Clean Energy
BATWBottom Ash Transport Water
BSERBest System of Emission Reduction
CAAClean Air Act
CO2
Carbon Dioxide
CSAPRELGCross-State Air Pollution RuleSteam Electric Effluent Limitation Guidelines
GHGGreenhouse Gas
NAAQSGHGNational Ambient Air Quality StandardsGreenhouse Gas
NOVMATSMercury and Air Toxics Standards
NOVNotice of Violation
NOxRTRNitrogen OxideRisk and Technology Review
SO2
The Combustion Turbine Rule		Sulfur DioxideNational Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines
Measurements
DthDekatherm
MWhMWMegawatt-hourMegawatt
MWhMegawatt-hour
Other Terms and Abbreviations
D.C. Circuit Court of AppealsAMIUnited States Court of Appeals for the District of Columbia CircuitAdvanced Metering Infrastructure
Badger Hollow IBadger Hollow Solar Park I
CDCCenters for Disease Control and Prevention
COVID-19Coronavirus Disease – 2019
Exchange ActSecurities Exchange Act of 1934, as amended
FTRsFTRFinancial Transmission RightsRight
MISOLIBORLondon Interbank Offered Rate
MISOMidcontinent Independent System Operator, Inc.
MISO Energy MarketsMISO Energy and Operating Reserves Markets
ROEReturn on Equity
SMRPSystem Modernization and Reliability Project
Supreme CourtUnited States Supreme Court


Tax LegislationTax Cuts and Jobs Act of 2017
Two CreeksTwo Creeks Solar Park
WHOWorld Health Organization

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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,rates, 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 2019 Annual Report on Form 10-K, for the year ended December 31, 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 the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;


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

The timely completion of capital projects within budgets, as well as the recoveryimpact of the related costs through rates;COVID-19 pandemic on our business functions, financial condition, liquidity, and results of operations;


•The impact of recent and future federal, state, and local legislative andand/or 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;mandates, and tax laws, including the Tax Legislation as well as those that affect our ability to use production tax credits and investment tax credits;


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


•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 and the ability to recover the related costs through rates;

•Factors affecting the implementation of WEC Energy Group's CO2 emission and/or methane emission reduction goals, and opportunities and actions related to those goals, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, and the feasibility of competing generation projects;

•The financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;

•The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas and other fossil fuels, purchased power, materials needed to operate environmental controls at our electric
09/30/2020 Form 10-Q1Wisconsin Public Service Corporation
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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;


•Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;

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


•The direct or indirect effect on our business resulting from terrorist attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;

•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, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;


•The timing, costs, and anticipated benefitsrisk associated with the remaining integration efforts relatingvalues of goodwill and other intangible assets and their possible impairment;

•Potential business strategies to WEC Energy Group's acquisitionacquire and dispose of Integrys;assets, which cannot be assured to be completed timely or within budgets;


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


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

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


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


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



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PART I. FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS


WISCONSIN PUBLIC SERVICE CORPORATION


CONDENSED INCOME STATEMENTS (Unaudited)Three Months EndedNine Months Ended
September 30September 30
(in millions)2020201920202019
Operating revenues$367.7 $352.3 $1,049.9 $1,069.0 
Operating expenses
Cost of sales105.3 114.5 330.3 408.1 
Other operation and maintenance105.2 107.4 296.3 308.7 
Depreciation and amortization43.5 42.3 129.7 123.4 
Property and revenue taxes10.9 10.1 30.5 30.4 
Total operating expenses264.9 274.3 786.8 870.6 
Operating income102.8 78.0 263.1 198.4 
Other income, net8.7 9.8 25.4 29.0 
Interest expense15.6 15.8 47.9 47.2 
Other expense(6.9)(6.0)(22.5)(18.2)
Income before income taxes95.9 72.0 240.6 180.2 
Income tax expense19.6 17.0 48.4 42.8 
Net income$76.3 $55.0 $192.2 $137.4 
CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) Three Months Ended Nine Months Ended
  September 30 September 30
(in millions) 2017 2016 2017 2016
Operating revenues $380.7
 $381.0
 $1,111.9
 $1,087.2
         
Operating expenses        
Cost of sales 125.1
 124.8
 420.5
 380.7
Other operation and maintenance 99.9
 110.1
 310.2
 359.3
Depreciation and amortization 35.1
 30.7
 103.9
 91.7
Property and revenue taxes 9.9
 10.1
 29.8
 29.9
Total operating expenses 270.0
 275.7
 864.4
 861.6
         
Operating income 110.7
 105.3
 247.5
 225.6
         
Other income, net 3.0
 8.9
 8.9
 25.7
Interest expense 13.7
 11.7
 41.2
 35.3
Other expense (10.7) (2.8) (32.3) (9.6)
         
Income before income taxes 100.0
 102.5
 215.2
 216.0
Income tax expense 39.1
 37.8
 84.3
 80.5
Net income $60.9
 $64.7
 $130.9
 $135.5


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 BALANCE SHEETS (Unaudited)September 30,December 31,
(in millions, except share and per share amounts)20202019
Assets  
Current assets
Cash and cash equivalents$2.0 $2.3 
Accounts receivable and unbilled revenues, net of reserves of $14.7 and $4.2, respectively180.9 210.0 
Accounts receivable from related parties19.2 38.7 
Materials, supplies, and inventories105.7 106.4 
Prepaid taxes37.3 63.4 
Other8.5 11.2 
Current assets353.6 432.0 
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $1,755.0 and $1,672.1, respectively4,794.0 4,544.5 
Regulatory assets424.6 437.9 
Goodwill36.4 36.4 
Pension and OPEB assets165.6 148.3 
Other38.0 42.5 
Long-term assets5,458.6 5,209.6 
Total assets$5,812.2 $5,641.6 
Liabilities and Equity 
Current liabilities
Short-term debt$16.0 $91.5 
Accounts payable171.5 176.9 
Accounts payable to related parties40.8 68.5 
Accrued payroll and benefits23.2 26.5 
Accrued interest21.6 10.6 
Customer credit balances15.5 17.3 
Other22.1 27.8 
Current liabilities310.7 419.1 
Long-term liabilities
Long-term debt1,644.2 1,642.8 
Deferred income taxes693.9 654.6 
Deferred investment tax credits36.7 6.1 
Regulatory liabilities761.5 782.5 
Environmental remediation liabilities83.8 83.8 
Pension and OPEB obligations18.1 18.6 
Other96.1 94.3 
Long-term liabilities3,334.3 3,282.7 
Commitments and contingencies (Note 15)
Common shareholder's equity
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding95.6 95.6 
Additional paid in capital1,426.3 1,221.1 
Retained earnings645.3 623.1 
Common shareholder's equity2,167.2 1,939.8 
Total liabilities and equity$5,812.2 $5,641.6 
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31,
(in millions, except share and per share amounts) 2017 2016
Assets  
  
Current assets    
Cash and cash equivalents $3.1
 $3.1
Collateral on deposit 21.2
 16.1
Accounts receivable and unbilled revenues, net of reserves of $4.0 and $3.0, respectively 173.0
 194.7
Receivables from related parties 4.0
 3.0
Materials, supplies, and inventories 129.9
 125.3
Prepaid taxes 29.1
 57.3
Other 7.1
 8.4
Current assets 367.4
 407.9
     
Long-term assets    
Property, plant, and equipment, net of accumulated depreciation of $1,620.1 and $1,595.1, respectively 3,759.3
 3,662.0
Regulatory assets 447.0
 465.8
Goodwill 36.4
 36.4
Pension and OPEB assets 31.7
 114.8
Other 53.2
 121.3
Long-term assets 4,327.6
 4,400.3
Total assets $4,695.0
 $4,808.2
     
Liabilities and Shareholder's Equity  
  
Current liabilities    
Short-term debt $120.8
 $176.8
Current portion of long-term debt 125.0
 125.0
Accounts payable 109.9
 165.4
Payables to related parties 22.5
 21.6
Other 74.9
 64.2
Current liabilities 453.1
 553.0
     
Long-term liabilities    
Long-term debt 1,165.9
 1,165.3
Deferred income taxes 910.4
 929.5
Deferred investment tax credits 6.8
 7.0
Regulatory liabilities 301.5
 291.3
Environmental remediation liabilities 96.0
 97.2
Pension and OPEB obligations 24.9
 25.4
Payables to related parties 3.6
 4.1
Other 108.9
 107.2
Long-term liabilities 2,618.0
 2,627.0
     
Commitments and contingencies (Note 14) 

 

     
Shareholder's equity    
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding 95.6
 95.6
Additional paid in capital 996.7
 966.9
Retained earnings 531.6
 565.7
Shareholder's equity 1,623.9
 1,628.2
Total liabilities and shareholder's equity $4,695.0
 $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 STATEMENTS OF CASH FLOWS (Unaudited)Nine Months Ended
September 30
(in millions)20202019
Operating activities  
Net income$192.2 $137.4 
Reconciliation to cash provided by operating activities  
Depreciation and amortization129.7 123.4 
Deferred income taxes and investment tax credits, net51.3 49.8 
Change in – 
Accounts receivable and unbilled revenues, net44.9 40.1 
Materials, supplies, and inventories0.7 (12.8)
Prepaid taxes26.1 11.6 
Other current assets7.0 (1.0)
Accounts payable(38.3)(35.9)
Accrued taxes3.1 16.6 
Other current liabilities(0.5)3.4 
Other, net(2.1)(10.0)
Net cash provided by operating activities414.1 322.6 
Investing activities  
Capital expenditures(381.0)(380.0)
Proceeds from cash surrender value of life insurance7.1 6.6 
Other, net0 1.4 
Net cash used in investing activities(373.9)(372.0)
Financing activities  
Issuance of long-term debt0 300.0 
Change in short-term debt(75.5)(265.9)
Payment of dividends to parent(170.0)(90.0)
Equity contribution from parent205.0 105.0 
Other, net0 (3.6)
Net cash (used in) provided by financing activities(40.5)45.5 
Net change in cash and cash equivalents(0.3)(3.9)
Cash and cash equivalents at beginning of period2.3 8.9 
Cash and cash equivalents at end of period$2.0 $5.0 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended
  September 30
(in millions) 2017 2016
Operating Activities  
  
Net income $130.9
 $135.5
Reconciliation to cash provided by operating activities  
  
Depreciation and amortization 103.9
 93.2
Deferred income taxes and investment tax credits, net 30.0
 76.9
Contributions and payments related to pension and OPEB plans (66.5) (1.2)
Cash received for pension plan assets transferred 157.8
 —
Change in –  
  
Accounts receivable and unbilled revenues 16.3
 (5.4)
Materials, supplies, and inventories (4.1) 13.0
Prepaid taxes 28.2
 19.4
Other current assets (2.8) 0.5
Accounts payable (24.5) (54.0)
Accrued taxes 9.6
 46.9
Other current liabilities 1.9
 16.8
Other, net 11.3
 (13.1)
Net cash provided by operating activities 392.0
 328.5
     
Investing Activities  
  
Capital expenditures (237.9) (235.0)
Proceeds from (payments for) assets transferred to (from) WBS (10.0) 7.3
Other, net 1.9
 (3.1)
Net cash used in investing activities (246.0) (230.8)
     
Financing Activities  
  
Change in short-term debt (56.0) (34.3)
Repayment of loan —
 (28.6)
Repayment of long-term debt to parent —
 (2.9)
Payment of dividends to parent (165.0) (88.9)
Equity contribution from parent 75.0
 55.0
Other, net —
 (0.2)
Net cash used in financing activities (146.0) (99.9)
     
Net change in cash and cash equivalents —
 (2.2)
Cash and cash equivalents at beginning of period 3.1
 6.1
Cash and cash equivalents at end of period $3.1
 $3.9


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 STATEMENTS OF EQUITY (Unaudited)
(in millions)Common StockAdditional Paid In CapitalRetained EarningsTotal Common Shareholder's Equity
Balance at December 31, 2019$95.6 $1,221.1 $623.1 $1,939.8 
Net income0 0 68.2 68.2 
Equity contribution from parent0 100.0 0 100.0 
Payment of dividends to parent0 0 (30.0)(30.0)
Stock-based compensation and other0 0.1 0 0.1 
Balance at March 31, 2020$95.6 $1,321.2 $661.3 $2,078.1 
Net income0 0 47.7 47.7 
Equity contribution from parent0 105.0 0 105.0 
Payment of dividends to parent0 0 (110.0)(110.0)
Stock-based compensation and other0 0.1 0 0.1 
Balance at June 30, 2020$95.6 $1,426.3 $599.0 $2,120.9 
Net income0 0 76.3 76.3 
Payment of dividends to parent0 0 (30.0)(30.0)
Balance at September 30, 2020$95.6 $1,426.3 $645.3 $2,167.2 

(in millions)Common StockAdditional Paid In CapitalRetained EarningsTotal Common Shareholder's Equity
Balance at December 31, 2018$95.6 $1,115.9 $558.4 $1,769.9 
Net income0 0 40.9 40.9 
Equity contribution from parent0 105.0 0 105.0 
Payment of dividends to parent0 0 (30.0)(30.0)
Balance at March 31, 2019$95.6 $1,220.9 $569.3 $1,885.8 
Net income0 0 41.5 41.5 
Payment of dividends to parent0 0 (30.0)(30.0)
Stock-based compensation and other0 0.1 0 0.1 
Balance at June 30, 2019$95.6 $1,221.0 $580.8 $1,897.4 
Net income0 0 55.0 55.0 
Payment of dividends to parent0 0 (30.0)(30.0)
Balance at September 30, 2019$95.6 $1,221.0 $605.8 $1,922.4 

The accompanying Notes to Condensed 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)
September 30, 20172020


NOTE 1—GENERAL INFORMATION


Wisconsin Public Service Corporation serves approximately 451,600 electric customers and 334,000 natural gas customers.

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, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation and its former subsidiary, WPS Leasing, Inc., which was dissolved in July 2016.Corporation.

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 13, 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 13, Related Parties, and Note 16, 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, 2016.2019. 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 nine months ended September 30, 2017,2020 are not necessarily indicative of expected results for 20172020 due to seasonal variations and other factors.factors, including any continuing financial impacts from the COVID-19 pandemic.


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


NOTE 2—ACQUISITION

Acquisition of a Wind Energy Generation Facility in Wisconsin

In October 2017, we, along with two other utilities, entered into an agreement to purchase the Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129 MWs. The aggregate purchase price is approximately $174 million of which our proportionate share is 44.6%, or approximately $78 million. We currently purchase 44.6% of the facility’s energy output under a power purchase agreement. The transaction is subject to PSCW and FERC approvals and is expected to close in the spring of 2018.

NOTE 3—PROPERTY, PLANT, AND EQUIPMENT2—OPERATING REVENUES


As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, early retirement of the Edgewater 4 generating unit was probable at September 30, 2017. The net book value of our ownership share of this generating unit was $13.3 million at September 30, 2017. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is currently included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 14, Commitments and Contingencies, forFor more information regardingabout our operating revenues, see Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

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

Wisconsin Public Service Corporation
Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Electric utility$328.0 $313.0 $864.3 $854.6 
Natural gas utility39.5 39.2 185.7 213.2 
Total revenues from contracts with customers367.5 352.2 1,050.0 1,067.8 
Other operating revenues0.2 0.1 (0.1)1.2 
Total operating revenues$367.7 $352.3 $1,049.9 $1,069.0 


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Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:
Electric Utility Operating Revenues
Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Residential$118.5 $101.1 $318.0 $278.8 
Small commercial and industrial104.1 103.3 268.1 272.7 
Large commercial and industrial66.1 64.5 168.4 173.7 
Other2.1 2.1 6.3 6.3 
Total retail revenues290.8 271.0 760.8 731.5 
Wholesale27.3 28.5 72.8 82.1 
Resale4.3 6.4 14.9 22.8 
Other utility revenues5.6 7.1 15.8 18.2 
Total electric utility operating revenues$328.0 $313.0 $864.3 $854.6 

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:
Natural Gas Utility Operating Revenues
Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Residential$19.6 $18.0 $107.0 $122.4 
Commercial and industrial10.5 10.3 56.6 72.6 
Total retail revenues30.1 28.3 163.6 195.0 
Transport3.8 3.1 14.0 12.3 
Other utility revenues (1)
5.6 7.8 8.1 5.9 
Total natural gas utility operating revenues$39.5 $39.2 $185.7 $213.2 

(1)Includes amounts collected from customers for purchased gas adjustment costs.

Other Operating Revenues

Other operating revenues consist primarily of the following:
Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Alternative revenues (1)
$0.1 $(0.6)$(1.3)$(1.4)
Late payment charges (2)
0.1 0.7 1.1 2.5 
Other0 0 0.1 0.1 
Total other operating revenues$0.2 $0.1 $(0.1)$1.2 

(1)Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to wholesale customers subject to true-up, as discussed in Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

(2)The reduction in late payment charges is a result of a regulatory order from the PSCW in response to the COVID-19 pandemic, which includes the suspension of late payment charges during a designated time period. See Note 17, Regulatory Environment, for more information.

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NOTE 3—CREDIT LOSSES

Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements.

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. NaN accounts receivable and unbilled revenue balances were reported in the other segment at September 30, 2020.

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. The incremental reserve included within our allowance for credit losses at September 30, 2020, specific to the economic risks associated with the COVID-19 pandemic, was not significant. We will continue to monitor the economic impacts of COVID-19 and the resulting effects that these impacts may have on the ability of our customers to pay their energy bills.

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by the PSCW if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 17, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic.

We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses.
(in millions)September 30, 2020
Accounts receivable and unbilled revenues$195.6
Allowance for credit losses14.7
Accounts receivable and unbilled revenues, net (1)
$180.9
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Total accounts receivable, net – past due greater than 90 days (1)
6Wisconsin Public Service Corporation$11.1
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)
93.4%

Table(1)Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of Contents

NOTE 4—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 taxuncollectible expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capitalbased on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at September 30, 2020, $66.3 million, or 36.7%, of our net accounts receivable and unbilled revenues balance sheet, and excess tax benefits could only be recognizedhad regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related 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 earningsdeferral of certain costs (including credit losses) incurred as a result of the adoptionCOVID-19 pandemic. The additional protections related to our September 30, 2020 accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentage in the above table or this note. See Note 17, Regulatory Environment, for more information.

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A rollforward of the allowance for credit losses for the three and nine months ended September 30, 2020, is included below:
(in millions)Three Months Ended September 30, 2020
Balance at June 30, 2020$10.0
Provision for credit losses3.5
Provision for credit losses deferred for future recovery or refund1.8
Write-offs charged against the allowance(1.5)
Recoveries of amounts previously written off0.9
Balance at September 30, 2020$14.7

(in millions)Nine Months Ended September 30, 2020
Balance at December 31, 2019$4.2
Provision for credit losses8.7
Provision for credit losses deferred for future recovery or refund5.1
Write-offs charged against the allowance(6.1)
Recoveries of amounts previously written off2.8
Balance at September 30, 2020$14.7

The increase in our allowance for credit losses in 2020 was driven by an increase in past due accounts receivable balances from December 31, 2019 to September 30, 2020. This ASU also requires excess tax benefitsis a trend we generally see over the winter moratorium months, when we are not allowed to be classifieddisconnect customer service as an operating activitya result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15. However, as a result of the statement of cash flows. We have elected to apply this provision on a prospective basis. As allowed under the ASU,COVID-19 pandemic and related regulatory orders we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

Asreceived, we were not requiredalso unable to record a cumulative-effect adjustment to retained earnings,disconnect any of our customers during the second and we did not record any excess tax benefits in 2017, adoptionthird quarters of this ASU had no impact2020. See Note 17, Regulatory Environment, for more information.

NOTE 4—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our financial statements.balance sheets at September 30, 2020 and December 31, 2019. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2019 Annual Report on Form 10-K.

(in millions)September 30, 2020December 31, 2019
Regulatory assets
Pension and OPEB costs$137.8 $151.8 
Environmental remediation costs112.4 113.5 
Plant retirements57.9 55.3 
Income tax related items44.6 38.9 
ReACT™18.8 20.8 
Asset retirement obligations16.5 8.4 
Forward Wind Energy Center12.2 17.9 
Termination of a tolling agreement with Fox Energy Company LLC5.8 9.9 
Other, net18.6 21.4 
Total regulatory assets$424.6 $437.9 
Restrictions

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(in millions)September 30, 2020December 31, 2019
Regulatory liabilities
Income tax related items$402.5 $416.7 
Removal costs196.5 201.8 
Pension and OPEB benefits98.6 100.5 
Earnings sharing mechanism32.5 42.0 
Energy costs refundable through rate adjustments10.9 20.0 
Electric transmission costs14.2 3.7 
Other, net11.5 11.5 
Total regulatory liabilities$766.7 $796.2 
Balance sheet presentation
Other current liabilities$5.2 $13.7 
Regulatory liabilities761.5 782.5 
Total regulatory liabilities$766.7 $796.2 

NOTE 5—COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to the sole holder of our common stock, Integrys, in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their subsidiaries. See Note 10, Common Equity, in our 20162019 Annual Report on Form 10-K for additional information on these and other restrictions.


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


NOTE 5—6—SHORT-TERM DEBT AND LINES OF CREDIT


The following table shows our short-term borrowings and their corresponding weighted-average interest rates:
(in millions, except percentages)September 30, 2020December 31, 2019
Commercial paper
Amount outstanding$16.0 $91.5 
Weighted-average interest rate on amounts outstanding0.14 %1.91 %
(in millions, except percentages) September 30, 2017 December 31, 2016
Commercial paper    
Amount outstanding $120.8
 $176.8
Weighted-average interest rate on amounts outstanding 1.24% 1.01%


Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2017,2020 was $126.5$62.2 million with a weighted-average interest rate during the period of 1.11%0.94%.


The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:
(in millions) Maturity September 30, 2017
Revolving credit facility * December 2020 $250.0
     
Less: commercial paper outstanding   $120.8
Available capacity under existing agreement   $129.2

*(in millions)In October 2017, we increased ourMaturitySeptember 30, 2020
Revolving credit facility to $400.0 million. We intend to request approval from the PSCW to extend the maturityOctober 2022$400.0
Less:
Letters of ourcredit issued inside credit facility to October 2022.$1.3
Commercial paper outstanding16.0
Available capacity under existing credit facility$382.7



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NOTE 6—7—MATERIALS, SUPPLIES, AND INVENTORIES


Our inventory consisted of:
(in millions)September 30, 2020December 31, 2019
Materials and supplies$57.9 $50.1 
Fossil fuel26.4 36.1 
Natural gas in storage21.4 20.2 
Total$105.7 $106.4 
(in millions) September 30, 2017 December 31, 2016
Fossil fuel $52.0
 $66.7
Materials and supplies 42.8
 37.5
Natural gas in storage 35.1
 21.1
Total $129.9
 $125.3


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


NOTE 7—8—INCOME TAXES

The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
Three Months Ended September 30, 2020Three Months Ended September 30, 2019
(in millions)AmountEffective Tax RateAmountEffective Tax Rate
Statutory federal income tax$20.1 21.0 %$15.1 21.0 %
State income taxes net of federal tax benefit5.9 6.2 %5.1 7.1 %
Federal excess deferred tax amortization – Wisconsin unprotected(4.3)(4.5)%0 0 %
Federal excess deferred tax amortization(1.8)(1.9)%(2.5)(3.4)%
Other(0.3)(0.4)%(0.7)(1.1)%
Total income tax expense$19.6 20.4 %$17.0 23.6 %

Nine Months Ended September 30, 2020Nine Months Ended September 30, 2019
(in millions)AmountEffective Tax RateAmountEffective Tax Rate
Statutory federal income tax$50.5 21.0 %$37.8 21.0 %
State income taxes net of federal tax benefit14.7 6.1 %11.8 6.5 %
Federal excess deferred tax amortization – Wisconsin unprotected(11.0)(4.6)%0 0 %
Federal excess deferred tax amortization(4.5)(1.9)%(5.0)(2.8)%
Other(1.3)(0.5)%(1.8)(0.9)%
Total income tax expense$48.4 20.1 %$42.8 23.8 %

The effective tax rates of 20.4% and 20.1% for the three and nine months ended September 30, 2020, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, we are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. In addition, as discussed in more detail below, the impact of the protected benefits associated with the Tax Legislation drove a decrease in the effective tax rate. These items were partially offset by state income taxes.

The effective tax rates of 23.6% and 23.8% for the three and nine months ended September 30, 2019, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to state income taxes, partially offset by the impact of the protected benefits associated with the Tax Legislation, which is discussed in more detail below.

The Tax Legislation required us to remeasure the deferred income taxes at our utility segment and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above).

See Note 17, Regulatory Environment, for more information.

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NOTE 9—FAIR VALUE MEASUREMENTS


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


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


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


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


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


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


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

We recognize transfers between 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, 2020
(in millions)Level 1Level 2Level 3Total
Derivative assets    
Natural gas contracts$4.9 $0.1 $0 $5.0 
FTRs0 0 1.9 1.9 
Coal contracts0 0.5 0 0.5 
Total derivative assets$4.9 $0.6 $1.9 $7.4 
Derivative liabilities    
Natural gas contracts$0.2 $0.2 $0 $0.4 
Coal contracts0 0.7 0 0.7 
Total derivative liabilities$0.2 $0.9 $0 $1.1 
  September 30, 2017
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets  
  
  
  
Natural gas contracts $0.9
 $0.1
 $—
 $1.0
Petroleum product contracts 0.2
 —
 —
 0.2
FTRs —
 —
 3.6
 3.6
Total derivative assets $1.1
 $0.1
 $3.6
 $4.8
         
Derivative liabilities  
  
  
  
Natural gas contracts $0.5
 $—
 $—
 $0.5
Coal contracts —
 0.9
 —
 0.9
Total derivative liabilities $0.5
 $0.9
 $—
 $1.4


  December 31, 2016
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.1
 $0.1
 $—
 $0.2
FTRs —
 —
 2.0
 2.0
Coal contracts —
 0.1
 —
 0.1
Total derivative assets $0.1
 $0.2
 $2.0
 $2.3
         
Derivative liabilities        
Coal contracts $—
 $1.4
 $—
 $1.4

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December 31, 2019
(in millions)Level 1Level 2Level 3Total
Derivative assets
Natural gas contracts$0.2 $0.2 $0 $0.4 
FTRs0 0 1.3 1.3 
Coal contracts0 0.4 0 0.4 
Total derivative assets$0.2 $0.6 $1.3 $2.1 
Derivative liabilities
Natural gas contracts$3.0 $0.2 $0 $3.2 
Coal contracts0 0.1 0 0.1 
Total derivative liabilities$3.0 $0.3 $0 $3.3 

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


The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
 Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Balance at the beginning of the period$3.4 $4.6 $1.3 $3.0 
Purchases0 0 4.0 5.4 
Settlements(1.5)(2.1)(3.4)(5.9)
Balance at the end of the period$1.9 $2.5 $1.9 $2.5 
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Balance at the beginning of period $5.8
 $5.9
 $2.0
 $2.0
Net realized and unrealized losses —
 —
 —
 (0.2)
Purchases —
 —
 6.9
 7.1
Sales —
 —
 —
 (0.2)
Settlements (2.2) (2.1) (5.3) (4.9)
Balance at the end of period $3.6
 $3.8
 $3.6
 $3.8

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 arewere not recorded at fair value:
 September 30, 2020December 31, 2019
(in millions)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt (1)
$1,613.2 $1,903.6 $1,612.1 $1,793.5 
  September 30, 2017 December 31, 2016
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current portion $1,290.9
 $1,404.0
 $1,290.3
 $1,373.4


Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, the(1)The carrying amount for each such item approximates fair value. of long-term debt excludes finance lease obligations of $31.0 million and $30.7 million at September 30, 2020 and December 31, 2019, respectively.

The fair value of our long-term debt is estimated based on the quoted market prices for the same or similar issues and is categorized within Level 2 of the fair value hierarchy.


NOTE 8—10—DERIVATIVE INSTRUMENTS


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


We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allowthe PSCW allows 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:liabilities, along with their classification on our balance sheets. NaN of our derivatives are designated as hedging instruments.
 September 30, 2020December 31, 2019
(in millions)Derivative AssetsDerivative LiabilitiesDerivative AssetsDerivative Liabilities
Other current
Natural gas contracts$4.3 $0.4 $0.4 $3.1 
FTRs1.9 0 1.3 0 
Coal contracts0.2 0.3 0.2 0 
Total other current (1)
6.4 0.7 1.9 3.1 
Other long-term
Natural gas contracts0.7 0 0 0.1 
Coal contracts0.3 0.4 0.2 0.1 
Total other long-term (1)
1.0 0.4 0.2 0.2 
Total$7.4 $1.1 $2.1 $3.3 
  September 30, 2017 December 31, 2016
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
Natural gas contracts $0.8
 $0.5
 $0.2
 $—
Petroleum products contracts 0.2
 —
 —
 —
FTRs 3.6
 —
 2.0
 —
Coal contracts —
 0.7
 —
 0.9
Total other current * $4.6
 $1.2
 $2.2
 $0.9
         
Other long-term        
Natural gas contracts $0.2
 $—
 $—
 $—
Coal contracts —
 0.2
 0.1
 0.5
Total other long-term * $0.2
 $0.2
 $0.1
 $0.5
Total $4.8
 $1.4
 $2.3
 $1.4


(1)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.
*On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.


Realized gains (losses) on derivative instrumentsderivatives are primarily includedrecorded 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, 2020Three Months Ended September 30, 2019
(in millions)VolumesGains (Losses)VolumesGains (Losses)
Natural gas contracts6.4 Dth$(1.7)6.7 Dth$(2.4)
FTRs2.3 MWh0.4 2.2 MWh2.3 
Total$(1.3)$(0.1)
  Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
(in millions) Volumes Gains (Losses) Volumes Gains
Natural gas contracts 4.0 Dth $(0.6) 6.0 Dth $0.5
Petroleum products contracts       0.3 gallons —
 1.0 gallons —
FTRs 2.5 MWh 1.8
 2.2 MWh 2.6
Total   $1.2
   $3.1


Nine Months Ended September 30, 2020Nine Months Ended September 30, 2019
(in millions)VolumesGains (Losses)VolumesGains (Losses)
Natural gas contracts27.6 Dth$(8.8)27.5 Dth$(3.6)
FTRs6.2 MWh0.9 7.2 MWh5.5 
Total$(7.9)$1.9 

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  Nine Months Ended September 30, 2017
Nine Months Ended September 30, 2016
(in millions) Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts 9.1 Dth $(1.1) 20.0 Dth $(1.3)
Petroleum products contracts 0.3 gallons —
 3.4 gallons (0.6)
FTRs 6.8 MWh 2.5
 6.3 MWh 4.9
Total   $1.4
   $3.0


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 September 30, 2017 and2020, we had received cash collateral of $1.7 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities. At December 31, 2016,2019, we had posted cash collateral of $21.2$4.8 million and $16.1 million, respectively, in our margin accounts. These amounts primarily relate to cash collateral posted with MISO.This amount was recorded on our balance sheet in other current assets.


The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
September 30, 2020December 31, 2019
(in millions)Derivative AssetsDerivative LiabilitiesDerivative AssetsDerivative Liabilities
Gross amount recognized on the balance sheet$7.4 $1.1 $2.1 $3.3 
Gross amount not offset on the balance sheet(1.9)(1)(0.2)(0.3)(3.1)(2)
Net amount$5.5 $0.9 $1.8 $0.2 

(1)Includes cash collateral received of $1.7 million.

(2)Includes cash collateral posted of $2.8 million.

  September 30, 2017 December 31, 2016
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Gross amount recognized on the balance sheet $4.8
 $1.4
 $2.3
 $1.4
Gross amount not offset on the balance sheet (0.5) (0.5) —
 —
Net amount $4.3
 $0.9
 $2.3
 $1.4

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NOTE 9—11—GUARANTEES


As of September 30, 2017,2020, we had a $1.9$20.6 million of standby letterletters of credit due in January 2018, that was issued by a financial institutioninstitutions for the benefit of a third partyparties that extended credit to us. This amountus which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.


NOTE 10—12—EMPLOYEE BENEFITS

Through December 31, 2016, we participated in the Integrys Energy Group Retirement Plan, a noncontributory, qualified pension plan sponsored by WBS. We were responsible for our share of the plan assets and obligations. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017, however we made additional contributions to the plan as discussed below. See Note 13, Related Parties, for more information.


The following tables show the components of net periodic pension and OPEB costsbenefit cost (credit) for our benefit plans:plans.
 Pension Benefits
 Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Service cost$2.5 $2.2 $7.4 $6.5 
Interest cost6.3 7.0 18.9 21.1 
Expected return on plan assets(12.1)(11.9)(36.4)(35.9)
Amortization of net actuarial loss5.9 4.4 17.8 13.3 
Net periodic benefit cost$2.6 $1.7 $7.7 $5.0 
  Pension Costs
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Service cost $2.2
 $2.3
 $6.7
 $6.9
Interest cost 6.6
 6.9
 20.0
 20.7
Expected return on plan assets (11.6) (12.9) (34.8) (38.9)
Gain (loss) on plan settlement —
 (0.1) —
 3.1
Amortization of net actuarial loss 4.4
 4.3
 13.0
 13.0
Net periodic benefit cost $1.6
 $0.5
 $4.9
 $4.8


 OPEB Benefits
 Three Months Ended September 30Nine Months Ended September 30
(in millions)2020201920202019
Service cost$1.1 $1.0 $3.3 $3.1 
Interest cost1.2 1.6 3.8 4.9 
Expected return on plan assets(4.5)(4.1)(13.6)(12.4)
Amortization of prior service credit(2.6)(2.9)(7.9)(8.6)
Amortization of net actuarial (gain) loss(0.3)0.4 (1.0)1.2 
Net periodic benefit credit$(5.1)$(4.0)$(15.4)$(11.8)

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  OPEB Costs
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Service cost $1.5
 $1.8
 $4.6
 $5.5
Interest cost 2.3
 2.6
 7.0
 7.9
Expected return on plan assets (4.1) (3.9) (12.3) (11.9)
Amortization of prior service credit (2.3) (1.9) (6.9) (5.6)
Amortization of net actuarial loss 0.7
 0.7
 1.9
 1.9
Net periodic benefit credit $(1.9) $(0.7) $(5.7) $(2.2)


During the nine months ended September 30, 2017,2020, we made contributions and payments of $65.6 million to our pension plans and $0.9 million to our OPEB plans. We expect to make payments of $0.1$0.5 million related to our pension plans duringand an insignificant amount related to our OPEB plans. Our expected contributions and payments related to our pension and OPEB plans for the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and tax law changes. We do not expect to contribute to the OPEB plans during the remainder of 2017.year are insignificant.


NOTE 11—13—GOODWILL AND OTHER INTANGIBLE ASSETS


Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no0 changes to the carrying amount of goodwill during the nine months ended September 30, 2017 and 2016. 2020.

In the third quarter of 2017,2020, we completed our annual goodwill impairment test, and no0 impairment resulted from this test.


The identifiable intangible assets other than goodwill listed below are classified as other long-term assets on our balance sheets.
  September 30, 2017 December 31, 2016
(in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount
Amortized intangible assets * $8.3
 $(5.3) $3.0
 $15.6
 $(10.7) $4.9
Unamortized intangible assets 0.4
 —
 0.4
 0.4
 —
 0.4
Total intangible assets $8.7
 $(5.3) $3.4
 $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 amortization period at September 30, 2017, was approximately three years.

NOTE 12—14—SEGMENT INFORMATION


We use operating income to measure segment profitability and to allocate resources to our businesses. At September 30, 2017,2020, we reported two2 segments, which are described below.


Our utility segment includes our electric and natural gas utility operations.operations, which serve customers in northeastern and central Wisconsin. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in northeastern Wisconsin.electricity. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers andas well as the transportation of customer-owned natural gas in northeastern Wisconsin. Effective January 1, 2017, we transferred our customers and electric and natural gas distribution assets located in the Upper Peninsula of Michigan to UMERC. See Note 13, Related Parties, and Note 16, Regulatory Environment, for more information.gas.


During 2017, theOur other segment included non-utility activities, as well asprimarily consists of 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 13, Related Parties, for more information.Wisconsin River Power Company.



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The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 20172020 and 2016:2019, related to our reportable segments:
(in millions)UtilityOtherWisconsin Public Service Corporation
Three Months Ended September 30, 2020
Operating revenues$367.7 $0 $367.7 
Other operation and maintenance105.2 0 105.2 
Depreciation and amortization43.5 0 43.5 
Operating income102.8 0 102.8 
Other income, net8.3 0.4 8.7 
Interest expense15.6 0 15.6 
(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated(in millions)UtilityOtherWisconsin Public Service Corporation
Three Months Ended September 30, 2017        
External revenues $380.7
 $—
 $—
 $380.7
Three Months Ended September 30, 2019Three Months Ended September 30, 2019
Operating revenuesOperating revenues$352.3 $0 $352.3 
Other operation and maintenance 100.0
 (0.1) —
 99.9
Other operation and maintenance107.4 0 107.4 
Depreciation and amortization 35.0
 0.1
 —
 35.1
Depreciation and amortization42.3 0 42.3 
Operating income 110.7
 —
 —
 110.7
Operating income78.0 0 78.0 
Other income, net 2.9
 0.1
 —
 3.0
Other income, net9.5 0.3 9.8 
Interest expense 13.7
 —
 —
 13.7
Interest expense15.8 0 15.8 


(in millions)UtilityOtherWisconsin Public Service Corporation
Nine Months Ended September 30, 2020
Operating revenues$1,049.9 $0 $1,049.9 
Other operation and maintenance296.3 0 296.3 
Depreciation and amortization129.7 0 129.7 
Operating income263.1 0 263.1 
Other income, net24.2 1.2 25.4 
Interest Expense47.9 0 47.9 
(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Three Months Ended September 30, 2016  
  
    
External revenues $381.0
 $—
 $—
 $381.0
Intersegment revenues —
 0.1
 (0.1) —
Other operation and maintenance 110.0
 0.2
 (0.1) 110.1
Depreciation and amortization 30.7
 —
 —
 30.7
Operating income (loss) 105.5
 (0.2) —
 105.3
Other income, net 6.3
 2.6
 —
 8.9
Interest expense 11.7
 —
 —
 11.7


(in millions)UtilityOtherWisconsin Public Service Corporation
Nine Months Ended September 30, 2019
Operating revenues$1,069.0 $0 $1,069.0 
Other operation and maintenance308.7 0 308.7 
Depreciation and amortization123.4 0 123.4 
Operating income198.4 0 198.4 
Other income, net28.0 1.0 29.0 
Interest expense47.2 0 47.2 

(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Nine Months Ended September 30, 2017        
External revenues $1,111.9
 $—
 $—
 $1,111.9
Other operation and maintenance 309.8
 0.4
 —
 310.2
Depreciation and amortization 103.9
 —
 —
 103.9
Operating income (loss) 247.9
 (0.4) —
 247.5
Other income, net 7.0
 1.9
 —
 8.9
Interest expense 41.2
 —
 —
 41.2

(in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated
Nine Months Ended September 30, 2016  
  
    
External revenues $1,087.2
 $—
 $—
 $1,087.2
Intersegment revenues —
 0.4
 (0.4) —
Other operation and maintenance 359.5
 0.2
 (0.4) 359.3
Depreciation and amortization 91.7
 —
 —
 91.7
Operating income 225.5
 0.1
 —
 225.6
Other income, net 18.5
 7.2
 —
 25.7
Interest expense 35.2
 0.1
 —
 35.3

NOTE 13—RELATED PARTIES

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

We provide and receive services, property, and other items of value to and from our ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group.

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A new AIA took effect January 1, 2017. 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. All of the applicable state commissions approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater, which is discussed in more detail below.

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 $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 therefore, did not result in the recognition of a gain or loss.

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

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

Our balance sheets included the following receivables and payables related to transactions entered into with related parties:
(in millions) September 30, 2017 December 31, 2016
Accounts receivable    
Services provided to ATC $0.5
 $1.1
Accounts payable  
  
Network transmission services from ATC 9.0
 8.8
Liability related to income tax allocation    
Integrys 4.3
 4.8


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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
(in millions) 2017 2016 2017 2016
Transactions with WE (1)
        
Natural gas sales to WE $0.8
 $1.0
 $1.3
 $1.7
Billings to WE 1.4
 1.4
 3.6
 1.9
Billings from WE 6.4
 4.1
 14.1
 7.0
Transactions with WBS (1)
        
Net cash (paid) received for transfer of pension assets (2)
 (4.1) —
 157.8
 —
Billings to WBS (3)
 2.9
 4.5
 13.4
 17.8
Billings from WBS (4)
 26.1
 52.8
 94.3
 135.2
Transactions with UMERC (5)
        
Electric sales to UMERC 4.1
 —
 12.2
 —
Billings from UMERC (1)
 5.5
 —
 12.2
 —
Transactions with Bluewater (6)
        
Storage service fees 0.2
 —
 0.2
 —
Transactions related to ATC    
    
Charges from ATC for network transmission services 27.0
 27.8
 80.9
 83.2
Charges to ATC for services and construction 1.4
 2.2
 4.2
 6.2
Refund from ATC per FERC ROE order —
 —
 (8.9) —
Transactions with equity-method investees        
Rental payments to WRPC (7)
 0.4
 —
 0.9
 —
Purchases of energy from WRPC (7)
 —
 1.0
 0.5
 2.9
Charges from WRPC for services 0.6
 —
 1.4
 —
Charges to WRPC for operations 0.2
 0.2
 0.7
 0.5
Equity earnings from WPSI —
 2.3
 —
 6.4

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

(2)
Relates to our transfer of pension trust assets in conjunction with the Integrys pension plan split. See Note 10, Employee Benefits, for more information.

(3)
Includes $7.3 million for the transfer of certain assets to WBS for the nine months ended September 30, 2016. There were no transfers of assets to WBS for the three and nine months ended September 30, 2017, and the three months ended September 30, 2016.

(4)
Includes $0.8 million and $10.0 million for the transfer of certain assets to us for the three and nine months ended September 30, 2017, respectively. Includes $12.3 million and $18.2 million, respectively, for the transfer of certain benefit-related liabilities to WBS for the three and nine months ended September 30, 2016.

(5)
UMERC became operational effective January 1, 2017. See below for more information.

(6)
The acquisition of Bluewater was completed June 30, 2017. See below for more information.

(7)
In March 2017, we terminated our purchased power agreement with WRPC and entered into an agreement with WRPC to rent 50% of its hydroelectric power generation facilities.

Upper Michigan Energy Resources Corporation

In December 2016, both the 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.


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UMERC obtains its energy and capacity requirements to supply its customers through power purchase agreements with us and WE.

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

On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that will provide for a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with Bluewater to take the allocated storage. See Note 16, Regulatory Environment, for more information.

NOTE 14—15—COMMITMENTS AND CONTINGENCIES


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


Unconditional Purchase Obligations


We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of September 30, 2017,2020, were $1,085.6 million.approximately $0.7 billion.


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Environmental Matters


Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx,sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposalmanagement 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 Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing the CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015 and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this 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, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and will finalize its designation by the end of 2017. We believe our fleet overall is well positioned to meet the regulation 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

Sheboygan County is currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has submitted an attainment plan for Sheboygan County to the EPA, and a decision is expected later in 2017.

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expectedNational Ambient Air Quality Standards. The EPA issued final nonattainment area designations in April 2018. The following counties within our service territory were designated as partial nonattainment with the 2015 standard: Door and Manitowoc. A decision was issued in July 2020 remanding the rule to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (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. further evaluation. We expect that any subsequent EPA re-designation, if necessary, would take place in 2021.The EPA is currently scheduled to finalize designations later in 2017. For nonattainment areas, the stateState of Wisconsin will have to develop asubmitted the "infrastructure" portion of its state implementation plan outlining how it will implement, maintain, and enforce the 2015 Ozone standard. The plan is subject to bringEPA review and approval. We do not expect the areas back into attainment. We will berevised plan to have an impact on us.

Mercury and Air Toxics Standards

In May 2020, the EPA finalized revisions to the Supplemental Cost Finding for the MATS rule as well as the CAA required RTR. The EPA was required by the United States Supreme Court to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts forreview both costs and benefits of complying with the 2015 ozone NAAQS untilMATS rule. After its review of costs, the designationsEPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. As a result, under the final rule, the emission standards and other requirements of the MATS rule first enacted in 2012 remain in place. The EPA did not remove coal- and oil-fired power plants from the list of sources that are final and untilregulated under Section 112. The EPA also determined that 0 revisions to MATS are warranted based on the state preparesresults of the RTR. As a draft attainment plan.

Althoughresult, we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet the ozone standard and do not expect the rule to incur significant costs to comply.have a material impact on our financial condition or results of operations.


Climate Change


In 2015, the EPA issued a finalThe ACE rule regulating GHG emissions frombecame effective in September 2019. This rule provides existing coal-fired generating units referred to aswith standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, (CPP)and (2) revised implementing regulations for ACE, ongoing emissions guidelines, and all future emission guidelines for existing sources issued under CAA section 111(d). Every state's plan to implement ACE is required to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The rule is being litigated in challenges brought in the United States Court of Appeals for the District of Columbia Circuit by 22 states (including Wisconsin), alocal governments, and certain nongovernmental organizations. In the meantime, the Wisconsin Department of Natural Resources continues to work with state utilities and has begun the process of developing the implementation plan with respect to the ACE rule.

In December 2018, the EPA proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standardsrevise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 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 CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. 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.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, 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 announceddetermined that itthe BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage. The EPA has initiated this review. As a result of this orderreviewed comments and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrewintends to take final action on the proposed rule for a federal plan and model trading rules that were publishedlater in October 2015 for use in developing state plans to implement the CPP or for use in states where2020.

WEC Energy Group has a plan is not submitted or approved. In October 2017,(referred to as its ESG progress plan), which includes us, that includes the EPA issued a noticeretirement of proposed rulemakingolder, fossil-fueled generation, to repealbe replaced with the CPP. The EPA is expected subsequently to issue an advanced noticeconstruction of proposed rulemaking that will solicit input on whether it is appropriate to replacezero-carbon emitting renewable generation and clean natural gas-fired generation. We have already retired approximately 300 MW of coal-fired generation since the CPP. In addition,beginning of 2018, which included the Governor of Wisconsin issued 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 CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups,Pulliam power plant and the Statejointly-owned Edgewater Unit 4 generating units. WEC Energy Group expects to retire approximately 1,800 MW of Wisconsin, withadditional fossil-fueled generation by 2025. The retirements will contribute to meeting a new, near-term goal of reducing WEC Energy Group's CO2emissions from its electric generation by 55% below 2005 levels by 2025. In 2019, WEC Energy Group met and surpassed its original goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. We have implementedIn July 2020, WEC Energy Group announced a new goal to reduce CO2 emissions from its electric generation by 70% below 2005 levels by 2030 and continue to evaluate numerous options in order to meet our CO2 reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.


be net
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carbon neutral by 2050. In addition to retiring these older, fossil-fueled plants, WEC Energy Group expects to invest in low-cost renewable energy in Wisconsin. WEC Energy Group's plan is to replace a portion of the retired capacity by building and owning a combination of clean, natural gas-fired generation and zero-carbon-emitting renewable generation facilities.
Water Quality

WEC Energy Group also has a goal to decrease the rate of methane emissions from the natural gas distribution lines in its network by 30% per mile by the year 2030 from a 2011 baseline. WEC Energy Group was over half way toward meeting that goal at the end of 2019.
Clean Water Act Cooling Water Intake Structure Rule

National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines
In August 2014,
Effective in March 2020, the EPA issued a final regulation, under Section 316(b) ofThe Combustion Turbine Rule. The Combustion Turbine Rule was issued to complete the Clean Water Act, which requires thatRTR required by the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014,CAA every five years, and applies only to all of our existing generating facilities with cooling water intake structures.

Facility owners must select from seven compliance options available to meetcombustion turbines constructed or reconstructed after January 14, 2003. The Combustion Turbine Rule clarifies certain performance testing, semi-annual and excess emission reporting requirements, implements electronic reporting requirements, and changes certain requirements applicable during startup, shutdown, and malfunction. We have evaluated the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

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

During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these 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 the 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. We expect to submit entrainment studies being conducted at Pulliam Units 7 and 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.the rule will have a material impact on our financial condition or results of operations.


Water Quality

Steam Electric Effluent Limitation Guidelines


The EPA's final steam electric effluent limitations guidelines (ELG)2015 ELG rule took effect in January 2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements. This rule applies to wastewater discharges from ourcreated new requirements for several types of power plant processes in Wisconsin. Whilewastewaters. The new requirement that affects us relates to discharge limits for BATW. As a result of past capital investments, we believe our fleet is well positioned to meet the existing ELG compliance deadlines are postponed, the WDNR has indicated that it will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR has indicated that it will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years.regulations. Our Weston power plant facilitiesfacility already havehas advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed,There will, however, need to be modifications to the ELGBATW systems at Weston Unit 3. Based on preliminary engineering, we estimate that compliance with the current rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.$10 million in capital costs.


The ELG requirements for BATW systems were being re-evaluated by the EPA. In September 2017, the EPA issued a final rule would phase in new or more stringent(Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW requirements while it re-evaluated the ELG rule. The Postponement Rule left unchanged the latest ELG rule compliance date of December 31, 2023. In August 2020, the EPA Administrator signed the ELG Reconsideration Rule to revise the treatment technology requirements related to limits of arsenic, mercury, selenium,BATW at existing facilities. This rule is effective December 14, 2020 and nitrogen in wastewater dischargedincludes provisions that:

•Exempt facility owners from wet scrubber systems. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new BATW requirements if a generating unit is retired by December 31, 2028.

•Would limit the investment required to meet these new rule and modifications would be required at Pulliam Units 7 and 8 and Weston Unit 3. requirements if the coal-fueled unit has a low utilization rate where the 2-year average annual capacity utilization rating is less than 10%.

We are beginning preliminary engineering for compliance withcurrently evaluating what impact, if any, the rule and estimate a totalmay have on our estimated compliance cost range of $25$10 million to $35 million for these advanced treatment and bottom ash transport systems.noted above.


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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.


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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 tofor manufactured gas plant sites:
(in millions)September 30, 2020December 31, 2019
Regulatory assets$112.4 $113.5 
Reserves for future environmental remediation83.8 83.8 
(in millions) September 30, 2017 December 31, 2016
Regulatory assets $113.0
 $116.0
Reserves for future remediation 96.0
 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.


Consent Decrees


Weston and Pulliam Consent DecreePower Plants


In November 2009, the EPA issued aan NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power 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.


Also,With the retirement of Pulliam Units 7 and 8 in May 2010,October 2018, we completed the mitigation projects required by the Consent Decree and received a completeness letter 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.EPA in October 2018. We entered into a Standstill Agreementare working with the Sierra Club by whichEPA on a closeout process for 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 September 30, 2017. It is unknown whether the Sierra Club will take further action in the future.Consent Decree.


Joint Ownership Power Plants Consent Decree – Columbia and Edgewater


In December 2009, the EPA issued aan NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018.


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 impact on our financial condition or results of operations.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION
Nine Months Ended September 30
(in millions)20202019
Cash paid for interest, net of amount capitalized$35.7 $30.9 
Cash (received) for income taxes, net(16.4)(23.2)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs48.6 34.3 

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NOTE 17—REGULATORY ENVIRONMENT

Coronavirus Disease – 2019

The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territory. In response to the COVID-19 pandemic, Wisconsin declared a public health emergency and issued a shelter-in-place order, which has since been lifted. On March 24, 2020, the PSCW issued 2 orders requiring certain actions to ensure that essential utility services were, and continue to be, available to our customers. The first order required all public utilities in the state of Wisconsin, including us, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.

In the second order issued on March 24, 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW has affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As we already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for our commercial and industrial customers. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of September 30, 2020, our deferrals related to the COVID-19 pandemic were not significant.

On June 26, 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 24, 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. We resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020.

The PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which begins on November 1 and ends on April 15. Utilities are allowed to continue assessing late fees during the winter moratorium.

2020 and 2021 Rates

In March 2019, we filed an application with the PSCW to increase our retail electric and natural gas rates, effective January 1, 2020. In August 2019, we filed an application with the PSCW for approval of a settlement agreement entered into with certain intervenors to resolve several outstanding issues in our rate case. In December 2019, the PSCW issued a written order that approved the settlement agreement without material modification and addressed the remaining outstanding issues that were not included in the settlement agreement. The new rates became effective January 1, 2020. The final order reflects the following:
2020 Effective rate increase
Electric (1) (2)
$15.8  million/1.6%
Gas (3)
$4.3  million/1.4%
ROE10.0%
Common equity component average on a financial basis52.5%

(1)Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts to our customers. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. Approximately $11 million of tax benefits are being amortized in 2020 and approximately $39 million will be amortized in 2021. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW.

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(2)The rate order is net of $21 million of refunds related to our 2018 earnings sharing mechanism. These refunds will be made to customers evenly over two years, with half being returned in 2020 and the remainder in 2021.


(3)Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts to our customers. 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. Managementrate order reflects all of the joint owners has recommendedunprotected deferred tax benefits from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax benefits being amortized each year. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW.

Our rate order allows us to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset will be collected from customers over eight years.

We will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that Edgewater Unit 4 be retired by December 2018. See Note 3, Property, Plant,is consistent with other Wisconsin investor-owned utilities. Under the new earnings sharing mechanism, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and Equipment,(iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate order also requires us to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for more informationour electric market-based rate programs for large industrial customers through 2021.

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION
  Nine Months Ended September 30
(in millions) 2017 2016
Cash (paid) for interest, net of amount capitalized $(27.8) $(27.5)
Cash (paid) received for income taxes, net (27.5) 48.8
Significant noncash transactions:    
Accounts payable related to construction costs 36.3
 42.2
Transfer of ownership in WPSI to another subsidiary of Integrys * 67.2
 —
Transfer of net assets to UMERC * 21.1
 —

*See Note 13, Related Parties, for more information on these transactions.

NOTE 16—REGULATORY ENVIRONMENT


2018 and 2019 Wisconsin Rates


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


In addition to freezing base rates, the settlement agreement extendsextended and expandsexpanded the electric real-time market pricing program options for large commercial and industrial customers. In addition, we will defer the revenue requirement impacts of any federal corporate tax reform enacted in 2017 or during the base rate freeze period. Additionally, the agreement allowsallowed us to extend, through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to our electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million.


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


Natural Gas Storage Facilities in Michigan

NOTE 18—NEW ACCOUNTING PRONOUNCEMENTS

Cloud Computing

In January 2017, WEC Energy Group signedAugust 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide a portion 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 in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreements and interstate natural gas transportation contractsasset related to the storage facilities. We also requested approvalservice contract and which costs to amend WEC Energy Group's AIA to ensure WBSexpense. The guidance specifies classification for capitalizing implementation costs and WEC Energy Group's other subsidiaries could provide servicesrelated amortization expense within the financial statements and requires additional disclosures. The adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements and related disclosures.

Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the storage facilities. During June 2017,Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the PSCW granted, subjectdisclosure requirements for defined benefit pension and OPEB plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we finalizedall periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the long-term service agreement for the natural gas storage and filed with the PSCW for approvaleffects of this agreement. We expectpronouncement on the notes to receive approval of the service agreement in the fourth quarter of 2017. See Note 13, Related Parties, for more information.our financial statements.



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Simplifying the Accounting for Income Taxes
Upper Michigan Energy Resources Corporation

Formation of Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WE and us, located in the Upper Peninsula of Michigan.

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 rate order now apply to UMERC, including the related deferrals.

NOTE 17—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.

We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan 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 beginning of 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 finalizing our review of our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our 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 our operating revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition. 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.

Recognition and Measurement of Financial Instruments

In January 2016,2019, the FASB issued ASU 2016-01, Recognition2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and Measurementcalculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of Financial Assets and Liabilities. Thisa consolidated group. The guidance iswill be effective for fiscal yearsannual and interim periods beginning after December 15, 2017,2020. We plan to adopt the new standard effective January 1, 2021, and will be recorded, if applicable, 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 do not believeexpect the adoption of this guidance willto have a significantmaterial impact on our financial statements.statements and related disclosures.


LeasesReference Rate Reform


In February 2016,March 2020, the FASB issued ASU 2016-02, Leases. This guidance isNo. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning afterall entities as of March 12, 2020 through 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.31, 2022. We are currently assessingevaluating the effectsimpact this guidance may have on our financial statements.statements and related disclosures.



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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. While we have not fully determined the impacts of the adoption of this standard, we expect that as a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components), will be recognized in our financial statements consistent with the current ratemaking treatment. As a result, we believe the impacts of adoption will be limited to changes in classification of non-service costs in the income 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 2019 Annual Report on Form 10-K for the year ended December 31, 2016.10-K.


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 Wisconsin.customers. 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 12,14, 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 13, 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 13, Related Parties, for more information.

Corporate Strategy


Our goal is to continue to createbuild and sustain long-term value for our customers and WEC Energy Group's shareholders by focusing on the following:fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety. WEC Energy Group's plan, referred to as its ESG progress plan, for efficiency, sustainability and growth will provide us a roadmap for achieving this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow our investment in the future of energy.


Creating a Cleaner Energy Future

WEC Energy Group's ESG progress plan includes the retirement of older, fossil-fueled generation, to be replaced with the construction of zero-carbon-emitting renewable generation and clean natural gas-fired generation. When taken together, the retirements and new investments should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting a new, near-term goal of reducing WEC Energy Group's carbon dioxide (CO2) emissions from electric generation by 55% below 2005 levels by 2025.

In 2019, WEC Energy Group met and surpassed its original goal to reduce CO2 emissions by 40% below 2005 levels by 2030. In July 2020, WEC Energy Group announced a new goal, to reduce CO2 emissions from electricity generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050.

WEC Energy Group has already retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018 across its electric utilities, which included the 2018 retirement of the Pulliam power plant as well as the jointly-owned Edgewater Unit 4 generating units. As part of its ESG progress plan, WEC Energy Group expects to retire approximately 1,800 MW of additional fossil-fueled generation by 2025.

In addition to retiring these older, fossil-fueled plants, WEC Energy Group expects to invest approximately $2 billion in low-cost renewable energy in Wisconsin. WEC Energy Group's plan is to replace a portion of the retired capacity by building and owning a combination of clean, natural gas-fired generation and zero-carbon-emitting renewable generation facilities that are anticipated to include:

•800 MW of utility-scale solar;
•600 MW of battery storage;
•100 MW of wind; and
•100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation.

WEC Energy Group also plans to purchase 200 MW of capacity in the West Riverside Energy Center — a new, combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin. These new investments are in addition to the renewable projects currently underway.

We have partnered with an unaffiliated utility to construct two utility-scale solar projects in Wisconsin. Two Creeks Solar Park (Two Creeks) is located in Manitowoc County, Wisconsin, and Badger Hollow Solar Park I (Badger Hollow I) is located in Iowa County, Wisconsin. Upon completion, we will own 100 MW of each project for a total of 200 MW. The Public Service Commission of Wisconsin approved the acquisition of these two projects in April 2019. Commercial operation was achieved in the first week of November 2020 for Two Creeks, and is targeted for April 2021 for Badger Hollow I.
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WEC Energy Group also has a goal to decrease the rate of methane emissions from the natural gas distribution lines in its network by 30% per mile by the year 2030 from a 2011 baseline. WEC Energy Group was over half way toward meeting that goal at the end of 2019. In April 2019, WEC Energy Group issued a climate report, which analyzes its GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. WEC Energy Group will evaluate potential GHG reduction pathways as climate change policies and relevant technologies evolve over time.

Reliability


We have made significant reliability relatedreliability-related investments in recent years, and in accordance with WEC Energy Group's ESG progress plan, expect to continue making significant capital investments to strengthenstrengthening and modernize the reliability ofmodernizing our generation fleet and distribution networks.networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in us being recognized in 2019 by PA Consulting Group, an independent consulting firm, as an Outstanding Midsize Utility.


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


Operating Efficiency


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


WEC Energy Group continues to focus on integrating and improving business processes and IT infrastructure across allthe resources of its companies.businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements. We expect these integration effortsalso strive to continueprovide the best value to drive operational efficiency.our customers and WEC Energy Group's shareholders by embracing constructive change, leveraging capabilities and expertise, and using creative solutions to meet or exceed our customers' expectations.


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,plants, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Acquisition, for information on the acquisition of a portion of a wind energy generation facility in Wisconsin.

WEC Energy Group has developed and is executing a strategy to reshape its generation portfolio in order to reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. Subject to final review, WEC Energy Group plans on retiring approximately 1,800 MWs of coal generation by 2020 across its electric utilities. See Note 3, Property, Plant, and Equipment, for

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information related to the planned retirement of our jointly-owned Edgewater 4 generation unit. In addition, as part of WEC Energy Group’s strategy, we plan to retire our Pulliam power plant in Green Bay, WI, subject to the completion of a significant transmission project in that area. We, along with WEC Energy Group, are also reviewing retirements of additional coal-fired generation units.


Exceptional Customer Care


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

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


Safety


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


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RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 20172020


Consolidated Earnings


Our consolidated earnings for the three months ended September 30, 20172020 were $60.9$76.3 million, compared to $64.7$55.0 million for the same quarter in 2016.2019. See below for additional information on the $3.8$21.3 million decreaseincrease 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 meaningfuluseful 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 September 30, 20172020 and 20162019 was $110.7$102.8 million and $105.5$78.0 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.



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Utility Segment Contribution to Operating Income


The following table compares our utility segment's contribution to operating income forduring the third quarter of 20172020, compared with the thirdsame quarter of 2016,in 2019, including favorable or better, "B", and unfavorable or worse, "W", 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 13, Related Parties, for more information.
Three Months Ended September 30
(in millions)20202019B (W)
Electric revenues$328.2 $312.9 $15.3 
Fuel and purchased power88.9 97.3 8.4 
Total electric margins239.3 215.6 23.7 
Natural gas revenues39.5 39.4 0.1 
Cost of natural gas sold16.4 17.2 0.8 
Total natural gas margins23.1 22.2 0.9 
Total electric and natural gas margins262.4 237.8 24.6 
Other operation and maintenance105.2 107.4 2.2 
Depreciation and amortization43.5 42.3 (1.2)
Property and revenue taxes10.9 10.1 (0.8)
Operating income$102.8 $78.0 $24.8 

  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Electric revenues $337.5
 $340.0
 $(2.5)
Fuel and purchased power 106.6
 108.4
 1.8
Total electric margins 230.9
 231.6
 (0.7)
       
Natural gas revenues 43.2
 41.0
 2.2
Cost of natural gas sold 18.5
 16.4
 (2.1)
Total natural gas margins 24.7
 24.6
 0.1
       
Total electric and natural gas margins 255.6
 256.2
 (0.6)
       
Other operation and maintenance 100.0
 110.0
 10.0
Depreciation and amortization 35.0
 30.7
 (4.3)
Property and revenue taxes 9.9
 10.0
 0.1
Operating income $110.7
 $105.5
 $5.2

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The following table shows a breakdown of other operation and maintenance:
Three Months Ended September 30
(in millions)20202019B (W)
Operation and maintenance not included in line items below$54.5 $62.6 $8.1 
Transmission (1)
40.0 37.4 (2.6)
Regulatory amortizations and other pass through expenses (2)
10.7 7.4 (3.3)
Total other operation and maintenance$105.2 $107.4 $2.2 
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Operation and maintenance not included in line items below $54.3
 $60.9
 $6.6
Transmission (1)
 38.7
 38.7
 —
Regulatory amortizations and other pass through expenses (2)
 7.0
 10.4
 3.4
Total other operation and maintenance $100.0
 $110.0
 $10.0


(1)Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for 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 September 30, 2020 and 2019, $37.6 million and $36.3 million, respectively, of costs were billed to us by transmission providers.
(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 September 30, 2017 and 2016, $39.7 million and $39.6 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.

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

The following tables provide information on delivered sales volumes by customer class and weather statistics:
Three Months Ended September 30
MWh (in thousands)
Electric Sales Volumes20202019B (W)
Customer class  
Residential875.4 805.7 69.7 
Small commercial and industrial1,080.9 1,071.0 9.9 
Large commercial and industrial950.7 991.8 (41.1)
Other5.9 5.9 — 
Total retail2,912.9 2,874.4 38.5 
Wholesale577.3 595.7 (18.4)
Resale168.3 165.6 2.7 
Total sales in MWh3,658.5 3,635.7 22.8 
  Three Months Ended September 30
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W)
Customer class  
  
  
Residential 753.1
 845.0
 (91.9)
Small commercial and industrial 1,085.6
 1,099.9
 (14.3)
Large commercial and industrial 1,039.8
 1,089.1
 (49.3)
Other 5.9
 6.1
 (0.2)
Total retail 2,884.4
 3,040.1
 (155.7)
Wholesale 766.2
 717.5
 48.7
Resale 294.4
 110.1
 184.3
Total sales in MWh 3,945.0
 3,867.7

77.3


Three Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes20202019B (W)
Customer class  
Residential14.4 11.8 2.6 
Commercial and industrial23.7 19.8 3.9 
Total retail38.1 31.6 6.5 
Transport87.4 85.6 1.8 
Total sales in therms125.5 117.2 8.3 


Three Months Ended September 30
Degree Days
Weather (1)
20202019B (W)
Heating (189 Normal)198 98 102.0 %
Cooling (376 Normal)471 424 11.1 %

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

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  Three Months Ended September 30
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W)
Customer class  
  
  
Residential 13.7
 13.3
 0.4
Commercial and industrial 20.3
 18.9
 1.4
Total retail 34.0
 32.2
 1.8
Transport 87.1
 84.1
 3.0
Total sales in therms 121.1
 116.3
 4.8

  Three Months Ended September 30
  Degree Days
Weather * 2017
2016 B (W)
Heating (200 normal) 178
 79
 99
Cooling (363 normal) 315
 426
 (111)

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

Electric Utility Margins


Electric utility margins decreased $0.7increased $23.7 million during the third quarter of 2017,2020, compared with the same quarter in 2016.2019. The significant factors impacting the lowerhigher electric utility margins were:


An $8.0•A $23.3 million decreasenet increase in margins related to lower retailthe impact of our rate order approved by the PSCW, effective January 1, 2020. This increase in margins includes the impact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in income taxes.

•A $3.5 million increase in margins related to higher residential sales volumes, during the third quarter of 2017, primarily driven by the impact of cooler summer weather and the transfer of customers and their related sales to UMERC.favorable weather. As measured by cooling degree days, the third quarter of 20172020 was 26.1% cooler11.1% warmer than the same quarter in 2016.

A $3.2 million decrease in retail demand revenues during2019. As measured by heating degree days, the third quarter of 2017, driven by lower peak usage due to2020 was 102.0% colder than the cooler summer weather.same quarter in 2019.


These decreasesincreases in margins were partially offset by:

A $5.1by a $1.4 million quarter-over-quarter positivenegative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by underunder- 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 $3.2 million increase in wholesale margins during the third quarter of 2017, driven by UMERC purchasing a portion of its energy from us.


Natural Gas Utility Margins


Natural gas utility margins increased $0.1$0.9 million during the third quarter of 2017,2020, compared with the same quarter in 2016,2019. The most significant factor impacting the higher natural gas utility margins was an increase in margins from higher sales volumes, driven by an increase in sales volumes.heating degree days during the third quarter of 2020, compared to the same quarter in 2019.


Operating Income


Operating income at the utility segment increased $5.2$24.8 million during the third quarter of 2017,2020, compared with the same quarter in 2016. The2019. This increase was driven by a $5.8the $24.6 million decreaseincrease in margins discussed above, in addition to $0.2 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $0.6 million net decrease in margins discussed above..


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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 factorsfactor impacting the decrease in operating expenses which were dueduring the third quarter of 2020, compared with the same quarter in part to synergy savings, were:

A $7.82019, was an $8.6 million decrease in operationelectric and natural gas distribution expenses, driven by lower maintenance and storm restoration expense, as well as our focus on operating efficiency.

This decrease in operating expenses related to our plants.
was partially offset by:


•A $3.4$3.3 million decreaseincrease in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.


These decreases•A $2.6 million increase in operating expenses were partially offset by a $4.3transmission expense as approved in the PSCW's 2019 rate order, which was effective January 1, 2020. See the notes under the other operation and maintenance table above for more information.

•A $1.2 million increase in depreciation and amortization, expense, driven by the ReACTTM multi-pollutant control system at Weston Unit 3 goingassets being placed into service during the fourth quarter of 2016.as we continue to execute on our capital plan.


Other Segment Contribution to Operating Income
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Operating loss $—
 $(0.2) $0.2

Consolidated Other Income, Net
 Three Months Ended September 30
(in millions)20202019B (W)
AFUDC – Equity$3.4 $1.8 $1.6 
Non-service components of net periodic benefit costs4.9 4.6 0.3 
Other, net0.4 3.4 (3.0)
Other income, net$8.7 $9.8 $(1.1)

  Three Months Ended September 30
(in millions) 2017 2016 B (W)
AFUDC – Equity $1.1
 $5.6
 $(4.5)
Earnings from equity method investments 0.2
 2.4
 (2.2)
Other, net 1.7
 0.9
 0.8
Other income, net $3.0
 $8.9
 $(5.9)

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Other income, net decreased by $5.9$1.1 million when compared toduring the third quarter of 2016,2020, compared with the same quarter in 2019. The decrease was primarily due to a decrease in AFUDC driven by the ReACTTM emission control technology at Weston Unit 3 going into service2019 deferral of costs that were offset in other income statement line items and had no impact on net income. This decrease was partially offset by higher AFUDC – Equity 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 13, Related Parties, for more information.

Consolidated Interest Expense
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Interest expense $13.7
 $11.7
 $(2.0)

Interest expense increased by $2.0 million, as compared to the third quarter of 2016, primarily due to a decrease in capitalized interest2020, driven by the ReACTTM emission control technology at Weston Unit 3 going into service during the fourth quarter of 2016.continued capital investment.


Consolidated Interest Expense
 Three Months Ended September 30
(in millions)20202019B (W)
Interest expense$15.6 $15.8 $0.2 

Income Tax Expense
 Three Months Ended September 30
 20202019B (W)
Effective tax rate20.4 %23.6 %3.2 %
  Three Months Ended September 30
  2017 2016 B (W)
Effective tax rate 39.1% 36.9% (2.2)%


Our effective tax rate increaseddecreased by 2.2% when compared with3.2% during the third quarter of 2016,2020, compared with the same quarter in 2019. The decrease was primarily due to athe 2020 amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with our Wisconsin rate order approved by the PSCW, effective January 1, 2020. This decrease in our effective tax rate was partially offset by the projected 2017 annual taximpact of the protected benefits associated with AFUDC – Equity.the Tax Legislation. These items did not impact earnings as they were offset in operating income. See Note 8, Income Taxes, and Note 17, Regulatory Environment, for more information.


NINE MONTHS ENDED SEPTEMBER 30, 20172020


Consolidated Earnings


Our consolidated earnings for the nine months ended September 30, 20172020 were $130.9$192.2 million, compared to $135.5$137.4 million for the same period in 2016.2019. See below for additional information on the $4.6$54.8 million decreaseincrease 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 meaningfuluseful 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 nine months ended September 30, 20172020 and 20162019 was $247.9$263.1 million and $225.5$198.4 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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Utility Segment Contribution to Operating Income

Nine Months Ended September 30
(in millions)20202019B (W)
Electric revenues$863.9 $855.0 $8.9 
Fuel and purchased power238.0 281.5 43.5 
Total electric margins625.9 573.5 52.4 
Natural gas revenues186.0 214.0 (28.0)
Cost of natural gas sold92.3 126.6 34.3 
Total natural gas margins93.7 87.4 6.3 
Total electric and natural gas margins719.6 660.9 58.7 
Other operation and maintenance296.3 308.7 12.4 
Depreciation and amortization129.7 123.4 (6.3)
Property and revenue taxes30.5 30.4 (0.1)
Operating income$263.1 $198.4 $64.7 
The following table compares our utility segment's contribution to operating income for the nine months ended September 30, 2017, with the nine months ended September 30, 2016, including favorable or better, "B", and unfavorable or worse, "W", 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 13, Related Parties, for more information.
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Electric revenues $914.7
 $903.9
 $10.8
Fuel and purchased power 311.4
 286.2
 (25.2)
Total electric margins 603.3
 617.7
 (14.4)
       
Natural gas revenues 197.2
 183.3
 13.9
Cost of natural gas sold 109.1
 94.5
 (14.6)
Total natural gas margins 88.1
 88.8
 (0.7)
       
Total electric and natural gas margins 691.4
 706.5
 (15.1)
       
Other operation and maintenance 309.8
 359.5
 49.7
Depreciation and amortization 103.9
 91.7
 (12.2)
Property and revenue taxes 29.8
 29.8
 —
Operating income $247.9
 $225.5
 $22.4


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The following table shows a breakdown of other operation and maintenance:
Nine Months Ended September 30
(in millions)20202019B (W)
Operation and maintenance not included in line items below$147.9 $174.6 $26.7 
Transmission (1)
119.9 110.2 (9.7)
Regulatory amortizations and other pass through expenses (2)
28.5 23.9 (4.6)
Total other operation and maintenance$296.3 $308.7 $12.4 
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Operation and maintenance not included in line items below $173.5
 $220.8
 $47.3
Transmission (1)
 111.8
 112.8
 1.0
Regulatory amortizations and other pass through expenses (2)
 24.5
 25.9
 1.4
Total other operation and maintenance $309.8
 $359.5
 $49.7


(1)Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for 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 nine months ended September 30, 2020 and 2019, $109.4 million and $105.8 million, respectively, of costs were billed to us by transmission providers.
(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 nine months ended September 30, 2017 and 2016, $104.0 million and $115.3 million, respectively, of costs were billed to us by transmission providers.


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

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

The following tables provide information on delivered sales volumes by customer class and weather statistics:
Nine Months Ended September 30
MWh (in thousands)
Electric Sales Volumes20202019B (W)
Customer class  
Residential2,306.9 2,165.7 141.2 
Small commercial and industrial2,933.7 3,006.7 (73.0)
Large commercial and industrial2,757.7 2,941.3 (183.6)
Other18.8 19.1 (0.3)
Total retail8,017.1 8,132.8 (115.7)
Wholesale1,554.3 1,691.4 (137.1)
Resale620.8 611.5 9.3 
Total sales in MWh10,192.2 10,435.7 (243.5)
  Nine Months Ended September 30
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W)
Customer class  
  
  
Residential 2,072.7
 2,194.9
 (122.2)
Small commercial and industrial 3,000.8
 3,058.7
 (57.9)
Large commercial and industrial 3,032.0
 3,167.0
 (135.0)
Other 19.3
 20.1
 (0.8)
Total retail 8,124.8
 8,440.7
 (315.9)
Wholesale 2,100.6
 1,957.3
 143.3
Resale 615.1
 348.3
 266.8
Total sales in MWh 10,840.5
 10,746.3
 94.2

  Nine Months Ended September 30
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W)
Customer Class  
  
  
Residential 159.0
 162.1
 (3.1)
Commercial and industrial 110.7
 111.7
 (1.0)
Total retail 269.7
 273.8
 (4.1)
Transport 310.6
 305.6
 5.0
Total sales in therms 580.3
 579.4
 0.9

  Nine Months Ended September 30
  Degree Days
Weather * 2017
2016 B (W)
Heating (4,809 normal) 4,285
 4,481
 (196)
Cooling (494 normal) 440
 568
 (128)

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



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Nine Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes20202019B (W)
Customer Class  
Residential166.4 181.0 (14.6)
Commercial and industrial127.6 140.0 (12.4)
Total retail294.0 321.0 (27.0)
Transport313.3 316.1 (2.8)
Total sales in therms607.3 637.1 (29.8)

Nine Months Ended September 30
Degree Days
Weather (1)
20202019B (W)
Heating (4,854 Normal)4,644 4,979 (6.7)%
Cooling (509 Normal)656 502 30.7 %

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

Electric Utility Margins


Electric utility margins decreased $14.4increased $52.4 million during the nine months ended September 30, 2017,2020, compared with the same period in 2016.2019. The significant factorsfactor impacting the lowerhigher electric utility margins were:was a $58.7 million net increase in margins related to the impact of our rate order approved by the PSCW, effective January 1, 2020. This increase in margins includes the impact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in income taxes.


This increase in margins was partially offset by:

•A $16.6$2.9 million decrease in margins related to lower retailwholesale sales volumes, driven by lower sales to UMERC. UMERC's new natural gas-fired generating units in the Upper Peninsula of Michigan began commercial operation on March 31, 2019, at which time we stopped providing wholesale services to UMERC.

•A $2.5 million decrease in margins related to other revenues, which included late payment charges and revenues from third party use of our assets.

Natural Gas Utility Margins

Natural gas utility margins increased $6.3 million during the nine months ended September 30, 2017, primarily driven by the transfer of customers and their related sales to UMERC, the impact of unfavorable weather, and an additional day of sales during2020, compared with the same period in 2016 due2019. The most significant factor impacting the higher natural gas utility margins was a $7.8 million increase related to leap year. As measuredthe impact of our rate order approved by cooling degree days, the nine months ended September 30, 2017, were 22.5% cooler thanPSCW, effective January 1, 2020. This increase in margins includes the same periodimpact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in 2016.income taxes.

This increase in margins was partially offset by a $2.3 million net reduction in margins related to lower sales volumes, driven by warmer winter weather during 2020. As measured by heating degree days, the nine months ended September 30, 2017,2020 were 4.4%6.7% warmer than the same period in 2016.
2019. In addition to the weather impact, the decrease in sales volumes for our commercial and industrial customers was also driven by business interruptions and closings related to, in large part, a shelter-in-place order issued by the state of Wisconsin during the COVID-19 pandemic.


A $2.8Operating Income

Operating income at the utility segment increased $64.7 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

Partially offsetting these decreases was a $5.3 million increase in wholesale margins during the nine months ended September 30, 2017,2020, compared with the same period in 2019. This increase was driven by UMERC purchasing a portionthe $58.7 million increase in margins discussed above, as well as $6.0 million of its energy from us.lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes).


Natural Gas Utility Margins

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NaturalThe significant factors impacting the decrease in operating expenses during the nine months ended September 30, 2020, compared with the same period in 2019, were:

•A $15.1 million decrease in electric and natural gas utility marginsdistribution expenses, driven by lower maintenance and storm restoration expense, as well as our focus on operating efficiency.

•A $4.7 million decrease in benefit costs, primarily due to lower deferred compensation costs, stock-based compensation, and medical costs.

•A $3.9 million decrease in maintenance expense at our plants, driven by the timing of planned outages at the Weston and Columbia power plants.

These decreases in operating expenses were partially offset by:

•A $9.7 million increase in transmission expense as approved in the PSCW's 2019 rate order, which was effective January 1, 2020. See the notes under the other operation and maintenance table above for more information.

•A $6.3 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

•A $4.6 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

Other Income, Net
 Nine Months Ended September 30
(in millions)20202019B (W)
AFUDC – Equity$8.3 $3.6 $4.7 
Non-service components of net periodic benefit costs14.6 13.6 1.0 
Other, net2.5 11.8 (9.3)
Other income, net$25.4 $29.0 $(3.6)

Other income, net decreased $3.6 million during the nine months ended September 30, 2020, compared with the same period in 2019. The decrease was primarily driven by the 2019 deferral of costs that were offset in other income statement line items and had no impact on net income. This decrease was partially offset by higher AFUDC – Equity during the nine months ended September 30, 2020, driven by continued capital investment.

Interest Expense
 Nine Months Ended September 30
(in millions)20202019B (W)
Interest expense47.9 $47.2 $(0.7)

Interest expense increased $0.7 million during the nine months ended September 30, 2017,2020, compared with the same period in 2016.2019, primarily due to higher long-term debt balances. The increase was partially offset by lower margins wereshort-term debt balances and lower interest rates on short-term debt. The increase in long-term debt balances was primarily drivenrelated to continued capital investments.

Income Tax Expense
 Nine Months Ended September 30
 20202019B (W)
Effective tax rate20.1 %23.8 %3.7 %

Our effective tax rate decreased by the transfer of customers and their related sales to UMERC.

Operating Income

Operating income at the utility segment increased $22.4 million3.7% during the nine months ended September 30, 2017,2020, compared with the same period in 2016. The increase2019. This decrease was drivenprimarily due to the 2020 amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with our Wisconsin rate order approved by a $37.5 millionthe PSCW, effective January 1, 2020. This decrease in operating expenses, partially offset by the $15.1 million decrease 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, which were due in part to synergy savings, were:

A $17.6 million decrease in expenses related to 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. The portion of these lower expenses related to the transfer are offset through higher depreciation and amortization, discussed below.

A $9.2 million decrease in electric and natural gas distribution expenses, due in part to the transfer of customers and their related sales to UMERC.

A $9.2 million decrease in operation and maintenance expenses related to our plants.

An $8.1 million decrease in benefit costs.

These decreases in operating expenses were partially offset by a $12.2 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 and the transfer of the information technology project to us during 2017.

Other Segment Contribution to Operating Income
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Operating (loss) income $(0.4) $0.1
 $(0.5)


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Consolidated Other Income, Net
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
AFUDC – Equity $3.2
 $16.3
 $(13.1)
Earnings from equity method investments 0.7
 7.1
 (6.4)
Other, net 5.0
 2.3
 2.7
Other income, net $8.9
 $25.7
 $(16.8)

Other income, net decreased by $16.8 million when compared to the nine months ended September 30, 2016, primarily due to a decrease in AFUDC driven by the ReACTTM emission control technology at Weston Unit 3 going 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 13, Related Parties, for more information.

Consolidated Interest Expense
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Interest expense $41.2
 $35.3
 $(5.9)

Interest expense increased by $5.9 million, when compared with the nine months ended September 30, 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
  Nine Months Ended September 30
  2017 2016 B (W)
Effective tax rate 39.2% 37.3% (1.9)%

Our effective tax rate increasedwas partially offset by 1.9% when compared with the nine months ended September 30, 2016, primarily due to a decrease inimpact of the projected 2017 annual taxprotected benefits associated with AFUDC-Equity. the Tax Legislation. These items did not impact earnings as they were offset in operating income.

We expect our 20172020 annual effective tax rate to be between 39.0%19% and 40.0%20%, which includes an estimated 5% effective tax rate benefit due to the amortization of unprotected excess deferred taxes in connection with our Wisconsin rate order approved by the PSCW, effective January 1, 2020. Excluding this estimated effective tax rate benefit, the expected 2020 range would be between 24% and 25%.


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows


The following table summarizes our cash flows during the nine months ended September 30:
(in millions)20202019Change in 2020 Over 2019
Cash provided by (used in):
Operating activities$414.1 $322.6 $91.5 
Investing activities(373.9)(372.0)(1.9)
Financing activities(40.5)45.5 (86.0)
(in millions) 2017 2016 Change in 2017 Over 2016
Cash provided by (used in):      
Operating activities $392.0
 $328.5
 $63.5
Investing activities (246.0) (230.8) (15.2)
Financing activities (146.0) (99.9) (46.1)


Operating Activities


Net cash provided by operating activities increased $63.5$91.5 million during the nine months ended September 30, 2017,2020, compared with the same period in 2016,2019, driven by:


•A $157.8$67.3 million increase in cash related to cash receivedlower payments for net assets transferred out offuel and purchased power at our pension planplants during the nine months ended September 30, 2020, compared with the same period in 2017. See Note 13, Related Parties,2019. Our payments for more information.


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A $52.2 million increase in cash related to higher overall collections from customers, primarilyfuel and purchased power decreased due to higher commodity prices.lower natural gas costs used to fuel our plants. The average per-unit cost of natural gas sold increased 15.2%decreased 20.5% during the nine months ended September 30, 2017,2020, compared withto the same period in 2016.
2019. Lower fuel and purchased power costs were also driven by lower sales volumes, related to warmer winter weather during 2020, as well as business interruptions and closings during the COVID-19 pandemic.


•A $47.9$24.7 million increase in cash from lower payments for operating and maintenance costs. During the nine months ended September 30, 2017, our payments related to transmission, electric and natural gas distribution costs,other operation and maintenance of our plants, and employee benefits decreased.

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

A $76.3 million net decrease in cash related to $27.5 million of cash paid for income taxes during the nine months ended September 30, 2017, compared with $48.8 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 duringexpenses. During the nine months ended September 30, 2016.

A $65.3 million increase in contributions2020, our payments were lower for electric and payments tonatural gas distribution expenses, benefits, and maintenance at our pension and OPEB plans during the nine months ended September 30, 2017,plants, compared with the same period in 2016.

A $57.1 million decrease in cash resulting from higher payments2019. See Results of Operations – Utility Segment Contribution to Operating Income for natural gas and fuel and purchased power, primarily due to higher commodity prices during the nine months ended September 30, 2017, compared with the same period in 2016.
2020, for more information.


Investing Activities


Net cash used in investing activities increased $15.2$1.9 million during the nine months ended September 30, 2017,2020, compared with the same period in 2016,2019, driven by $10.0 million of cash paid for assets received from WBS during the nine months ended September 30, 2017, compared with $7.3 million of cash received for assets transferred to WBS during the same periodan increase in 2016. In addition, cash paid for capital expenditures, increased $2.9 million, which is discussed in more detail below.


Capital Expenditures


Capital expenditures for the nine months ended September 30 were as follows:
(in millions) 2017 2016 Change in 2017 Over 2016(in millions)20202019Change in 2020 Over 2019
Capital expenditures $237.9
 $235.0
 $2.9
Capital expenditures$381.0 $380.0 $1.0 


The increase in cash paid for capital expenditures during the nine months ended September 30, 2017,2020, compared with the same period in 2019, was driven by higheran increase in payments for capital expenditures for the SMRP. This increase was partiallyrelated to Badger Hollow I and upgrades to our electric distribution system, offset by lowera decrease in cash paid for capital expenditures for the ReACTTM emission control technology project at Weston Unit 3, which was completed in 2016,related to Two Creeks and lower expenditures for upgrades to combustion turbine units atour natural gas distribution system during the Fox Energy Center, which were completednine months ended September 30, 2020, compared with the same period in June 2017.2019.


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


Financing Activities


Net cash used inrelated to financing activities increased $46.1decreased $86.0 million during the nine months ended September 30, 2017,2020, compared with the same period in 2016,2019, driven by:


•A $76.1$300.0 million increase decrease in cash due to the issuance of long-term debt during the nine months ended September 30, 2019. There were no issuances of long-term debt in 2020.

•An $80.0 million decrease in cash related to higher dividends paid to our parent during the nine months ended September 30, 2017. We paid a special dividend to our parent2020, compared with the same period in 2019, to balance our capital structure during the first quarter of 2017, driven bystructure.

These decreases in cash received for assets transferred out of our pension plan in January 2017.
were partially offset by:


•A $21.7$190.4 million increase in thecash related to lower net repayments of commercial paper during the nine months ended September 30, 2017.
2020, compared with the same period in 2019.



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These increases in net cash used for financing activities were partially offset by:

•A $28.6 million repayment of a loan during 2016.

A $20.0$100.0 million increase in equity contributions received from our parent relatedduring the nine months ended September 30, 2020, compared with the same period in 2019, to balancingbalance our capital structure.


For more information on our short-term financing activities, see Note 5,6, Short-Term Debt and Lines of Credit.


Capital Resources and Requirements


Capital Resources


Liquidity


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


We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement,arrangements, access to capital markets, and internally generated cash. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information on the impacts of the COVID-19 pandemic.


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 5,6, Short-Term Debt and Lines of Credit, for more information on our credit facility.


Working Capital


AsAlthough not the case as of September 30, 2017,2020, our current liabilities exceededsometimes exceed our current assets by $85.7 million. We doassets. If this were to occur, we would not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.


Credit Rating Risk


AccessWe do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.
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In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

In July 2017, Moody's downgraded our senior unsecured rating to A2 from A1. Moody's affirmed our P-1 commercial paper rating. We do not believe this change in rating 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.



If we are unable to successfully take actions to manage any impacts from the COVID-19 pandemic and/or any additional adverse impacts of the Tax Legislation as a result of additional interpretations, regulations, amendments or technical corrections, these potential impacts could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.

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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, impacts from the Tax Legislation, additional changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, and economic trends.the COVID-19 pandemic. Our estimated capital expenditures for the next three years are as follows:
(in millions)
2020$534.1 
2021578.8 
2022537.6 
Total$1,650.5 
(in millions)  
2017 $315.9
2018 441.7
2019 378.2
Total $1,135.8


We continue to upgrade our electric and natural gas distribution systems to enhance reliability. These upgrades include the 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. We are continuing work on the SMRP.System Modernization and Reliability Project. This project involves modernizing parts of our electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of the electric service that we provide to our customers. We expect to invest approximately $300$100 million between 20172020 and 20212022 on this project.

WEC Energy Group is committed to investing in solar, wind, and battery storage. As part of this commitment, we have received approval to invest in 200 MW of utility-scale solar. We also continuehave partnered with an unaffiliated utility to upgradeconstruct two solar projects in Wisconsin. Two Creeks is located in Manitowoc County, Wisconsin, and Badger Hollow I is located in Iowa County, Wisconsin. Upon completion, we will own 100 MW of each project for a total of 200 MW. Our share of the cost of both projects is estimated to be approximately $260 million. Commercial operation was achieved in the first week of November 2020 for Two Creeks, and is targeted for April 2021 for Badger Hollow I.

See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for information on the impacts to our electric and natural gas distribution systems to enhance reliability. These upgrades includecapital projects as a result of the advanced metering infrastructure (AMI) program. AMI is an integrated systemCOVID-19 pandemic.

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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 9,6, Short-Term Debt and Lines of Credit, and Note 11, 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 20162019 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the nine months ended September 30, 2020.


FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES


The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 20162019 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,competitive markets, environmental matters, critical accounting policies and estimates, and other matters.


Coronavirus Disease – 2019

The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC and has spread globally, including throughout the United States. There is still considerable uncertainty regarding the extent to which COVID-19 will spread and the extent and duration of measures currently in place to try to contain the virus, such as travel bans and restrictions, quarantines, and limitations on business operations. Although the shelter-in-place order that was in effect for Wisconsin has expired, other orders limiting the capacity of various businesses have been adopted at the state and local levels. In addition, similar or more restrictive orders could be adopted in the future depending on how the virus continues to spread. Such measures have significantly disrupted economic activity in our service territory and have caused disruptions and volatility in the capital markets. See Item 1A. Risk Factors for more information on our risks related to COVID-19.

Liquidity and Financial Markets

Volatility and uncertainty in the financial markets and global economy have impacted us in a number of ways. Upon the initial enactment of certain COVID-19 related shelter-in-place orders in early to mid-March 2020, commercial paper markets became more expensive and related terms became less flexible. In response to these signs of market instability, the Federal Reserve implemented certain measures, including a reduction in its benchmark Federal Funds rate and the establishment of various programs to restore liquidity and stability into the short-term funding markets. These measures have had a mitigating effect on commercial paper rates and availability. In addition, the initial disruption in the long-term debt markets as a result of the COVID-19 pandemic has subsided.

Our overall liquidity position remains strong. As of September 30, 2020, we had $382.7 million available under our credit facility, providing sufficient backing for our commercial paper program.

Pensions and Other Benefits

Our pension and OPEB plans were well funded at December 31, 2019, with total plan assets exceeding total benefit obligations by $129.7 million. There has been significant volatility in global capital markets during the COVID-19 pandemic, although the market losses recorded during the early stages of the pandemic in the first quarter of 2020 have reversed course in the second and third quarters of 2020 in response to government stimulus and relief efforts and the gradual reopening of businesses. During the nine months ended September 30, 2020, we recognized a $35 million increase in the value of long-term investments held in our pension and OPEB plan trusts as second and third quarter gains more than offset first quarter losses.

We could still see earnings volatility associated with certain other benefit plans maintained by our ultimate parent, WEC Energy Group, primarily related to performance units granted to certain of our employees, and deferred compensation plans. Certain of the
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liabilities associated with the deferred compensation plans are indexed to mutual funds and WEC Energy Group common stock, and the liabilities associated with outstanding performance units are indexed to WEC Energy Group common stock. These liabilities are marked to fair value through earnings each period, with earnings increasing as market prices decrease.

Allowance for Credit Losses

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. Risks identified that we do not believe are reflected in historical reserve percentages are assessed on a quarterly basis to determine whether further adjustments are required. Economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates and the inability of some businesses to recover from the pandemic, could cause a higher percentage of accounts receivable to become uncollectible. An increase in credit losses could negatively impact our results of operations and could result in higher working capital requirements.

Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) and foregone revenues related to the COVID-19 pandemic. The additional protections provided by these COVID-19 specific regulatory orders are still being assessed and will be subject to prudency reviews. See Note 17, Regulatory Environment, for more information.

Loss of Business

We have seen a decrease in the consumption of electricity and natural gas by some of our commercial and industrial customers as they continue to experience lower demand for their products and services as a result of the COVID-19 pandemic. Many businesses in our service territory still are not operating at full capacity. The extent to which this decrease in consumption will impact our results of operations and liquidity is dependent upon the duration of the COVID-19 pandemic and the ability of our customers to resume and continue normal operations.

Supply Chain and Capital Projects

We have not yet experienced a significant disruption in our supply chain as a result of the COVID-19 pandemic. However, if the pandemic significantly impacts our key suppliers’ ability to manufacture or deliver critical equipment and supplies or provide services, we could experience delays in our ability to perform certain maintenance and capital project activities.

The timing of Badger Hollow I has been impacted by the COVID-19 pandemic. The parties agreed to delay the expected commercial operation date from December 2020 to April 2021 so that initial staffing increases could be minimized in light of state mandated COVID-19 orders. We are not currently aware of any other major delays or changes related to our capital plan as a result of the COVID-19 pandemic, although we are continuing to monitor potential impacts on an ongoing basis.

Employee Safety

The health and safety of our employees during the COVID-19 pandemic is paramount and enables us to continue to provide critical services to our customers.

We are following CDC guidelines and have taken enhanced precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, provided additional employee benefits, and implemented remote work policies where appropriate. We have activated an incident management team and updated our pandemic continuity plan, which includes identifying critical work groups and ensuring safe harbor plans are in place. We have minimized the unnecessary risk of exposure to COVID-19 by implementing self-quarantine measures and have adopted additional precautionary measures for our critical work groups.

Additional protocols have been implemented for our field employees who travel to customer premises in order to protect them, our customers, and the public. We have modified our work protocols to ensure compliance with social distancing and face covering recommendations.

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All of these safety measures have caused us to incur additional costs, and depending upon the duration of the COVID-19 pandemic, could have a material impact on our results of operations and liquidity.

Regulatory Environment

We have taken actions to ensure that essential utility services are available to our customers during the COVID-19 pandemic. In addition, the PSCW has issued written orders requiring certain actions by all public utilities in the state of Wisconsin. See Note 17, Regulatory Environment, for more information on these orders and the potential recovery of expenditures incurred as a result of the measures being taken.

Market Risks and Other Significant Risks


We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the regulatory recovery risk described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 20162019 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.


Regulatory Recovery

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by the PSCW.

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Recovery of the deferred costs in future rates is subject to the review and approval by the PSCW. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by the PSCW, the costs would be charged to income in the current period. The PSCW can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities.

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

In June 2016, the PSCW approved the deferral of costs related to our ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 16, Regulatory Environment, for more information. We will be required to obtain a separate approval for collection of these deferred costs in a future rate case.

Prior to its acquisition by WEC Energy Group, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries, including us. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of September 30, 2017, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

See Note 16, Regulatory Environment, for more information regarding recent and pending rate proceedings and orders.

Environmental Matters


See Note 14,15, 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.



Critical Accounting Policies and Estimates

We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require any additional disclosures. We have found that the disclosures made in our 2019 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill Impairment

We completed our annual goodwill impairment test for our utility reporting unit as of July 1, 2020. No impairment was recorded as a result of this test. At July 1, 2020, our reporting unit had $36.4 million of goodwill.

The fair value calculated in step one of the test was greater than its carrying value. The fair value of our reporting unit was calculated using a combination of the income approach and the market approach.

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

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

For the market approach, we used an equal weighting of the guideline public company method and the guideline merged and acquired company method. The guideline public company method uses financial metrics from similar companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting unit to determine fair value.

The underlying assumptions and estimates used in the impairment test were made as of a point in time. Subsequent changes in these assumptions and estimates could change the result of the test.
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The fair value of our reporting unit exceeded its carrying value by over 50%. Based on this result, our reporting unit is not at risk of failing step one of the goodwill impairment test.

See Note 13, Goodwill, for more information.

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 2019 Annual Report on Form 10-K for the year ended December 31, 2016.10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019 and Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 7,9, Fair Value Measurements, Note 8,10, Derivative Instruments, and Note 9,11, Guarantees, in this report for information concerning our market risk exposures.


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 third quarter of 20172020 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 20162019 Annual Report on Form 10-K. See Note 14,15, Commitments and Contingencies, and Note 17, Regulatory Environment, in this report for moreadditional information on material legal proceedings and matters related to us.


In addition to those legal proceedings referenced abovediscussed in Note 15, Commitments and discussed below,Contingencies, and Note 17, Regulatory Environment, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.


Environmental Matters

Sheboygan River Matter

We were contacted by the United States Department of Justice in March 2016 to commence discussions with the federal natural resource trustees to resolve our alleged liability for natural resources damages (NRD) in the Sheboygan River related to the former Camp Marina manufactured gas plant site. We were originally notified about this claim in September 2012, but the WDNR chose not to be a party to the NRD claim negotiation in February 2014. However, the National Oceanic and Atmospheric Administration has co-equal trusteeship with the WDNR over the impacted Sheboygan River natural resources and is now pursuing the NRD claim. 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 theThe following risk factor updates and supplements those risk factors presenteddisclosed in our Annual Report on Form 10-K for the year ended December 31, 2016. See Item 1A. Risk Factors in Part I of our 20162019 Annual Report on Form 10-K and Part II of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.

The ongoing COVID-19 pandemic could adversely affect our business functions, financial condition, liquidity, and results of operations.

The global outbreak of COVID-19 was declared a discussionpandemic by the WHO and the CDC and has spread globally, including throughout the United States. There is still considerable uncertainty regarding the extent to which COVID-19 will spread and the extent and duration of measures currently in place to try to contain the virus, such as travel bans and restrictions, quarantines, and limitations on business operations. Although the shelter-in-place order that was in effect in Wisconsin has expired, other orders limiting the capacity of various businesses have been adopted at the state and local levels. In addition, similar or more restrictive orders could be adopted in the future depending on how the virus continues to spread.

Such measures have significantly disrupted economic activity in our service territory and have caused disruptions and volatility in the capital markets. In addition, we are continuing to temporarily suspend disconnections for non-payment by certain risk factors applicablecustomer classes. The effects of the continued outbreak of COVID-19 and related government responses have included, and may continue to us.

ITEM 5. OTHER INFORMATION

In October 2017, Allen L. Leverett, Chief Executive Officerinclude, extended disruptions to supply chains and capital markets, reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could continue to have a variety of Wisconsin Public Service, suffered a stroke. Mr. Leverett has been releasedadverse impacts on us, including continued reductions in demand for energy, particularly from the hospitalcommercial and is making progressindustrial customers; impairment of goodwill or long-lived assets; continued decreases in his recovery and rehabilitation work. Pursuantrevenue due to the Wisconsin Public Service Bylaws,inability to collect late fees; increased bad debt expense; impairment of our ability to develop, construct, and operate facilities; and impaired ability to successfully access funds from credit and capital markets.

Any additional effects of COVID-19 on October 31, 2017, the Wisconsin Public Service Board orderedU.S. capital markets may significantly impact us. For example, the costs related to our pension and other post-retirement benefit plans are based in part on the value of the plans’ assets. Adverse investment performance for these assets or the failure to maintain sustained growth in pension investments over time could increase our plan costs and funding requirements. Similarly, we rely on access to the capital markets to fund some of our operations and capital requirements. To the extent that access to the dutiescapital markets is adversely affected by COVID-19, we may need to consider alternative sources of Chief Executive Officer would be exercised byfunding for our operations and for working capital, which may increase our cost of, as well as adversely impact our access to, capital.

We have taken precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, and implemented remote work policies where appropriate. Additional protocols have been implemented for our field employees who travel to customer premises in order to protect them, our customers, and the Presidentpublic.

Despite our efforts to manage the impacts of Wisconsin Public Service, J. Kevin Fletcher,the COVID-19 pandemic, the extent to which COVID-19 may continue to affect us depends on an interim basis. Mr. Fletcher has executedfactors beyond our knowledge or control. Therefore, we are currently unable to determine what additional impact the certificates attachedCOVID-19 pandemic may have on our business plans and operations, liquidity, financial condition, and results of operations, but will continue to this Form 10-Q in such capacity.


monitor COVID-19 developments and modify our plans as conditions change.
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ITEM 6. EXHIBITS
NumberExhibit
31Rule 13a-14(a) / 15d-14(a) Certifications
NumberExhibit
31Rule 13a-14(a) / 15d-14(a) Certifications
32Section 1350 Certifications
101Interactive Data Files
101.INSInline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCHInline XBRL Taxonomy Extension Schema
101.CALInline XBRL Taxonomy Extension Calculation Linkbase
101.DEFInline XBRL Taxonomy Extension Definition Linkbase
101.LABInline XBRL Taxonomy Extension Label Linkbase
101.PREInline XBRL Taxonomy Extension Presentation Linkbase
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)



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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)
WISCONSIN PUBLIC SERVICE CORPORATION
(Registrant)
/s/ WILLIAM J. GUC
Date:November 3, 20176, 2020William J. Guc
Vice President, Controller, and ControllerAssistant Corporate Secretary
(Duly Authorized Officer and Chief Accounting Officer)



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