UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549


FORM 10-Q


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

For the Quarterly Period Ended quarterly period ended June 30, 20182019

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;
IRS Employer
File Number
Address; and Telephone Number
 
IRS Employer
Identification No.
001-01245 WISCONSIN ELECTRIC POWER COMPANY 39-0476280
(A Wisconsin Corporation)
231 West Michigan Street
P.O. Box 2046
Milwaukee, WI 53201
(414) 221-2345

(A Wisconsin Corporation)
231 West Michigan Street
P. O. Box 2046
Milwaukee, WI53201
(414) 221-2345


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 [X] (Do not check if a smaller reporting company)☒ Smaller reporting company [  ]☐
   Emerging growth company [  ]☐


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


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


Yes [ ]☐    No [X]☒


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

Common Stock, $10 Par Value,
33,289,327shares outstanding at
June 30, 2019
33,289,327 shares outstanding at
June 30, 2018


All of the common stock of Wisconsin Electric Power Company is ownedheld by WEC Energy Group, Inc.
 

WISCONSIN ELECTRIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended June 30, 20182019
TABLE OF CONTENTS
   Page
 
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
 
1
PART I.
FINANCIAL INFORMATION
 
3
ITEM 1.
FINANCIAL STATEMENTS (UNAUDITED)
 
3
 
Condensed Consolidated Income Statements
 
3
 
Condensed Consolidated Balance Sheets
 
4
 
Condensed Consolidated Statements of Cash Flows
 
5
 
Condensed Consolidated Statements of Equity
6
Notes to Condensed Consolidated Financial Statements
 
67
   Page 
 
Note 1
General Information
67
 
 
Note 2
DispositionOperating Revenues
67
 
 
Note 3
Operating Revenues
6
Note 4
Property, Plant,Regulatory Assets and EquipmentLiabilities
9
 
 
Note 54
Property, Plant, and Equipment
9
Note 5
Common Equity
10
 
 
Note 6
Short-Term Debt and Lines of Credit
10
 
 
Note 7
Long-Term DebtLeases
10
 
 
Note 8
Materials, Supplies, and Inventories
11
Note 9
Income Taxes
11
Note 10
Fair Value Measurements
11
Note 11
Derivative Instruments
13
Note 12
Employee Benefits
14
Note 13
Segment Information
15
 
 
Note 149
Variable Interest EntitiesIncome Taxes
15
Note 10
Fair Value Measurements
16
 
 
Note 1511
Related PartiesDerivative Instruments
17
 
 
Note 1612
Commitments and ContingenciesGuarantees
19
 
 
Note 1713
Supplemental Cash Flow InformationEmployee Benefits
2219
 
 
Note 1814
Regulatory EnvironmentSegment Information
2219
 
 
Note 1915
New Accounting PronouncementsVariable Interest Entities
20
Note 16
Commitments and Contingencies
20
Note 17
Supplemental Cash Flow Information
23
 
ITEM 2.Note 18
Regulatory Environment
23
Note 19
New Accounting Pronouncements
24
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
2425
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
38
ITEM 4.
CONTROLS AND PROCEDURES
39
PART II.
OTHER INFORMATION
40
ITEM 1.
LEGAL PROCEEDINGS
40
ITEM 1A.
RISK FACTORS
40
ITEM 6.
EXHIBITS
 
41
ITEM 4.
CONTROLS AND PROCEDURES
41
PART II.
OTHER INFORMATION
42
ITEM 1.
LEGAL PROCEEDINGS
42
ITEM 1A.
RISK FACTORS
42
ITEM 6.
EXHIBITS
42
SIGNATURE
  
4243




06/30/20182019 Form 10-QiWisconsin Electric Power Company
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS


The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates
ATC American Transmission Company LLC
BluewaterBluewater Natural Gas Holding, LLC
Bostco Bostco LLC
UMERC Upper Michigan Energy Resources Corporation
WBSWEC Business Services LLC
We Power W.E. Power, LLC
WEC Energy Group WEC Energy Group, Inc.
WG Wisconsin Gas LLC
WPSWisconsin Public Service Corporation
   
Federal and State Regulatory Agencies
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
IRSUnited States Internal Revenue Service
MDEQ Michigan Department of Environmental Quality
MPSCMichigan Public Service Commission
PSCW Public Service Commission of Wisconsin
SEC United States Securities and Exchange Commission
WDNRWisconsin Department of Natural Resources
   
Accounting Terms
AFUDC Allowance for Funds Used During Construction
ASU Accounting Standards Update
FASB Financial Accounting Standards Board
GAAP United States Generally Accepted Accounting Principles
OPEB Other Postretirement Employee Benefits
   
Environmental Terms
ACEAffordable Clean Energy
BATWBottom Ash Transport Water
BSERBest System of Emission Reduction
BTABest Technology Available
CAAClean Air Act
CO2
 Carbon Dioxide
CPPELG Clean Power PlanSteam Electric Effluent Limitation Guidelines
FGDFlue Gas Desulfurization
GHG Greenhouse Gas
MATSMercury and Air Toxics Standards
RTRRisk and Technology Review
   
Measurements
Dth Dekatherm
MW Megawatt
MWh Megawatt-hour
   
Other Terms and Abbreviations
D.C. Circuit Court of AppealsAMI United States Court of Appeals for the District of Columbia CircuitAdvanced Metering Infrastructure
Badger Hollow IIBadger Hollow Solar Farm II
ERGS Elm Road Generating Station
ER 1Elm Road Generating Station Unit 1
ER 2Elm Road Generating Station Unit 2
Exchange Act Securities Exchange Act of 1934, as amended
FTRsFTR Financial Transmission RightsRight

06/30/2019 Form 10-QiiWisconsin Electric Power Company
Table of Contents

MISO Midcontinent Independent System Operator, Inc.
MISO Energy MarketsMISO Energy and Operating Reserves Markets
OCPP Oak Creek Power Plant
OC 5 Oak Creek Power Plant Unit 5
OC 6 Oak Creek Power Plant Unit 6
OC 7 Oak Creek Power Plant Unit 7
OC 8 Oak Creek Power Plant Unit 8

06/30/2018 Form 10-QiiWisconsin Electric Power Company
Table of Contents

PIPP Presque Isle Power Plant
PWGS Port Washington Generating Station
PWGS 1Port Washington Generating Station Unit 1
PWGS 2Port Washington Generating Station Unit 2
ROE Return on Equity
Supreme CourtSSR United States Supreme CourtSystem Support Resource
Tax Legislation Tax Cuts and Jobs Act of 2017
TildenTilden Mining Company




06/30/20182019 Form 10-QiiiWisconsin Electric Power Company
Table of Contents


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 20172018 Annual Report on Form 10-K, and those identified below:


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


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


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


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


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


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


The remaining uncertainty surrounding the recentlyTax Legislation enacted Tax Legislation,in December 2017, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;


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


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


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


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

06/30/2019 Form 10-Q1Wisconsin Electric Power Company
Table of Contents

or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

06/30/2018 Form 10-Q1Wisconsin Electric Power Company
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Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;


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


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


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


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


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 benefits associated with the remaining integration efforts relating to WEC Energy Group's acquisition of Integrys Holding, Inc.;


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


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


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


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


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


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




06/30/20182019 Form 10-Q2Wisconsin Electric Power Company
Table of Contents


PART I. FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS


WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) Three Months Ended Six Months Ended Three Months Ended Six Months Ended
 June 30 June 30
CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) June 30 June 30
 2018 2017 2018 2017 2019 2018 2019 2018
Operating revenues $856.2
 $855.4
 $1,797.7
 $1,827.4
 $791.7
 $856.2
 $1,752.5
 $1,797.7
                
Operating expenses                
Cost of sales 270.9
 273.9
 627.9
 622.5
 253.5
 270.9
 610.7
 627.9
Other operation and maintenance 366.6
 324.4
 702.2
 651.0
 234.3
 366.6
 493.2
 702.2
Depreciation and amortization 86.9
 82.7
 172.2
 164.8
 95.2
 86.9
 191.2
 172.2
Property and revenue taxes 27.3
 28.3
 54.5
 56.7
 26.1
 27.3
 51.9
 54.5
Total operating expenses 751.7
 709.3
 1,556.8
 1,495.0
 609.1
 751.7
 1,347.0
 1,556.8
                
Operating income 104.5
 146.1
 240.9
 332.4
 182.6
 104.5
 405.5
 240.9
                
Other income, net 15.3
 1.1
 11.1
 4.3
 5.9
 15.3
 11.4
 11.1
Interest expense 29.2
 29.1
 58.9
 58.7
 119.6
 29.2
 239.5
 58.9
Other expense (13.9) (28.0) (47.8) (54.4) (113.7) (13.9) (228.1) (47.8)
                
Income before income taxes 90.6
 118.1
 193.1
 278.0
 68.9
 90.6
 177.4
 193.1
Income tax (benefit) expense (2.5) 42.5
 (6.1) 100.3
Income tax benefit (16.3) (2.5) (22.8) (6.1)
Net income 93.1
 75.6
 199.2
 177.7
 85.2
 93.1
 200.2
 199.2
                
Preferred stock dividend requirements 0.3
 0.3
 0.6
 0.6
 0.3
 0.3
 0.6
 0.6
Net income attributed to common shareholder $92.8
 $75.3
 $198.6
 $177.1
 $84.9
 $92.8
 $199.6
 $198.6


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




06/30/20182019 Form 10-Q3Wisconsin Electric Power Company
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WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in millions, except share and per share amounts)
 June 30, 2018 December 31, 2017 June 30, 2019 December 31, 2018
Assets        
Current assets        
Cash and cash equivalents $1.1
 $12.3
 $4.6
 $20.2
Accounts receivable and unbilled revenues, net of reserves of $39.6 and $39.5, respectively 456.0
 513.8
Accounts receivable and unbilled revenues, net of reserves of $37.6 and $40.9, respectively 403.5
 472.3
Accounts receivable from related parties 114.6
 109.1
 65.0
 112.4
Materials, supplies, and inventories 236.7
 250.7
 228.0
 241.4
Prepayments 120.8
 144.3
 138.6
 163.7
Other 12.1
 9.4
 16.6
 6.3
Current assets 941.3
 1,039.6
 856.3
 1,016.3
        
Long-term assets        
Property, plant, and equipment, net of accumulated depreciation of $3,377.9 and $3,741.8, respectively 9,378.7
 10,007.7
Property, plant, and equipment, net of accumulated depreciation and amortization of $4,447.2 and $4,505.5, respectively 9,383.5
 9,528.9
Regulatory assets 2,879.4
 1,984.9
 3,126.9
 2,902.2
Other 111.1
 89.4
 112.6
 90.9
Long-term assets 12,369.2
 12,082.0
 12,623.0
 12,522.0
Total assets $13,310.5
 $13,121.6
 $13,479.3
 $13,538.3
        
Liabilities and Equity        
Current liabilities        
Short-term debt $341.8
 $210.9
 $39.5
 $134.9
Current portion of long-term debt —
 250.0
 250.0
 250.0
Current portion of capital lease obligations 46.4
 42.5
Current portion of finance and capital lease obligations 53.8
 49.9
Accounts payable 237.1
 329.3
 207.4
 248.9
Accounts payable to related parties 186.4
 131.5
 161.5
 226.0
Accrued payroll and benefits 44.9
 53.4
 44.8
 50.4
Accrued taxes 73.8
 58.2
Other 98.0
 111.8
 112.9
 116.8
Current liabilities 1,028.4
 1,187.6
 869.9
 1,076.9
        
Long-term liabilities        
Long-term debt 2,413.4
 2,412.3
 2,460.4
 2,459.6
Capital lease obligations 2,819.3
 2,823.8
Finance and capital lease obligations 2,804.6
 2,807.2
Deferred income taxes 1,190.4
 1,155.5
 1,345.6
 1,298.3
Regulatory liabilities 1,893.6
 1,708.0
 2,026.2
 2,002.3
Pension and OPEB obligations 157.7
 143.2
 106.9
 118.5
Other 286.3
 276.9
 287.0
 284.3
Long-term liabilities 8,760.7
 8,519.7
 9,030.7
 8,970.2
        
Commitments and contingencies (Note 16) 
 
 

 

        
Common shareholder's equity        
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding 332.9
 332.9
 332.9
 332.9
Additional paid in capital 831.2
 802.7
 929.2
 831.3
Retained earnings 2,326.9
 2,248.3
 2,286.2
 2,296.6
Common shareholder's equity 3,491.0
 3,383.9
 3,548.3
 3,460.8
        
Preferred stock 30.4
 30.4
 30.4
 30.4
Total liabilities and equity $13,310.5
 $13,121.6
 $13,479.3
 $13,538.3

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



06/30/20182019 Form 10-Q4Wisconsin Electric Power Company
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WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended Six Months Ended
 June 30 June 30
(in millions) 2018 2017 2019 2018
Operating Activities        
Net income $199.2
 $177.7
 $200.2
 $199.2
Reconciliation to cash provided by operating activities        
Depreciation and amortization 172.2
 164.8
 191.2
 172.2
Deferred income taxes and investment tax credits, net (39.5) 64.1
 (42.6) (39.5)
Contributions and payments related to pension and OPEB plans (3.8) (5.6) (3.2) (3.8)
Change in –        
Accounts receivable and unbilled revenues 57.9
 26.7
 112.9
 57.9
Materials, supplies, and inventories 14.0
 (7.2) 13.4
 14.0
Prepayments 25.1
 23.5
Other current assets 28.4
 10.1
 (9.2) 4.9
Accounts payable (36.2) (8.1) (98.5) (36.2)
Accrued taxes 19.0
 (24.4) (0.3) 19.0
Other current liabilities (18.1) (24.2) (16.8) (18.1)
Other, net 138.5
 (14.0) 63.2
 138.5
Net cash provided by operating activities 531.6
 359.9
 435.4
 531.6
        
Investing Activities        
Capital expenditures (287.0) (246.9) (230.4) (287.0)
Proceeds from the sale of assets 0.6
 22.0
Payments for assets transferred from affiliates (50.1) —
 —
 (50.1)
Short-term notes receivable from related parties, net —
 (3.1)
Other, net 5.4
 2.3
 5.1
 6.0
Net cash used in investing activities (331.1) (225.7) (225.3) (331.1)
        
Financing Activities        
Change in short-term debt 130.9
 (84.0) (95.4) 130.9
Repayment of subsidiary note to parent —
 (18.5)
Retirement of long-term debt (250.0) —
 —
 (250.0)
Payments for finance lease obligations (24.4) —
Equity contribution from parent 28.0
 75.0
 105.0
 28.0
Payment of dividends to parent (120.0) (120.0) (210.0) (120.0)
Payment of preferred stock dividends (0.6) (0.6)
Other —
 0.1
Other, net (0.9) (0.6)
Net cash used in financing activities (211.7) (148.0) (225.7) (211.7)
        
Net change in cash and cash equivalents (11.2) (13.8) (15.6) (11.2)
Cash and cash equivalents at beginning of period 12.3
 15.4
 20.2
 12.3
Cash and cash equivalents at end of period $1.1
 $1.6
 $4.6
 $1.1


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




06/30/20182019 Form 10-Q5Wisconsin Electric Power Company
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WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)      
             
  Wisconsin Electric Power Company Common Shareholder's Equity    
(in millions) Common Stock Additional Paid In Capital Retained Earnings Total Common Shareholder's Equity Preferred Stock Total Equity
Balance at December 31, 2018 $332.9
 $831.3
 $2,296.6
 $3,460.8
 $30.4
 $3,491.2
Net income —
 —
 115.0
 115.0
 —
 115.0
Dividends            
Common stock —
 —
 (150.0) (150.0) —
 (150.0)
Preferred stock —
 —
 (0.3) (0.3) —
 (0.3)
Stock-based compensation and other —
 0.2
 —
 0.2
 —
 0.2
Balance at March 31, 2019 $332.9
 $831.5
 $2,261.3
 $3,425.7
 $30.4
 $3,456.1
Net income —
 —
 85.2
 85.2
 —
 85.2
Dividends       

   

Common stock —
 —
 (60.0) (60.0) —
 (60.0)
Preferred stock —
 —
 (0.3) (0.3) —
 (0.3)
Equity contribution from parent —
 105.0
 —
 105.0
 —
 105.0
Transfer of net assets to UMERC —
 (7.3) —
 (7.3) —
 (7.3)
Balance at June 30, 2019 $332.9
 $929.2
 $2,286.2
 $3,548.3
 $30.4
 $3,578.7

  Wisconsin Electric Power Company Common Shareholder's Equity    
(in millions) Common Stock Additional Paid In Capital Retained Earnings Total Common Shareholder's Equity Preferred Stock Total Equity
Balance at December 31, 2017 $332.9
 $802.7
 $2,248.3
 $3,383.9
 $30.4
 $3,414.3
Net income —
 —
 106.1
 106.1
 —
 106.1
Dividends            
Common stock —
 —
 (60.0) (60.0) —
 (60.0)
Preferred stock —
 —
 (0.3) (0.3) —
 (0.3)
Equity contribution from parent —
 28.0
 —
 28.0
 —
 28.0
Stock-based compensation and other —
 0.2
 —
 0.2
 —
 0.2
Balance at March 31, 2018 $332.9
 $830.9
 $2,294.1
 $3,457.9
 $30.4
 $3,488.3
Net income —
 —
 93.1
 93.1
 —
 93.1
Dividends       

   

Common stock —
 —
 (60.0) (60.0) —
 (60.0)
Preferred stock —
 —
 (0.3) (0.3) —
 (0.3)
Stock-based compensation and other —
 0.3
 —
 0.3
 —
 0.3
Balance at June 30, 2018 $332.9
 $831.2
 $2,326.9
 $3,491.0
 $30.4
 $3,521.4

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


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WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
June 30, 20182019


NOTE 1—GENERAL INFORMATION


Wisconsin Electric Power Company serves approximately 1.1 million electric customers and 0.5 million 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 Electric Power Company and its former subsidiary, Bostco.Bostco, which was dissolved in October 2018.


We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017.2018. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2018,2019 are not necessarily indicative of expected results for 20182019 due to seasonal variations and other factors.


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


NOTE 2—DISPOSITIONOPERATING REVENUES


Other Segment–Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net onFor more information about our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shiftsignificant accounting policies related to operating revenues, see Note 1(d), Operating Revenues, in our corporate strategy and did not have a major effect2018 Annual Report on our operations and financial results.Form 10-K.


NOTE 3—OPERATING REVENUES

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

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

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

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

We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.
When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.
We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.

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We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.
We elected to apply this standard only to contracts that are not completed as of the date of initial application.

Disaggregation of Operating Revenues


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

  Wisconsin Electric Power Company Consolidated
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Electric utility $723.7
 $784.6
 $1,502.5
 $1,564.2
Natural gas utility 64.7
 68.6
 242.6
 229.4
Total revenues from contracts with customers 788.4
 853.2
 1,745.1
 1,793.6
Other operating revenues 3.3
 3.0
 7.4
 4.1
Total operating revenues $791.7
 $856.2
 $1,752.5
 $1,797.7

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

  Wisconsin Electric Power Company Consolidated
(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
Electric utility $784.6
 $1,564.2
Natural gas utility 68.6
 229.4
Total revenues from contracts with customers 853.2
 1,793.6
Other operating revenues 3.0
 4.1
Total operating revenues $856.2
 $1,797.7

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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 June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Residential $266.5
 $295.0
 $569.1
 $576.4
Small commercial and industrial 241.9
 260.6
 487.0
 498.3
Large commercial and industrial 139.4
 172.4
 295.4
 321.3
Other 4.9
 4.9
 10.5
 10.3
Total retail revenues 652.7
 732.9
 1,362.0
 1,406.3
Wholesale 20.1
 28.9
 49.0
 57.4
Resale 41.8
 17.1
 73.1
 80.8
Steam 4.3
 4.6
 14.4
 14.3
Other utility revenues 4.8
 1.1
 4.0
 5.4
Total electric utility operating revenues $723.7
 $784.6
 $1,502.5
 $1,564.2

  Electric Utility Operating Revenues
(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
Residential $295.0
 $576.4
Small commercial and industrial 260.6
 498.3
Large commercial and industrial 172.4
 321.3
Other 4.9
 10.3
Total retail revenues 732.9
 1,406.3
Wholesale 28.9
 57.4
Resale 17.1
 80.8
Steam 4.6
 14.3
Other utility revenues 1.1
 5.4
Total electric utility operating revenues $784.6
 $1,564.2

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


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

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

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


Natural Gas Utility Operating Revenues


The following table disaggregates natural gas utility operating revenues into customer class:
 Natural Gas Utility Operating Revenues
 Natural Gas Utility Operations Three Months Ended June 30 Six Months Ended June 30
(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 2019 2018 2019 2018
Residential $40.7
 $155.4
 $35.4
 $40.7
 $161.0
 $155.4
Commercial and industrial 18.2
 73.8
 14.1
 18.2
 75.0
 73.8
Total retail revenues 58.9
 229.2
 49.5
 58.9
 236.0
 229.2
Transport 3.1
 7.5
 2.9
 3.1
 7.2
 7.5
Other utility revenues * 6.6
 (7.3) 12.3
 6.6
 (0.6) (7.3)
Total natural gas utility operating revenues $68.6
 $229.4
 $64.7
 $68.6
 $242.6
 $229.4


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

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


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

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


Other Operating Revenues


Other operating revenues consist primarily of the following:
 Three Months Ended June 30 Six Months Ended June 30
(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 2019 2018 2019 2018
Late payment charges $2.1
 $4.9
 $2.0
 $2.1
 $4.7
 $4.9
Leases 1.4
 2.2
Rental revenues 1.5
 1.4
 2.2
 2.2
Alternative revenues * (0.5) (3.0) (0.2) (0.5) 0.5
 (3.0)
Total other operating revenues $3.0
 $4.1
 $3.3
 $3.0
 $7.4
 $4.1


*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 wholesale true-ups, as discussed below.true-ups.


Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates
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NOTE 3—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at June 30, 2019 and December 31, 2018. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.our 2018 Annual Report on Form 10-K.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.
(in millions) June 30, 2019 December 31, 2018
Regulatory assets    
Plant retirements * $954.5
 $754.1
Finance and capital leases 900.6
 869.3
Pension and OPEB costs 475.6
 490.6
Income tax related items 372.6
 317.9
SSR 319.0
 316.7
We Power generation 38.6
 43.0
Electric transmission costs 25.2
 57.8
Environmental remediation costs 23.6
 24.2
Other, net 17.2
 28.7
Total regulatory assets $3,126.9
 $2,902.3
     
Balance sheet presentation    
Other current assets $—
 $0.1
Regulatory assets 3,126.9
 2,902.2
Total regulatory assets $3,126.9
 $2,902.3


*On March 31, 2019, we retired the PIPP generating units. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP units.
(in millions) June 30, 2019 December 31, 2018
Regulatory liabilities    
Income tax related items $1,012.9
 $1,024.8
Removal costs 765.3
 748.1
Mines deferral 130.5
 120.8
Pension and OPEB costs 73.7
 74.7
Uncollectible expense 20.9
 16.4
Energy efficiency programs 14.7
 13.5
Other, net 23.2
 15.9
Total regulatory liabilities $2,041.2
 $2,014.2
     
Balance sheet presentation    
Other current liabilities $15.0
 $11.9
Regulatory liabilities 2,026.2
 2,002.3
Total regulatory liabilities $2,041.2
 $2,014.2


NOTE 4—PROPERTY, PLANT, AND EQUIPMENT


Utility SegmentPresque Isle Power Plant

Pursuant to be RetiredMISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. As a result of the retirement of the plant, the net book value was reclassified as a regulatory asset on our balance sheet. In the second quarter of 2019, $12.5 million of the regulatory asset, along with the related deferred taxes and a portion of the cost of removal reserve, was transferred to UMERC for recovery from their retail customers. At June 30, 2019, the remaining carrying value of the PIPP units on our balance sheet was $155.5 million. This amount included the net book value of $166.1 million, which was classified as a regulatory asset. In addition, a $10.6 million cost of removal reserve related to the PIPP units remained classified as a regulatory liability at June 30, 2019. We have FERC approval to continue to collect the carrying value of the PIPP units using the approved composite depreciation rates, in addition to a return on the remaining carrying value. However, this approval is subject to refund pending the outcome of settlement procedures. We will amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired.


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Severance Liability for Plant Retirements

We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement ofPIPP and the plants identified below.Pleasant Prairie power plant. In addition, a severance liability was recorded in other current liabilities on our balance sheets within the utility segment related to these plant retirements.
(in millions)  
Severance liability at December 31, 2018 $12.9
Severance payments (5.3)
Other (1.8)
Total severance liability at June 30, 2019 $5.8

(in millions)  
Severance liability at December 31, 2017 $25.8
Severance payments (8.7)
Other (3.0)
Total severance liability at June 30, 2018 $14.1

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired effective April 10, 2018. The carrying value of this plant was $667.7 million at June 30, 2018. This amount included the net book value of $774.2 million, which was reclassified as a regulatory asset on our balance sheet in the second quarter as a result of the retirement of the plant. In addition, a $106.5 million cost of removal reserve related to the Pleasant Prairie power plant was recorded as a regulatory liability at June 30, 2018. We continue to amortize this regulatory asset on

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a straight-line basis using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 16, Commitments and Contingencies, for more information.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new units are expected to begin commercial operation during the second quarter of 2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. In connection with MISO's April 2018 approval of the retirement of the plant, the PIPP units will be retired on or before May 31, 2019. The carrying value of the PIPP units was $189.7 million at June 30, 2018. This amount included the net book value of $199.8 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $10.1 million cost of removal reserve related to the PIPP units was recorded as a regulatory liability at June 30, 2018. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 16, Commitments and Contingencies, for more information.


NOTE 5—COMMON EQUITY


Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group 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 or its subsidiaries. See Note 8, Common Equity, in our 20172018 Annual Report on Form 10-K for additional information on these and other restrictions.


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


NOTE 6—SHORT-TERM DEBT AND LINES OF CREDIT


The following table shows our short-term borrowings and their corresponding weighted-average interest rates:
(in millions, except percentages) June 30, 2019 December 31, 2018
Commercial paper    
Amount outstanding $39.5
 $134.9
Weighted-average interest rate on amounts outstanding 2.50% 2.96%

(in millions, except percentages) June 30, 2018 December 31, 2017
Commercial paper    
Amount outstanding $341.8
 $210.9
Weighted-average interest rate on amounts outstanding 2.35% 1.81%


Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2018,2019 was $79.2$62.2 million with a weighted-average interest rate during the period of 2.06%2.68%.


The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:
(in millions) Maturity June 30, 2019
Revolving credit facility October 2022 $500.0
     
Less:    
Letters of credit issued inside credit facility   $1.2
Commercial paper outstanding   39.5
Available capacity under existing agreement   $459.3

(in millions) Maturity June 30, 2018
Revolving credit facility October 2022 $500.0
     
Less:    
Letters of credit issued inside credit facility   $1.2
Commercial paper outstanding   341.8
Available capacity under existing agreement   $157.0


NOTE 7—LONG-TERM DEBTLEASES


In July 2018,February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded.

As required, we redeemed all $80.0 million outstanding of our series of tax-exempt pollution control refunding bonds. Since August 2009,adopted Topic 842 effective January 1, 2019. We utilized the bondsfollowing practical expedients, which were outstanding, but were not reportedavailable under ASU 2016-02, in our long-term debt because theyadoption of the new lease guidance.

We did not reassess whether any expired or existing contracts were held by us.leases or contained leases.



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We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases).
We did not reassess the accounting for initial direct costs for any existing leases.

We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with Accounting Standards Codification 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract.

We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842.

In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842.

In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842.

Both the right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $13.0 million. Regarding our finance leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the finance lease assets and related liability amounts recorded on our balance sheets.

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities associated with the following operating leases.

Land we are leasing related to our Rothschild biomass plant through June 2018,2051.
Rail cars we are leasing to transport coal to various generating facilities through February 2021.
Various office space leases.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our $250.0 millionleases contain options to renew past the initial term, as set forth in the lease agreement.

Obligations Under Finance Leases

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under finance lease accounting, we have recorded the leased plants and corresponding obligations as right of 1.70% Debentures matured,use assets and lease liabilities on our balance sheets. We treat these agreements as operating leases for rate-making purposes.

Prior to our adoption of Topic 842 on January 1, 2019, we accounted for these finance leases under Topic 980-840, Regulated Operations – Leases, as follows:

We recorded our minimum lease payments under the power purchase contract as purchased power expense on our income statement.
We recorded our minimum lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements.

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We recorded the difference between the minimum lease payments and the outstanding principalsum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets.

In conjunction with our adoption of Topic 842, while the timing of expense recognition related to our finance leases did not change, the classification of the lease expense changed as follows:

Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within purchased power expense, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases.
Similarly, the lease payments related to our leases with We Power were no longer classified as rent expense within other operation and maintenance in our income statements, but were also divided between amortization expense and interest expense in accordance with Topic 980-842.
In order to ensure the timing of lease expense did not change for these finance leases upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, in accordance with Topic 980-842 the amortization of the right of use assets was paidmodified from what would typically be recorded for a finance lease under Topic 842.
We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets.

Power Purchase Commitment

In 1997, we entered into a 25-year power purchase contract with proceeds receivedan unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from issuing commercial paper.a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. We originally recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities.


As previously discussed, we treat the long-term power purchase contract as an operating lease for rate-making purposes. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $21.0 million at June 30, 2019, and will decrease to zero over the remaining life of the contract.

Port Washington Generating Station

We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units, which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.4 million in the year 2021 for PWGS 1 and to approximately $126.0 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases for the units was $626.7 million as of June 30, 2019, and will decrease to zero over the remaining lives of the contracts.

The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.

When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.


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Elm Road Generating Station

We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8 generating units, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $524.7 million in the year 2028 for ER 1 and to approximately $431.1 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases was $2,210.7 million as of June 30, 2019, and will decrease to zero over the remaining lives of the contracts.

The only variability associated with the ER lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.

When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.

Amounts Recognized in the Financial Statements

The components of lease expense and supplemental cash flow information related to our leases for the three and six months ended June 30 are as follows:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Long-term power purchase commitment $2.1
 $1.9
 $4.1
 $3.8
We Power leases 90.6
 91.8
 182.4
 183.6
Total finance/capital lease expense (1)
 $92.7
 $93.7
 $186.5
 $187.4
         
Operating lease expense (2)
 0.6
 0.7
 1.3
 1.4
Total lease expense $93.3
 $94.4
 $187.8
 $188.8
         
Other information        
         
Cash paid for amounts included in the measurement of lease liabilities        
Operating cash flows for finance/capital leases (3)
   

 $176.0
 $191.1
Operating cash flows for operating leases   

 $1.3
 $1.4
Financing cash flows for finance leases (3)
   

 $24.4
 $—
         
Non-cash activity – right of use assets obtained in exchange for operating lease liabilities   

 $13.0
  
         
Weighted-average remaining lease term – finance leases   

 19.1 years
  
Weighted-average remaining lease term – operating leases   

 23.0 years
  
         
Weighted-average discount rate – finance leases (4)
   

 13.9%  
Weighted average discount rate – operating leases (4)
   

 4.4%  

(1)
For the three and six months ended June 30, 2019, total finance lease expense included amortization of right of use assets in the amount of $4.8 million and $10.5 million (included in depreciation and amortization expense), respectively, and interest on lease liabilities of $87.9 million and $176.0 million (included in interest expense), respectively. For each of the three and six months ended June 30, 2018, total capital lease cost

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related to the long-term power purchase agreement was included in cost of sales and total capital lease cost related to the PWGS and ERGS units was included in other operation and maintenance.

(2)
Operating lease expense was included as a component of operation and maintenance for the three and six months ended June 30, 2019 and 2018.

(3)
Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to capital leases were recorded as a component of operating cash flows.

(4)
Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our financing leases, the rate implicit in each lease was readily determinable.

The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets:
(in millions) June 30, 2019 December 31, 2018
Long-term power purchase commitment    
Under finance/capital lease $140.3
 $140.3
Accumulated amortization (123.7) (120.9)
Total long-term power purchase commitment $16.6
 $19.4
     
PWGS    
Under finance/capital lease $740.0
 $736.9
Accumulated amortization (351.7) (335.9)
Total PWGS $388.3
 $401.0
     
ERGS    
Under finance/capital lease $2,188.8
 $2,166.3
Accumulated amortization (635.8) (598.8)
Total ERGS $1,553.0
 $1,567.5
     
Total finance lease right of use assets/capital lease assets $1,957.9
 $1,987.9


Right of use assets related to operating leases were $12.0 million at June 30, 2019, and were included in other long-term assets on our balance sheets.

Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of June 30, 2019 were as follows:
(in millions) Total Operating Leases Power Purchase Commitment PWGS ERGS Total Finance Leases
Six months ending December 31, 2019 $1.3
 $4.1
 $49.0
 $146.8
 $199.9
2020 2.7
 8.8
 98.1
 293.6
 400.5
2021 0.7
 9.4
 98.1
 293.6
 401.1
2022 0.6
 4.2
 98.1
 293.5
 395.8
2023 0.5
 —
 98.1
 293.3
 391.4
2024 0.5
 —
 98.0
 293.3
 391.3
Thereafter 13.5
 —
 678.7
 4,547.0
 5,225.7
Total minimum lease payments 19.8
 26.5
 1,218.1
 6,161.1
 7,405.7
Less: Interest (7.8) (5.5) (591.4) (3,950.4) (4,547.3)
Present value of minimum lease payments 12.0
 21.0
 626.7
 2,210.7
 2,858.4
Less: Short-term lease liabilities (2.3) (5.6) (23.8) (24.4) (53.8)
Long-term lease liabilities $9.7
 $15.4
 $602.9
 $2,186.3
 $2,804.6


Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively.


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Significant Judgments and Other Information

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

As of August 6, 2019, we have not entered into any material operating leases that have not yet commenced.

NOTE 8—MATERIALS, SUPPLIES, AND INVENTORIES


Our inventory consisted of:
(in millions) June 30, 2019 December 31, 2018
Materials and supplies $147.2
 $146.1
Fossil fuel 59.2
 58.7
Natural gas in storage 21.6
 36.6
Total $228.0
 $241.4

(in millions) June 30, 2018 December 31, 2017
Materials and supplies $137.2
 $140.7
Fossil fuel 75.9
 74.8
Natural gas in storage 23.6
 35.2
Total $236.7
 $250.7


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


NOTE 9—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 June 30, 2019 Three Months Ended June 30, 2018
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $14.4
 21.0 % $18.9
 21.0 %
State income taxes net of federal tax benefit 4.5
 6.6 % 5.8
 6.4 %
Tax repairs (30.5) (44.3)% (22.5) (24.7)%
Federal excess deferred tax amortization (3.8) (5.6)% (4.4) (4.8)%
Wind production tax credits (2.2) (3.2)% (2.3) (2.6)%
Other 1.3
 1.8 % 2.0
 1.9 %
Total income tax benefit $(16.3) (23.7)% $(2.5) (2.8)%

  Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $37.1
 21.0 % $40.4
 21.0 %
State income taxes net of federal tax benefit 11.6
 6.6 % 12.5
 6.5 %
Tax repairs (60.1) (33.9)% (48.0) (24.9)%
Federal excess deferred tax amortization (10.0) (5.7)% (9.8) (5.1)%
Wind production tax credits (5.0) (2.8)% (5.5) (2.9)%
Other 3.6
 1.9 % 4.3
 2.2 %
Total income tax benefit $(22.8) (12.9)% $(6.1) (3.2)%

The effective tax rates of (23.7)% and (12.9)% for the three and six months ended June 30, 2019, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, the impact of the Tax Legislation, and wind production tax credits, partially offset by state income taxes.

The effective tax rates of (2.8)% and (3.2)% for the three and six months ended June 30, 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, and the impact of the Tax Legislation, and wind production tax credits, partially offset by state income taxes.

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The Tax Legislation, signed into law in December 2017, required usour regulated utilities to remeasure ourtheir deferred income taxes and beginwe began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements.requirements (see federal excess deferred tax amortization line above). See Note 18, Regulatory Environment, for more information on the Tax Legislation andabout the Wisconsin rate settlement.

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


NOTE 10—FAIR VALUE MEASUREMENTS


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


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


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


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


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


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

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


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


The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
 June 30, 2018 June 30, 2019
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Derivative assets                
Natural gas contracts $1.5
 $—
 $—
 $1.5
 $0.3
 $—
 $—
 $0.3
Petroleum products contracts 0.3
 —
 —
 0.3
FTRs —
 —
 8.7
 8.7
 —
 —
 5.8
 5.8
Coal contracts —
 0.5
 —
 0.5
 —
 0.1
 —
 0.1
Total derivative assets $1.8
 $0.5
 $8.7
 $11.0
 $0.3
 $0.1
 $5.8
 $6.2
                
Derivative liabilities                
Natural gas contracts $0.1
 $—
 $—
 $0.1
 $7.9
 $—
 $—
 $7.9
Coal contracts —
 0.1
 —
 0.1
Total derivative liabilities $7.9
 $0.1
 $—
 $8.0



  December 31, 2017
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.5
 $0.1
 $—
 $0.6
Petroleum products contracts 0.9
 —
 —
 0.9
FTRs —
 —
 2.4
 2.4
Coal contracts —
 0.7
 —
 0.7
Total derivative assets $1.4
 $0.8
 $2.4
 $4.6
         
Derivative liabilities       
Natural gas contracts $2.0
 $0.1
 $—
 $2.1
Coal contracts —
 0.3
 —
 0.3
Total derivative liabilities $2.0
 $0.4
 $—
 $2.4

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  December 31, 2018
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.7
 $—
 $—
 $0.7
FTRs —
 —
 4.4
 4.4
Total derivative assets $0.7
 $—
 $4.4
 $5.1
         
Derivative liabilities       
Natural gas contracts $1.2
 $—
 $—
 $1.2
Coal contracts —
 0.1
 —
 0.1
Total derivative liabilities $1.2
 $0.1
 $—
 $1.3


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 June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Balance at the beginning of the period $2.0
 $0.8
 $4.4
 $2.4
Purchases 6.8
 9.4
 6.8
 9.4
Settlements (3.0) (1.5) (5.4) (3.1)
Balance at the end of the period $5.8
 $8.7
 $5.8
 $8.7

  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Balance at the beginning of the period $0.8
 $1.1
 $2.4
 $3.1
Purchases 9.4
 6.9
 9.4
 6.9
Settlements (1.5) (2.0) (3.1) (4.0)
Balance at the end of the period $8.7
 $6.0
 $8.7
 $6.0


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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:
  June 30, 2019 December 31, 2018
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $28.2
 $30.4
 $28.3
Long-term debt, including current portion 2,710.4
 3,068.9
 2,709.6
 2,881.6

  June 30, 2018 December 31, 2017
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $28.7
 $30.4
 $30.5
Long-term debt, including current portion 2,413.4
 2,603.4
 2,662.3
 2,976.3


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


NOTE 11—DERIVATIVE INSTRUMENTS


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


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



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The following table shows our derivative assets and derivative liabilities:liabilities, none of which are designated as hedging instruments.
 June 30, 2018 December 31, 2017 June 30, 2019 December 31, 2018
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current                
Natural gas contracts $1.5
 $—
 $0.6
 $1.9
 $0.3
 $7.5
 $0.7
 $1.2
Petroleum products contracts 0.3
 —
 0.9
 —
FTRs 8.7
 —
 2.4
 —
 5.8
 —
 4.4
 —
Coal contracts 0.5
 —
 0.6
 0.1
 0.1
 0.1
 —
 0.1
Total other current * $11.0
 $—
 $4.5
 $2.0
 $6.2
 $7.6
 $5.1
 $1.3
                
Other long-term        
Other long-term *        
Natural gas contracts $—
 $0.1
 $—
 $0.2
 $—
 $0.4
 $—
 $—
Coal contracts —
 —
 0.1
 0.2
Total other long-term * —
 0.1
 0.1
 0.4
Total $11.0
 $0.1
 $4.6
 $2.4
 $6.2
 $8.0
 $5.1
 $1.3


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


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


 Three Months Ended June 30, 2018
Three Months Ended June 30, 2017 Three Months Ended June 30, 2019 Three Months Ended June 30, 2018
(in millions) Volumes
Gains (Losses)
Volumes
Gains (Losses) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 12.0 Dth $(0.6) 5.0 Dth $0.2
 13.6 Dth $(1.1) 12.0 Dth $(0.6)
Petroleum products contracts 1.1 gallons 0.2
 4.9 gallons (0.4) — gallons —
 1.1 gallons 0.2
FTRs 4.8 MWh 0.9
 7.3 MWh 2.0
 5.6 MWh 0.5
 4.8 MWh 0.9
Total   $0.5
   $1.8
   $(0.6)   $0.5



 Six Months Ended June 30, 2018
Six Months Ended June 30, 2017 Six Months Ended June 30, 2019
Six Months Ended June 30, 2018
(in millions) Volumes
Gains (Losses)
Volumes
Gains (Losses) Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts 23.7 Dth
$(2.4)
13.2 Dth
$0.7
 31.7 Dth
$(2.5)
23.7 Dth
$(2.4)
Petroleum products contracts 2.5 gallons
0.6

9.8 gallons
(0.9) — gallons
—

2.5 gallons
0.6
FTRs 10.6 MWh
1.7

14.3 MWh
4.5
 11.1 MWh
2.1

10.6 MWh
1.7
Total  
$(0.1)
 
$4.3
  
$(0.4)
 
$(0.1)


On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 20182019 and December 31, 2017,2018, we had posted cash collateral of $1.0$10.3 million and $4.9$1.1 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets.


The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
 June 30, 2018 December 31, 2017 June 30, 2019 December 31, 2018
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Gross amount recognized on the balance sheet $11.0
 $0.1
 $4.6
 $2.4
  $6.2
 $8.0
 $5.1
 $1.3
 
Gross amount not offset on the balance sheet (0.1) (0.1) (1.3) (2.0)* (0.3) (7.9)
(1) 
(0.6) (1.3)
(2) 
Net amount $10.9
 $—
 $3.3
 $0.4
  $5.9
 $0.1
 $4.5
 $—
 


*
(1)
Includes cash collateral posted of $7.6 million.

(2)
Includes cash collateral posted of $0.7 million.



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NOTE 12—GUARANTEES

As of June 30, 2019, we had $26.2 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

NOTE 12—13—EMPLOYEE BENEFITS


The following tables show the components of net periodic pension and OPEB costs for our benefit plans:
 Pension Costs Pension Costs
 Three Months Ended June 30 Six Months Ended June 30 Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017 2019 2018 2019 2018
Service cost $3.3
 $3.1
 $6.6
 $6.1
 $2.5
 $3.3
 $6.3
 $6.6
Interest cost 10.5
 11.6
 21.1
 23.5
 11.1
 10.5
 22.6
 21.1
Expected return on plan assets (18.6) (19.1) (37.6) (38.3) (18.0) (18.6) (36.2) (37.6)
Loss on plan settlement —
 2.8
 —
 2.8
Amortization of prior service cost 0.2
 0.3
 0.4
 0.6
 0.1
 0.2
 0.2
 0.4
Amortization of net actuarial loss 9.6
 8.9
 19.0
 17.7
 6.8
 9.6
 14.0
 19.0
Net periodic benefit cost $5.0
 $7.6
 $9.5
 $12.4
 $2.5
 $5.0
 $6.9
 $9.5



  OPEB Costs
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Service cost $1.0
 $1.7
 $2.2
 $3.5
Interest cost 2.4
 2.7
 4.8
 5.5
Expected return on plan assets (3.6) (3.9) (7.1) (7.8)
Amortization of prior service credit (0.5) (0.5) (1.0) (1.1)
Amortization of net actuarial gain (0.7) —
 (1.1) —
Net periodic benefit (credit) cost $(1.4) $—
 $(2.2) $0.1

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  OPEB Costs
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Service cost $1.7
 $1.5
 $3.5
 $3.4
Interest cost 2.7
 3.1
 5.5
 6.2
Expected return on plan assets (3.9) (3.6) (7.8) (7.2)
Amortization of prior service credit (0.5) (0.3) (1.1) (0.6)
Amortization of net actuarial gain —
 (0.3) —
 —
Net periodic benefit cost $—
 $0.4
 $0.1
 $1.8


During the six months ended June 30, 2018,2019, we made contributions and payments of $2.9$2.5 million related to our pension plans and $0.9$0.7 million related to our OPEB plans. We expect to make contributions and payments of $1.2$1.3 million related to our pension plans and $3.5$2.9 million related to our OPEB plans during the remainder of 2018,2019, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

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

The following table shows the non-service (credit) cost components of net benefit costs:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Non-service (credit) cost components $(1.2) $3.3
 $(2.9) $4.5

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

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


NOTE 13—14—SEGMENT INFORMATION


We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2018,2019, we reported two segments, which are described below.


Our utility segment includes both our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin, andWisconsin. Prior to one customerApril 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. OurThis customer was transferred to UMERC on April 1, 2019 as UMERC's new generation in the Upper Peninsula of Michigan is now operational. In addition, our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin.Milwaukee. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.


OurPrior to October 2018, our other segment includesincluded Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Disposition, for more information.Bostco, and, in October 2018, Bostco was dissolved. No significant items were reported in the other segment during the six months ended June 30, 2019 and 2018.




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The following tables show summarized financial information for the three and six months ended June 30, 2018 and 2017, related to our reportable segments:
(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2018      
Operating revenues $856.2
 $—
 $856.2
Other operation and maintenance 366.6
 —
 366.6
Depreciation and amortization 86.9
 —
 86.9
Operating income 104.5
 —
 104.5
Interest expense 29.2
 —
 29.2
(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Three Months Ended June 30, 2017      
Operating revenues $855.4
 $—
 $855.4
Other operation and maintenance * 324.4
 —
 324.4
Depreciation and amortization 82.7
 —
 82.7
Operating income * 146.1
 —
 146.1
Interest expense 29.1
 —
 29.1

*Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 12, Employee Benefits, for more information on this new standard.
(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2018      
Operating revenues $1,797.7
 $—
 $1,797.7
Other operation and maintenance 702.2
 —
 702.2
Depreciation and amortization 172.2
 —
 172.2
Operating income 240.9
 —
 240.9
Interest expense 58.9
 —
 58.9
(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Six Months Ended June 30, 2017      
Operating revenues $1,827.4
 $—
 $1,827.4
Other operation and maintenance * 651.0
 —
 651.0
Depreciation and amortization 164.8
 —
 164.8
Operating income * 332.4
 —
 332.4
Interest expense 58.4
 0.3
 58.7

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

NOTE 14—15—VARIABLE INTEREST ENTITIES


The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.


We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.


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Purchased Power Purchase Agreement


We have a purchased power purchase agreement that represents a variable interest. This agreement is for 236 MWMWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capitalfinance lease. The agreement includes no minimum energy requirements over the remaining term of approximately fourthree years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power purchase agreement.


We have approximately $64.1$26.5 million of required capacity payments over the remaining term of this agreement. We believe that the required leasecapacity payments under this contract will continue to be recoverable in rates. Total capacityrates, and lease payments under this contract for the six months ended June 30, 2018 and 2017 were $9.4 million and $9.0 million, respectively. Ourour maximum exposure to loss is limited to thethese capacity payments under the contract.payments.


NOTE 15—RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and other affiliated entities.

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

On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016 to another subsidiary of WEC Energy Group. In addition, during 2017 we transferred $186.8 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.

Our balance sheets included the following receivables and payables related to transactions entered into with ATC:
(in millions) June 30, 2018 December 31, 2017
Accounts receivable    
Services provided to ATC $1.3
 $0.8
Accounts payable    
Services received from ATC 19.3
 22.2


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The following table shows activity associated with our related party transactions:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Lease agreements  
  
  
  
Lease payments to We Power (1)
 $95.1
 $106.7
 $187.3
 $211.1
Construction work in progress billed to We Power 5.0
 8.9
 8.8
 25.2
Transactions with WBS (2)
        
Billings to WBS 2.8
 60.5
 8.7
 117.0
Billings from WBS (3)
 68.6
 52.9
 176.7
 102.7
Transactions with WPS (2)
        
Billings to WPS 4.3
 5.2
 7.3
 7.7
Billings from WPS 1.9
 1.1
 5.1
 2.2
Transactions with WG    
    
Natural gas purchases from WG 1.3
 1.3
 2.6
 2.6
Billings to WG (2) (4)
 13.2
 16.1
 27.1
 31.9
Billings from WG (2)
 5.0
 5.8
 9.7
 11.3
Transactions with UMERC        
Electric sales to UMERC 6.9
 6.4
 15.0
 14.1
Billings to UMERC (2)
 2.9
 29.3
 7.1
 33.9
Transactions with Bluewater (5)
        
Storage service fees 4.6
 —
 5.9
 —
Transactions with ATC        
Charges to ATC for services and construction 2.7
 2.4
 5.7
 5.2
Charges from ATC for network transmission services 58.1
 60.4
 116.1
 120.7
Refund from ATC related to a FERC audit 15.4
 —
 15.4
 —
Refund from ATC per FERC ROE order —
 —
 —
 19.4

(1)
We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. Lease payments were reduced in 2018 as a result of tax savings related to Tax Legislation.

(2)
Includes amounts billed for services, pass through costs, and other items in accordance with approved affiliated interest agreements.

(3)
Includes $8.7 million and $57.6 million for the transfer of certain software assets from WBS during the three and six months ended June 30, 2018, respectively. There were no software assets transferred from WBS during 2017.

(4)
Includes $5.2 million for the transfer of certain software assets to WG during the three and six months ended June 30, 2018. There were no software assets transferred to WG during 2017.

(5)
WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

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 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. 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 net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017 was $61.1 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS.


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

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

NOTE 16—COMMITMENTS AND CONTINGENCIES


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


Unconditional Purchase Obligations


We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of June 30, 2018,2019, were $9,760.2 million.approximately $9.9 billion.


Environmental Matters


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


Air Quality


8-Hour Ozone National Ambient Air Quality Standards


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


Climate Change

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

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



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NotwithstandingMercury and Air Toxics Standards

In December 2018, the uncertain futureEPA proposed to revise 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 review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CPP,CAA. As a result, under the proposed rule, the emission standards and given current fuelother requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal-and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations.

Climate Change

In July 2019, the EPA published the ACE rule, which provides existing coal-fired generating units with standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and technology markets, wedistinct rulemakings, (1) the repeal of the Clean Power Plan, 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 would need to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The rule is being litigated.

In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA determined that the 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.

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 continue to evaluate opportunitiesupdate this analysis as climate-change policies and actions that preserverelevant technologies evolve over time with a focus on preserving fuel diversity, lowerlowering costs for our customers, and contribute towardsreducing long-term GHG reductions. emissions.

WEC Energy Group's plan, which includes us, is to work with its industry partners,peers, environmental groups, public policy makers, and the State of Wisconsin,customers, with a goalgoals of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group's new long-term goal is to reduce CO2 emissions by approximatelyand 80% below 2005 levels by 2050. We have implemented2030 and continue to evaluate numerous options in order to meet WEC Energy Group's CO2 reduction goals. Options considered include increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.2050, respectively. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547retired approximately 1,500 MW of coal generation by 2020, includingsince the beginning of 2018. This plan consisted of the March 31, 2019 retirement of the PIPP as well as the 2018 retirement of the Pleasant Prairie power plant (retired in April 2018) and PIPP.plant. See Note 4, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.information on the retirement of the PIPP.


Water Quality


Clean Water Act Cooling Water Intake Structure Rule


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


Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. 

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence,determinations for our intake modification at Valley power plant. Due to the retirement of the Pleasant Prairie Power Plant and our plans to retire PIPP, we do not believe that BTA determinations for EM will be necessary for these units. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTAfinal determinations to address EM reduction requirements will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements for these units. During 2018, we will continue to evaluate options to address the EM BTA requirements for these units.


We have also provided information to the WDNRWisconsin Department of Natural Resources and the MDEQ about plannedgenerating unit retirements. Based onFollowing discussions with the MDEQ, ifin January 2019, we submitsubmitted a signed certification stating that the PIPP willwould be retired no later than the endJune 1, 2019. The PIPP was retired on March 31, 2019.

As a result of the next permit cycle (assumedpast capital investments completed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ during 2018, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance.

Weaddress 316(b) compliance, we believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.



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Steam Electric Effluent Limitation Guidelines


The EPA's final steam electric effluent limitation guidelines (ELG)ELG rule took effect in January 2016. VariousThis rule created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for BATW and wet FGD wastewater.

This rule is being litigated, and various petitions challenging the ruleit were consolidated and are pending in the United States Fifth Circuit Court of Appeals.Appeals for the Fifth Circuit. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance datesdate to November 1, 2020 for the bottom ash transport waterBATW and wet flue gas desulfurization FGD wastewater requirements. Thisrequirements. The latest ELG rule applies tocompliance date remains December 31, 2023 for any new wastewater discharges from ourtreatment requirements contained in power plant processes in Wisconsin and Michigan. In February 2018, the Center for Biological Diversity (CBD) filed suit in the U.S. District Courtdischarge permits.

As a result of Arizona challenging the Postponement

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Rule. In April 2018, the Utility Water Act Group filed a motionpast capital investments completed to dismiss the CBD suit for lack of subject matter jurisdiction. While theaddress ELG compliance, deadlines are postponed,we believe our fleet overall is well positioned to meet the WDNR and the MDEQ have indicated that they 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 and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years.regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed,in its current form, the ELG rule willwould require additional wastewater treatment retrofits as well asand the installation of other equipment to minimize process water use.

The final rule would phase in new or more stringent requirements related Due to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatmentcompleted generating unit retirements, we believe the only facilities that would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systemssystem modifications are required by the new rule, and modifications would be required at OC 7 and OC 8. We are beginningOne wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. Based on preliminary engineering, forthe estimated rule compliance with the rule and estimatecost is approximately $50 million would be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the planned retirement of PIPP as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.million.


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. 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.


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


We have established the following regulatory assets and reserves related to manufactured gas plant sites:
(in millions) June 30, 2018 December 31, 2017 June 30, 2019 December 31, 2018
Regulatory assets $29.9
 $30.4
 $23.6
 $24.2
Reserves for future remediation * 18.5
 18.5
 13.2
 13.2


*Recorded within other long-term liabilities on our balance sheets.


Enforcement and Litigation Matters


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




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NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION
  Six Months Ended June 30
(in millions) 2018 2017
Cash (paid) for interest, net of amount capitalized $(57.8) $(57.6)
Cash (paid) for income taxes, net (8.2) (63.4)
Significant noncash transactions:    
Accounts payable related to construction costs 4.5
 13.0
Accounts payable related to assets transferred from affiliates 7.5
 —
Accounts receivable related to assets transferred to affiliates 5.4
 —
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2)
 —
 415.4
Transfer of net assets to UMERC (1)
 —
 60.0
  Six Months Ended June 30
(in millions) 2019 2018
Cash (paid) for interest, net of amount capitalized * $(239.1) $(57.8)
Cash (paid) for income taxes, net (10.6) (8.2)
Significant non-cash investing and financing transactions:    
Accounts payable related to construction costs 6.6
 4.5
Accounts payable related to the transfer of certain software assets from affiliates —
 7.5
Accounts receivable related to the transfer of certain software assets to affiliates —
 5.4


(1)
*		On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during the six months ended June 30, 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 15, Related Parties,7, Leases, for more information on these transactions.Topic 842 and our finance leases.

(2)
The amount transferred included a $13.4 million receivable for distributions approved and recorded in December 2016.


NOTE 18—REGULATORY ENVIRONMENT


Tax Cuts2020 and Jobs Act of 20172021 Rates


We deferred for returnIn March 2019, we filed an application with the PSCW to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate,increase our retail electric, natural gas, and steam rates, effective January 1, 2018,2020. Our proposal is also being deferred for return to ratepayers.

In May 2018, the PSCW issuedtargeting an order regarding the benefits associated with the Tax Legislation. The PSCW order requires oureffective electric utility operations to use 80%rate increase of the current 2018approximately $83 million (2.9%) in 2020 and 2019 tax benefits to reduce our transmission regulatory asset. The remaining 20% is to be returned to electric customersan additional increase of $83 million (2.9%) in the form of bill credits.2021. For our natural gas utility operations,and steam customers, our proposal is targeting effective rate increases of approximately $15 million (3.9%) and $1 million (4.5%), respectively, in 2020, with no additional increases in 2021. Our proposal reflects a ROE of 10.35% and a common equity component average of 52.0% on a financial basis. We also proposed to continue having an earnings sharing mechanism through 2021.

Our proposed increase in electric rates was driven by higher transmission charges, recovery of SSR revenues that were assumed in our 2015 rate order but were not received, and an increase in costs associated with a purchased power agreement previously approved by the PSCW indicated that 100%PSCW. Our proposed electric rates reflect our request to partially offset these increases with approximately $111 million of current 2018 and 2019previously deferred tax benefits should be returnedfrom the Tax Legislation. Our proposal also includes our request for approval to natural gas customerscontinue collecting the carrying value of the Pleasant Prairie power plant and the PIPP using the current approved composite depreciation rates, in addition to a return on the formremaining carrying value of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce our transmission regulatory asset for our electric utility operations and is being deferred forplants.

The proposed increase at our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes forwas driven by continued investment in our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. During the six months ended June 30, 2018, we reduced our transmission regulatory asset by $33.8 million as a result ofdistribution system.

A final order is expected from the PSCW order.
We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addresses all base rate impactsend of the Tax Legislation, which will be returned to the customer through bill credits.2019, with rates effective January 1, 2020.


2018 and 2019 Rates


During April 2017, we, along with WG and WPS,Wisconsin Public Service Corporation, 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 freezefreezes base rates through 2019 for our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remains at 10.2%, and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.


In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We will flow through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits

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to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.



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Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.


Solar Generation Project

On August 1, 2019, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin. Subject to receipt of the PSCW's approval, we will own 100 MW of the output of this project. Our share of the cost of this project is estimated to be $130 million. Commercial operation for Badger Hollow II is targeted for the end of 2021.

NOTE 19—NEW ACCOUNTING PRONOUNCEMENTS

Leases

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


Financial Instruments Credit Losses


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


Cloud Computing

In August 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 asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. We are currently evaluating the transition methods and the impact the adoption of this standard may have on our financial statements.

Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and other postretirement benefit 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 all 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 effects of this pronouncement on our Notes to Consolidated Financial Statements.



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


CORPORATE DEVELOPMENTS


The following discussion should be read in conjunction with the accompanying financial statements and related notes and our 2018 Annual Report on Form 10-K for the year ended December 31, 2017.10-K.


Introduction


We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 13,14, Segment Information, for more information on our reportable business segments.

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. See Note 2, Disposition, for more information.


Corporate Strategy


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


Reshaping Our Generation Fleet


WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group set a new long-term goal of reducing CO2 emissions2030 and by approximately 80% below 2005 levels by 2050. WEC Energy Group expects to retirehas retired approximately 1,800 MW of coal generation by 2020since the beginning of 2018 across its electric utilities, and expects to add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. OurWe retired our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. Itimmediately as it may take several years to finalize long-term plans for the site. We retired the Presque Isle power plant (PIPP) in March 2019. See Note 4, Property, Plant, and Equipment, for information related to the Pleasant Prairie power plant retirement and the planned retirement of PIPP asretirement.

As part of its commitment to invest in zero-carbon generation, WEC Energy Group's plan.Group plans to invest in utility scale solar of up to 350 MW within its Wisconsin segment, which includes us. We have partnered with an unaffiliated utility to acquire an ownership interest in Badger Hollow Solar Farm II, a solar project that will be located in Iowa County, Wisconsin. Subject to PSCW approval, we will own 100 MW of the output of the project. Commercial operation is targeted for the end of 2021. In December 2018, we received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add 35 MW of solar to our portfolio, allowing commercial and industrial customers to site utility owned solar arrays on their property. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that we would operate, adding up to 150 MW of renewables to our portfolio, and allowing these larger customers to meet their sustainability and renewable energy goals. As the cost of renewable energy generation continues to decline, these pilots have become cost effective opportunities for us and our customers to participate in renewable energy.


Reliability


We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized in 2018 by PA Consulting Group, an independent consulting firm, as the most reliable utility in the United States in 2017 and,Midwest for the seventheighth year in a row, asrow. We Energies is the most reliable utility in the Midwest.trade name under which we and WG, another wholly owned subsidiary of WEC Energy Group, operate.


Operating Efficiency


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

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between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.


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

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Financial Discipline


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


We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Disposition, for information on the sale of Bostco's remaining real estate holdings.


Exceptional Customer Care


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


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


Safety


We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. WEC Energy Group'sOur 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 JUNE 30, 20182019


Consolidated Earnings


The following table compares our consolidated results for the second quarter of 20182019 with the second quarter of 2017,2018, including favorable or better, "B", and unfavorable or worse, "W", variances:
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) Change Related to Flow Through of Tax Repairs Change Related to Tax Legislation Remaining Change
B (W)		 2019 2018 B (W) Change Related to Flow Through of Tax Repairs Change Related to Adoption of New Lease Guidance (Topic 842) Remaining Change
B (W)
Operating revenues $856.2
 $855.4
 $0.8
 $(20.9) $15.4
 $6.3
 $791.7
 $856.2
 $(64.5) $(4.6) $—
 $(59.9)
Cost of sales 270.9
 273.9
 3.0
 —
 —
 3.0
 253.5
 270.9
 17.4
 —
 2.1
 15.3
Other operation and maintenance 366.6
 324.4
 (42.2) (10.0) (33.8) 1.6
 234.3
 366.6
 132.3
 (6.5) 90.6
 48.2
Depreciation and amortization 86.9
 82.7
 (4.2) —
 —
 (4.2) 95.2
 86.9
 (8.3) —
 (4.8) (3.5)
Property and revenue taxes 27.3
 28.3
 1.0
 —
 —
 1.0
 26.1
 27.3
 1.2
 —
 —
 1.2
Operating income 104.5
 146.1
 (41.6) (30.9) (18.4) 7.7
 182.6
 104.5
 78.1
 (11.1) 87.9
 1.3
Other income, net 15.3
 1.1
 14.2
 —
 —
 14.2
 5.9
 15.3
 (9.4) —
 —
 (9.4)
Interest expense 29.2
 29.1
 (0.1) —
 —
 (0.1) 119.6
 29.2
 (90.4) —
 (87.9) (2.5)
Income before income taxes 90.6
 118.1
 (27.5) (30.9) (18.4) 21.8
 68.9
 90.6
 (21.7) (11.1) —
 (10.6)
Income tax (benefit) expense (2.5) 42.5
 45.0
 30.9
 18.4
 (4.3)
Income tax benefit (16.3) (2.5) 13.8
 11.1
 —
 2.7
Preferred stock dividend requirements 0.3
 0.3
 —
 —
 —
 —
 0.3
 0.3
 —
 —
 —
 —
Net income attributed to common shareholder $92.8
 $75.3
 $17.5
 $—
 $—
 $17.5
 $84.9
 $92.8
 $(7.9) $—
 $—
 $(7.9)


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Our consolidated earnings fordecreased $7.9 million during the three months ended June 30, 2018 were $92.8 million,second quarter of 2019, compared to $75.3 million forwith the same quarter in 2017.2018. The table above shows the income statement impactimpacts associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017.adoption of ASU 2016-02, Leases (Topic 842), effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder.shareholder, but did significantly impact our operating income. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.information on the flow through of tax repairs and Note 7, Leases, for more information on the adoption of Topic 842. See below for additional information on the $17.5$7.9 million increasedecrease 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 June 30, 2019 and 2018 and 2017 was $104.5$182.6 million and $146.1$104.5 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.


Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the second quarter of 2018 with the same quarter of 2017, including favorable or better, "B", and unfavorable or worse, "W", variances.
  Three Months Ended June 30
(in millions) 2018 2017 B (W)
Electric revenues $787.3
 $793.6
 $(6.3)
Fuel and purchased power 232.5
 241.2
 8.7
Total electric margins 554.8
 552.4
 2.4
       
Natural gas revenues 68.9
 61.8
 7.1
Cost of natural gas sold 38.4
 32.7
 (5.7)
Total natural gas margins 30.5
 29.1
 1.4
       
Total electric and natural gas margins 585.3
 581.5
 3.8
       
Other operation and maintenance 366.6
 324.4
 (42.2)
Depreciation and amortization 86.9
 82.7
 (4.2)
Property and revenue taxes 27.3
 28.3
 1.0
Operating income $104.5
 $146.1
 $(41.6)



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Utility Segment Contribution to Operating Income
  Three Months Ended June 30
(in millions) 2019 2018 B (W)
Electric revenues $726.6
 $787.3
 $(60.7)
Fuel and purchased power 218.1
 232.5
 14.4
Total electric margins 508.5
 554.8
 (46.3)
       
Natural gas revenues 65.1
 68.9
 (3.8)
Cost of natural gas sold 35.4
 38.4
 3.0
Total natural gas margins 29.7
 30.5
 (0.8)
       
Total electric and natural gas margins 538.2
 585.3
 (47.1)
       
Other operation and maintenance 234.3
 366.6
 132.3
Depreciation and amortization 95.2
 86.9
 (8.3)
Property and revenue taxes 26.1
 27.3
 1.2
Operating income $182.6
 $104.5
 $78.1

The following table shows a breakdown of other operation and maintenance:
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Operation and maintenance not included in line items below $108.0
 $106.6
 $(1.4) $79.8
 $108.0
 $28.2
We Power (1)
 125.9
 127.1
 1.2
 34.2
 125.9
 91.7
Transmission (2)
 66.1
 67.5
 1.4
 62.6
 66.1
 3.5
Transmission expense related to the flow through of tax repairs (3)
 10.0
 —
 (10.0) 16.5
 10.0
 (6.5)
Transmission expense related to Tax Legislation (4)
 33.8
 —
 (33.8) 17.5
 33.8
 16.3
Regulatory amortizations and other pass through expenses (5)
 22.8
 23.2
 0.4
 23.7
 22.8
 (0.9)
Total other operation and maintenance $366.6
 $324.4
 $(42.2) $234.3
 $366.6
 $132.3


(1) 
Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well aswe recognized. For the three months ended June 30, 2018, the amount also included the lease payments that arewere billed from We Power to us and then recovered in our rates. We adopted ASU 2016-02, Leases (Topic 842) effective January 1, 2019, which revised the previous guidance regarding the accounting for leases. As a result of this adoption, for the three months ended June 30, 2019, the $90.6 million of lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as $3.6 million and $87.0 million of depreciation and amortization and interest expense, respectively, in accordance with Topic 842.

During the three months ended June 30, 2019, $45.6 million of operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset. During the three months ended June 30, 2018, and 2017, $126.1 million and $139.2 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.


(2) 
The PSCW has approvedRepresents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended June 30, 2019 and 2018, and 2017, $64.2$80.5 million and $79.6$64.2 million, respectively, of costs were billed to us by transmission providers.


(3) 
Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at ourtheir December 31, 2017 levels. See Note 18, Regulatory Environment, for more information.


(4) 
As a result ofRepresents additional transmission expense associated with the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce our transmission regulatory asset balance, our transmission expense increased during the second quarter of 2018 with a corresponding offset in income taxes. See Note 18, Regulatory Environment, for more information.balance.


(5) 
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.



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The following tables provide information on delivered sales volumes by customer class and weather statistics:
 Three Months Ended June 30 Three Months Ended June 30
 
MWh (in thousands)
 
MWh (in thousands)
Electric Sales Volumes 2018 2017 B (W) 2019 2018 B (W)
Customer Class        
Residential 1,855.0
 1,797.8
 57.2
 1,682.0
 1,855.0
 (173.0)
Small commercial and industrial 2,165.0
 2,104.2
 60.8
 2,048.4
 2,165.0
 (116.6)
Large commercial and industrial 2,133.7
 2,092.1
 41.6
 1,693.2
 2,133.7
 (440.5)
Other 32.0
 33.6
 (1.6) 33.1
 32.0
 1.1
Total retail 6,185.7
 6,027.7
 158.0
 5,456.7
 6,185.7
 (729.0)
Wholesale 394.2
 397.2
 (3.0) 296.6
 394.2
 (97.6)
Resale 560.3
 1,064.6
 (504.3) 1,604.5
 560.3
 1,044.2
Total sales in MWh 7,140.2
 7,489.5
 (349.3) 7,357.8
 7,140.2
 217.6


 Three Months Ended June 30 Three Months Ended June 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2018 2017 B (W) 2019 2018 B (W)
Customer Class        
Residential 59.0
 46.7
 12.3
 55.9
 59.0
 (3.1)
Commercial and industrial 35.0
 27.8
 7.2
 31.3
 35.0
 (3.7)
Total retail 94.0
 74.5
 19.5
 87.2
 94.0
 (6.8)
Transport 77.7
 71.4
 6.3
 79.3
 77.7
 1.6
Total sales in therms 171.7
 145.9
 25.8
 166.5
 171.7
 (5.2)

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 Three Months Ended June 30 Three Months Ended June 30
 Degree Days Degree Days
Weather * 2018 2017 B(W) 2019 2018 B (W)
Heating (914 normal) 1,023
 748
 36.8%
Heating (921 normal) 973
 1,023
 (4.9)%
Cooling (166 normal) 217
 203
 6.9% 76
 217
 (65.0)%


*Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.


Electric Utility Margins


Electric utility margins increased $2.4decreased $46.3 million during the second quarter of 2018,2019, compared with the same quarter in 2017.2018. The significant factors impacting the higherlower electric utility margins were:


•
A $27.0 million decrease related to lower retail sales volumes during the second quarter of 2019, primarily driven by unfavorable weather. As measured by cooling degree days, the second quarter of 2019 was 65.0% cooler than the same quarter in 2018. As measured by heating degree days, the second quarter of 2019 was 4.9% warmer than the same quarter in 2018.

A $17.5$16.3 million increasedecrease in margins related to an increasesavings from the Tax Legislation that we are required to return to customers through bill credits or reductions in revenues, withother regulatory assets. This decrease in margins was offset by a corresponding increasedecrease in transmission expense, as a result ofexpense. We received the PSCW'sPSCW order in May 2018, associated with the Tax Legislation. The PSCW orderwhich required us to applyuse 80% of ourthe current 2018 and 2019 tax benefit against our transmissionbenefits to reduce certain regulatory asset balance.assets. Prior to receiving the order, we recorded all of the expected benefits related to the Tax Legislation as if they would be returned to customers through refunds or bill credits, which resulted in a decrease in revenuerevenues in the first quarter of 2018. InAfter receiving the order during the second quarter of 2018, we reversed a portion of this decrease in revenues we had assumed would be returned to customers as a result ofbill credits and instead applied the order. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.tax savings by reducing the regulatory assets.

•
A $4.6 million decrease in margins associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. See Note 18, Regulatory Environment, for more information.


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A $9.1$4.6 million increase related to higher retaildecrease in wholesale margins driven by lower sales volumes duringto UMERC. UMERC's new natural gas-fired generation in the second quarterUpper Peninsula of 2018, primarily driven by favorable weather and higher overall use per retail customer. Michigan began commercial operation on March 31, 2019, at which time we ceased providing wholesale services to UMERC.

A colder than normal April and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the second quarter of 2018 was 36.8% colder than the same quarter in 2017. As measured by cooling degree days, the second quarter of 2018 was 6.9% warmer than the same quarter in 2017.

These increases in margins were partially offset by:

A $20.9$4.0 million decrease in margins related to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. Tilden, who was our customer, became a settlement agreement withcustomer of UMERC once the PSCW to flow through the tax benefit of our repair-related deferred tax liabilities through reductionsnew generation solution began commercial operation on March 31, 2019.

These decreases in certain regulatory assets, which are amortized to revenues, as discussed in Note 18, Regulatory Environment.

A $2.8margins were partially offset by a $10.3 million quarter-over-quarter negativepositive 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.


Natural Gas Utility Margins


Natural gas utility margins increased $1.4decreased $0.8 million during the second quarter of 2018,2019, compared with the same quarter in 2017.2018. The most significant factor impacting the higherdecrease in natural gas utility margins was a $3.3 million increase related to higherlower sales volumes, primarily driven by a colder than normal Aprilunfavorable weather during the second quarter of 2019, compared with the same quarter in 2018, higher use per commercial and industrial customer, and customer growth. This increase in margins was partially offset by $2.1 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.2018.


Operating Income


Operating income at the utility segment decreased $41.6increased $78.1 million during the second quarter of 2018,2019, compared with the same quarter in 2017.2018. This decreaseincrease was driven by $45.4$125.2 million of higherlower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $3.8$47.1 million of higherdecrease in margins discussed above.


The significant factors impacting the decrease in operating expenses during the second quarter of 2019, compared with the same quarter in 2018, were:

A $90.6 million decrease in other operation and maintenance resulting from the adoption of the new lease guidance. As discussed in the other operation and maintenance table above, the adoption of Topic 842, effective January 1, 2019, required us to change the income statement classification of our lease payments related to the We Power leases. For the second quarter of 2019, the lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.

•
An $11.5 million decrease in operation and maintenance expenses across all of our plants, in part due to the retirements of the Pleasant Prairie power plant in April 2018 and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the second quarter of 2019. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP.

A $9.9 million decrease in operation and maintenance expense due to a 2018 item that was offset in other income, net and had no impact on net income for the quarter.

A $9.8 million net decrease in transmission expense. This was primarily driven by a $16.3 million decrease related to the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, which was offset by a corresponding decrease in margins, as previously discussed. Partially offsetting this decrease to transmission expense was a $6.5 million increase related to the flow through of tax repairs. Both changes in transmission expense are discussed in the other operation and maintenance table above.

These decreases in operating expenses were partially offset by an $8.3 million increase in depreciation and amortization, driven by capital expenditures as we continue to execute on our capital plan and additional expense recognized related to the adoption of Topic 842, as discussed in the other operation and maintenance table above.


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

A $33.8 million increase in transmission expense, with a corresponding offset in income taxes, associated with the May 2018 order from the PSCW related to the benefits associated with the Tax Legislation, as discussed in the table above.

A $10.0 million increase in transmission expenses related to the flow through of tax repairs, as discussed in the table above.

A $4.2 million increase in depreciation and amortization driven by an overall increase in utility plant in service and the implementation of an enterprise resource planning system in January 2018.

A $3.4 million increase in benefit costs.

These increases in operating expenses were partially offset by a $2.9 million decrease in expenses at our plants, primarily related to the retirement of the Pleasant Prairie power plant in April 2018 and the winding down of operations in anticipation of the retirement of the PIPP. This resulted in lower maintenance and labor costs during the second quarter of 2018. See Note 4, Property, Plant, and Equipment, for more information on the plant retirements.


Consolidated Other Income, Net
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
AFUDC – Equity $1.0
 $0.7
 $0.3
 $0.8
 $1.0
 $(0.2)
Non-service components of net periodic benefit costs 2.6
 1.2
 1.4
Other, net 14.3
 0.4
 13.9
 2.5
 13.1
 (10.6)
Other income, net $15.3
 $1.1
 $14.2
 $5.9
 $15.3
 $(9.4)


Other income, net increased $14.2decreased $9.4 million during the second quarter of 2018,2019, compared with the same quarter in 2017.2018. The increasedecrease was primarily driven by a 2018 item that was offset in other operation and maintenance expense and had no impact on net income for the timing of the recognition of returns related to certain regulatory assets and the quarter-over-quarter increase in income from the non-service components of our net periodic pension and OPEB costs. See Note 12, Employee Benefits, for more information on our benefit costs.quarter.


Consolidated Interest Expense
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Interest expense $29.2
 $29.1
 $(0.1) $119.6
 $29.2
 $(90.4)


Interest expense increased $90.4 million during the second quarter of 2019, compared with the same quarter in 2018, primarily due to the adoption of ASU 2016-02, Leases (Topic 842). Effective January 1, 2019, minimum lease payments billed from We Power to us were no longer classified within operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842. As a result of the adoption, for the three months ended June 30, 2019, $87.9 million of minimum lease payments were recorded as interest expense on finance lease liabilities. See Note 7, Leases, for more information.

Consolidated Income Tax (Benefit) ExpenseBenefit
  Three Months Ended June 30
  2018 2017 B (W)
Effective tax rate (2.8)% 36.0% 38.8%
  Three Months Ended June 30
  2019 2018 B (W)
Effective tax rate (23.7)% (2.8)% 20.9%


Our effective tax rate decreased by 38.8%20.9% when compared with the second quarter of 2017,2018, primarily due to a 24.8% effective tax ratean increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease in the effective tax rate was the impact of the Tax Legislation. See Note 9, Income Taxes and Note 18, Regulatory Environment, for more information.




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SIX MONTHS ENDED JUNE 30, 20182019


Consolidated Earnings


The following table compares our consolidated results for the six months ended June 30, 20182019 with the six months ended June 30, 2017,2018, including favorable or better, "B", and unfavorable or worse, "W", variances:
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) Change Related to Flow Through of Tax Repairs Change Related to Tax Legislation Remaining Change
B (W)		 2019 2018 B (W) Change Related to Flow Through of Tax Repairs Change Related to Adoption of New Lease Guidance (Topic 842) Remaining Change
B (W)
Operating revenues $1,797.7
 $1,827.4
 $(29.7) $(41.3) $(13.0) $24.6
 $1,752.5
 $1,797.7
 $(45.2) $(9.6) $—
 $(35.6)
Cost of sales 627.9
 622.5
 (5.4) —
 —
 (5.4) 610.7
 627.9
 17.2
 —
 4.1
 13.1
Other operation and maintenance 702.2
 651.0
 (51.2) (24.7) (33.8) 7.3
 493.2
 702.2
 209.0
 (7.1) 182.4
 33.7
Depreciation and amortization 172.2
 164.8
 (7.4) —
 —
 (7.4) 191.2
 172.2
 (19.0) —
 (10.5) (8.5)
Property and revenue taxes 54.5
 56.7
 2.2
 —
 —
 2.2
 51.9
 54.5
 2.6
 —
 —
 2.6
Operating income 240.9
 332.4
 (91.5) (66.0) (46.8) 21.3
 405.5
 240.9
 164.6
 (16.7) 176.0
 5.3
Other income, net 11.1
 4.3
 6.8
 —
 —
 6.8
 11.4
 11.1
 0.3
 —
 —
 0.3
Interest expense 58.9
 58.7
 (0.2) —
 —
 (0.2) 239.5
 58.9
 (180.6) —
 (176.0) (4.6)
Income before income taxes 193.1
 278.0
 (84.9) (66.0) (46.8) 27.9
 177.4
 193.1
 (15.7) (16.7) —
 1.0
Income tax (benefit) expense (6.1) 100.3
 106.4
 66.0
 46.8
 (6.4)
Income tax benefit (22.8) (6.1) 16.7
 16.7
 —
 —
Preferred stock dividend requirements 0.6
 0.6
 —
 —
 —
 —
 0.6
 0.6
 —
 —
 —
 —
Net income attributed to common shareholder $198.6
 $177.1
 $21.5
 $—
 $—
 $21.5
 $199.6
 $198.6
 $1.0
 $—
 $—
 $1.0


Our consolidated earnings forincreased $1.0 million during the six months ended June 30, 2018 were $198.6 million,2019, compared to $177.1 million forwith the same period in 2017.2018. The table above shows the income statement impactimpacts associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017.adoption of ASU 2016-02, Leases (Topic 842), effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder.shareholder, but did significantly impact our operating income. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.information on the flow through of tax repairs and Note 7, Leases, for more information on the adoption of Topic 842. See below for additional information on the $21.5$1.0 million increase in consolidated earnings.


Non-GAAP Financial Measures


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


We believe that electric and natural gas margins provide a more 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 six months ended June 30, 2019 and 2018 and 2017, was $240.9$405.5 million and $332.4$240.9 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 for the six months ended June 30, 2018, with the same period in 2017, including favorable or better, "B", and unfavorable or worse, "W", variances.
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Electric revenues $1,567.6
 $1,615.4
 $(47.8) $1,509.1
 $1,567.6
 $(58.5)
Fuel and purchased power 484.6
 493.9
 9.3
 457.4
 484.6
 27.2
Total electric margins 1,083.0
 1,121.5
 (38.5) 1,051.7
 1,083.0
 (31.3)
            
Natural gas revenues 230.1
 212.0
 18.1
 243.4
 230.1
 13.3
Cost of natural gas sold 143.3
 128.6
 (14.7) 153.3
 143.3
 (10.0)
Total natural gas margins 86.8
 83.4
 3.4
 90.1
 86.8
 3.3
            
Total electric and natural gas margins 1,169.8
 1,204.9
 (35.1) 1,141.8
 1,169.8
 (28.0)
            
Other operation and maintenance 702.2
 651.0
 (51.2) 493.2
 702.2
 209.0
Depreciation and amortization 172.2
 164.8
 (7.4) 191.2
 172.2
 (19.0)
Property and revenue taxes 54.5
 56.7
 2.2
 51.9
 54.5
 2.6
Operating income $240.9
 $332.4
 $(91.5) $405.5
 $240.9
 $164.6


The following table shows a breakdown of other operation and maintenance:
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Operation and maintenance not included in line items below $210.0
 $214.2
 $4.2
 $180.8
 $210.0
 $29.2
We Power (1)
 253.1
 254.7
 1.6
 70.1
 253.1
 183.0
Transmission (2)
 132.2
 134.5
 2.3
 129.3
 132.2
 2.9
Transmission expense related to the flow through of tax repairs (3)
 24.7
 —
 (24.7) 31.8
 24.7
 (7.1)
Transmission expense related to Tax Legislation (4)
 33.8
 —
 (33.8) 32.7
 33.8
 1.1
Regulatory amortizations and other pass through expenses (5)
 48.4
 47.6
 (0.8) 48.5
 48.4
 (0.1)
Total other operation and maintenance $702.2
 $651.0
 $(51.2) $493.2
 $702.2
 $209.0


(1) 
Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well aswe recognized. For the six months ended June 30, 2018, the amount also included the lease payments that arewere billed from We Power to us and then recovered in our rates. DuringWe adopted ASU 2016-02, Leases (Topic 842) effective January 1, 2019, which revised the previous guidance regarding the accounting for leases. As a result of this adoption, for the six months ended June 30, 20182019, the $182.4 million of lease expense related to the We Power leases was no longer classified within other operation and 2017, $236.7maintenance, but was instead recorded as $8.2 million and $265.0$174.2 million of depreciation and amortization and interest expense, respectively, of both lease and operating and maintenance costs were billed to or incurred by us,in accordance with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.Topic 842.


During the six months ended June 30, 2019, $76.4 million of operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset. During the six months ended June 30, 2018, $236.7 million of both lease and operating and maintenance costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(2) 
The PSCW has approvedRepresents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the six months ended June 30, 2019 and 2018, and 2017, $120.5$161.3 million and $134.7$120.5 million, respectively, of costs were billed to us by transmission providers.


(3) 
Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at ourtheir December 31, 2017 levels. See Note 18, Regulatory Environment, for more information.


(4) 
As a result ofRepresents additional transmission expense associated with the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce our transmission regulatory asset balance, our transmission expense increased during the six months ended June 30, 2018, with a corresponding offset in income taxes.balance. See Note 18, Regulatory Environment, for more information.


(5) 
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.




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The following tables provide information on sales volumes by customer class and weather statistics:
 Six Months Ended June 30 Six Months Ended June 30
 
MWh (in thousands)
 
MWh (in thousands)
Electric Sales Volumes 2018 2017 B (W) 2019 2018 B (W)
Customer Class        
Residential 3,766.9
 3,622.8
 144.1
 3,671.5
 3,766.9
 (95.4)
Small commercial and industrial 4,346.6
 4,301.8
 44.8
 4,211.7
 4,346.6
 (134.9)
Large commercial and industrial 4,159.5
 4,077.7
 81.8
 3,713.0
 4,159.5
 (446.5)
Other 69.6
 72.2
 (2.6) 69.5
 69.6
 (0.1)
Total retail 12,342.6
 12,074.5
 268.1
 11,665.7
 12,342.6
 (676.9)
Wholesale 820.1
 844.3
 (24.2) 743.2
 820.1
 (76.9)
Resale 2,751.7
 3,197.0
 (445.3) 2,698.8
 2,751.7
 (52.9)
Total sales in MWh 15,914.4
 16,115.8
 (201.4) 15,107.7
 15,914.4
 (806.7)


 Six Months Ended June 30 Six Months Ended June 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2018 2017 B (W) 2019 2018 B (W)
Customer Class        
Residential 236.4
 202.3
 34.1
 252.6
 236.4
 16.2
Commercial and industrial 131.1
 113.5
 17.6
 135.9
 131.1
 4.8
Total retail 367.5
 315.8
 51.7
 388.5
 367.5
 21.0
Transport 172.8
 160.5
 12.3
 181.0
 172.8
 8.2
Total sales in therms 540.3
 476.3
 64.0
 569.5
 540.3
 29.2


 Six Months Ended June 30 Six Months Ended June 30
 Degree Days Degree Days
Weather * 2018 2017 B(W) 2019 2018 B (W)
Heating (4,169 normal) 4,248
 3,597
 18.1%
Heating (4,192 normal) 4,456
 4,248
 4.9 %
Cooling (166 normal) 217
 203
 6.9% 76
 217
 (65.0)%


*Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.


Electric Utility Margins


Electric utility margins decreased $38.5$31.3 million during the six months ended June 30, 2018,2019, compared with the same period in 2017.2018. The significant factors impacting the lower electric utility margins were:


A $41.3
•
A $19.6 million decrease in margins related to lower retail sales volumes during the six months endedJune 30, 2019, primarily driven by unfavorable weather during the second quarter of 2019. As measured by cooling degree days, the six months endedJune 30, 2019, were 65.0% cooler than the same period in 2018.

•
A $9.6 million decrease in margins associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. See Note 18, Regulatory Environment, for more information.

Natural Gas Utility Margins

Natural gas utility margins increased $3.3 million during the six months ended June 30, 2019, compared with the PSCW to flow throughsame period in 2018. The most significant factor impacting the tax benefit of our repair-related deferred tax liabilities through reductions in certain regulatory assets, which are amortized to revenues, as discussed in Note 18, Regulatory Environment.

A $7.8 million decrease inhigher natural gas utility margins related to amounts expected to be refunded to customers through refunds, bill credits, or reductions in other regulatory assets,was higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per retail customer during the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

A $3.1 million decrease in wholesale margins driven by reduced capacity rates reflecting the Tax Legislation.

A $2.5 million period-over-period negative impact from collections of fuel and purchased power costssix months ended June 30, 2019, compared with costs approvedthe same period 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.2018.




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These decreases in margins were partially offset by an $18.7 million increase related to higher retail sales volumes duringOperating Income

Operating income at the six months ended June 30, 2018, primarily driven by favorable weather and higher overall use per retail customer. Cooler winter weather and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the six months ended June 30, 2018, were 18.1% colder than the same period in 2017. As measured by cooling degree days, the six months ended June 30, 2018, were 6.9% warmer than the same period in 2017.

Natural Gas Utility Margins

Natural gas utility marginssegment increased $3.4$164.6 million during the six months ended June 30, 2018,2019, compared with the same period in 2017.2018. The most significant factor impacting the higher natural gas utility margins was an $8.5 million increase related to higher sales volumes, primarily driven by colder winter weather, higher use per commercial and industrial customer, and customer growth. This increase in margins was partially offset by $5.2 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.

Operating Income

Operating income at the utility segment decreased $91.5 million during the six months ended June 30, 2018, compared with the same period in 2017. The decrease was driven by $56.4$192.6 million of higherlower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes) and, partially offset by the $35.1$28.0 million net decrease in margins discussed above.


The significant factors impacting the increasedecrease in operating expenses during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, were:


•
A $182.4 million decrease in other operation and maintenance resulting from the adoption of the new lease guidance. As discussed in the other operation and maintenance table above, the adoption of Topic 842, effective January 1, 2019, required us to change the income statement classification of our lease payments related to the We Power leases. For the six months endedJune 30, 2019, the lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.

•
A $23.1 million decrease in operation and maintenance expenses across all of our plants, in part due to the retirements of the Pleasant Prairie power plant in April 2018 and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the six months endedJune 30, 2019. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP.

•
A $9.9 million decrease in operation and maintenance expense due to a 2018 item that was offset in other income, net and had no impact on net income for six months endedJune 30, 2019.

These decreases in operating expenses were partially offset by:

A $33.8$19.0 million increase in transmissiondepreciation and amortization, driven by capital expenditures as we continue to execute on our capital plan and additional expense with a corresponding offset in income taxes, associated with the May 2018 order from the PSCWrecognized related to the benefits associated with the Tax Legislation,adoption of Topic 842, as discussed in the other operation and maintenance table above.


A $24.7$14.8 million increase in benefit costs, primarily related to deferred compensation.

A $7.1 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above.

A $7.4 million increase in depreciation and amortization driven by an overall increase in utility plant in service and the implementation of an enterprise resource planning system in January 2018.

These increases in operating expenses were partially offset by:

A $6.9 million decrease in expenses at our plants, primarily related to the retirement of the Pleasant Prairie power plant in April 2018 and the winding down of operations in anticipation of the retirement of the PIPP. This resulted in lower maintenance and labor costs during the six months ended June 30, 2018. See Note 4, Property, Plant, and Equipment, for more information on the plant retirements.

A $3.1 million net decrease in transmission expenses, lease costs from We Power, and regulatory amortizations and other pass-through expenses included in the table above. The lower transmission expenses and We Power lease costs were driven by the Tax Legislation.


Consolidated Other Income, Net
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
AFUDC – Equity $2.0
 $1.4
 $0.6
 $1.4
 $2.0
 $(0.6)
Non-service components of net periodic benefit costs 4.3
 2.9
 1.4
Other 9.1
 2.9
 6.2
 5.7
 6.2
 (0.5)
Other income, net $11.1
 $4.3
 $6.8
 $11.4
 $11.1
 $0.3


Other income, net
Consolidated Interest Expense
  Six Months Ended June 30
(in millions) 2019 2018 B (W)
Interest expense $239.5
 $58.9
 $(180.6)

Interest expense increased $6.8$180.6 million during the six months ended June 30, 2018,2019, compared with the same period in 2017, driven by2018, primarily due to the period-over-period increaseadoption of ASU 2016-02, Leases (Topic 842). Effective January 1, 2019, minimum lease payments billed from We Power to us were no longer classified within operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in income fromaccordance with Topic 842. As a result of the non-service componentsadoption, for the six months ended June 30, 2019, $176.0 million of our net periodic pension and OPEB costs.minimum lease payments were recorded as interest expense on finance lease liabilities. See Note 12, Employee Benefits,7, Leases, for more information on our benefit costs.information.



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Consolidated Interest Expense
  Six Months Ended June 30
(in millions) 2018 2017 B (W)
Interest expense $58.9
 $58.7
 $(0.2)


Consolidated Income Tax (Benefit) ExpenseBenefit
  Six Months Ended June 30
  2018 2017 B (W)
Effective tax rate (3.2)% 36.1% 39.3%
  Six Months Ended June 30
  2019 2018 B (W)
Effective tax rate (12.9)% (3.2)% 9.7%


Our effective tax rate decreased by 39.3%9.7% when compared with the six months ended June 30, 2017,2018, primarily due to a 24.9% effective tax ratean increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease in the effective tax rate was the impact of the Tax Legislation. See Note 9, Income Taxes, and Note 18, Regulatory Environment, for more information.


We expect our 20182019 annual effective tax rate to be between (5)(18.0)% and (4)(17.0)%, which includes an estimated 27%39.5% effective tax rate benefit fromdue to the flow through of tax repairs.repairs in connection with the Wisconsin rate settlement. Excluding the impact of the tax repairs, the expected 2019 effective tax rate would be between 21.5% and 22.5%.


LIQUIDITY AND CAPITAL RESOURCES


Cash Flows


The following table summarizes our cash flows during the six months ended June 30:
(in millions) 2018 2017 
Change in 2018
Over 2017
 2019 2018 Change in 2019 Over 2018
Cash provided by (used in):            
Operating activities $531.6
 $359.9
 $171.7
 $435.4
 $531.6
 $(96.2)
Investing activities (331.1) (225.7) (105.4) (225.3) (331.1) 105.8
Financing activities (211.7) (148.0) (63.7) (225.7) (211.7) (14.0)


Operating Activities


Net cash provided by operating activities increased $171.7decreased $96.2 million during the six months ended June 30, 2018,2019, compared with the same period in 2017, driven by:

A $94.32018. Our adoption of ASU 2016-02, Leases (Topic 842), on January 1, 2019 did not have a significant impact on our cash flows from operating activities as the $181.3 million increase in cash from lower paymentspaid for other operation and maintenance costs. During the six months ended June 30, 2018, our payments were lower for accounts payable to related parties as well as for plant maintenance and labor costs. In addition, our payments related to transmission and our lease payments to We Power decreased asinterest was primarily offset by a result of the Tax Legislation.

A $55.2 million increase in cash related to acorresponding decrease in cash paid for income taxes during the six months ended June 30, 2018, compared with the same periodother operation and maintenance. As a result, this classification change is not reflected in 2017. This increaseour discussion below. See Note 7, Leases, for more information. The $96.2 million decrease in net cash provided by operating activities was primarily the result of the utilization of certain tax benefit carryforwards.
driven by:


•
A $45.1 million decrease in cash from higher payments for other operation and maintenance expenses. During the six months ended June 30, 2019, our payments were higher for accounts payable, transmission, and benefits, compared with the same period in 2018.

•
A $36.2 million decrease in cash primarily related to the impact of the Tax Legislation, which resulted in lower overall collections from customers during the six months ended June 30, 2019, compared with the same period in 2018.
A $33.1 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during the six months endedJune 30, 2018, compared with the same period in 2017.
•
A $17.9 million decrease in cash due to higher collateral requirements during the six months ended June 30, 2019, compared with the same period in 2018, driven by an increase in our derivative liabilities.


These increasesdecreases in net cash provided by operating activities were partially offset by a $21.9$16.6 million decreaseincrease in cash resulting from higherprimarily related to lower payments for fuel and purchased power during the six months ended June 30, 2018,2019, compared with the same period in 2017, for natural gas we purchased at2018, due to the endretirements of 2017the Pleasant Prairie power plant in April 2018 and during the six months ended June 30, 2018, to meet the requirements of our customers during the colder winter weather. The average per-unit cost of natural gas increased 28.4% during the six months ended June 30, 2018, compared with the same periodPIPP in 2017.March 2019.




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Investing Activities


Net cash used in investing activities increased $105.4decreased $105.8 million during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, driven by:


•
A $56.6 million decrease in cash paid for capital expenditures during the six months ended June 30, 2019, compared with the same period in 2018, which is discussed in more detail below.

•
A payment of $50.1 million to WEC Business Services LLC during the six months ended June 30, 2018 for the transfer of an enterprise resource planning system and other software to us.
A payment of $50.1 million to affiliates during the six months ended June 30, 2018, related to transfers of an enterprise resource planning system and other software. There were no similar transfers in 2017.

A $40.1 million increase in cash paid for capital expenditures during the six months ended June 30, 2018, compared with the same period in 2017, which is discussed in more detail below.

A $21.4 million decrease in the proceeds received from the sale of assets during the six months ended June 30, 2018, compared with the same period in 2017. See Note 2, Disposition, for more information.


Capital Expenditures


Capital expenditures for the six months ended June 30 were as follows:
(in millions) 2018 2017 
Change in 2018
Over 2017
 2019 2018 Change in 2019 Over 2018
Capital expenditures $287.0
 $246.9
 $40.1
 $230.4
 $287.0
 $(56.6)


The increasedecrease in cash paid for capital expenditures during the six months ended June 30, 2019, compared with the same period in 2018, was primarily driven by upgrades ofto our natural gas and electric distribution systems, including main replacementsystem, projects at the OCPP, and various software projects.the implementation of an enterprise resource planning system during the six months ended June 30, 2018. These decreases in cash paid for capital expenditures were partially offset by increased capital expenditures for an information technology project created to improve our billing, call center, and credit collection functions during the six months ended June 30, 2019.


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


Financing Activities


Net cash used in financing activities increased $63.7$14.0 million during the six months ended June 30, 2018,2019, compared with the same period in 2017, primarily2018, driven by:


•
A $226.3 million net decrease in cash due to $95.4 million of net repayments of commercial paper during the six months ended June 30, 2019, compared with $130.9 million of net borrowings of commercial paper during the same period in 2018.

•
A $90.0 million decrease in cash due to higher dividends paid to our parent during the six months ended June 30, 2019, compared with the same period in 2018, to balance our capital structure.

•
A $24.4 million decrease in cash related to a change in the cash flow classification of our principal payments for finance lease obligations due to our adoption of Topic 842. Under Topic 842, our principal payments for finance lease obligations were no longer classified as cash flows from operating activities during the six months ended June 30, 2019 but were instead classified as cash flows from financing activities. See Note 7, Leases, for more information on Topic 842 and our finance lease obligations.

A $250.0 million repayment of long-term debt during the six months ended June 30, 2018. A portion of this repayment was financed with a net increaseThese decreases in cash of $214.9 million from commercial paper, which resulted from $130.9 million of net borrowings during the six months ended June 30, 2018, compared with $84.0 million of net repayments during the same period in 2017. We did not repay any long-term debt during the same period in 2017.

A $47.0 million decrease in equity contributions received from our parent during the six months ended June 30, 2018, compared with the same period in 2017.

These increases in net cash used in financing activities were partially offset by an $18.5 million repayment of our subsidiary's note to our parent during the six months ended June 30, 2017.by:


•
A $250.0 million increase in cash related to a repayment of long-term debt during the six months ended June 30, 2018.

•
A $77.0 million increase in cash related to higher equity contributions received from our parent during the six months ended June 30, 2019, compared with the same period in 2018, to balance our capital structure.

Significant Financing Activities

For more information on our short-term financing activities, see Note 6, Short-Term Debt and Lines of Credit, and Note 7, Long-Term Debt.Credit.



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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

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currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets, and internally generated cash.


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


Working Capital


As of June 30, 2018,2019, our current liabilities exceeded our current assets by $87.1$13.6 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt.debt, if necessary.


Credit Rating Risk


We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.


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


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


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



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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, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions)    
2018 $598.5
2019 552.5
 $636.7
2020 807.5
 876.3
2021 979.0
Total $1,958.5
 $2,492.0


The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI)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.


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Additionally, as part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar. We have partnered with an unaffiliated utility to acquire an ownership interest in Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin. We will own 100 MW of the output of the project. Our share of the cost of this project is estimated to be $130 million. Commercial operation is targeted for the end of 2021. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.


Off-Balance Sheet Arrangements


We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 6, Short-Term Debt and Lines of Credit, Note 12, Guarantees, and Note 14,15, Variable Interest Entities.


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 20172018 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the six months ended June 30, 2019.


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 20172018 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.


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 2018 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.


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Regulatory Recovery

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by the PSCW. Recovery of the deferred costs in future rates is subject to the review and approval by the PSCW. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs 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.

Due to the Tax Legislation signed into law in December 2017, we remeasured our deferred taxes and recorded a tax benefit of $1,102 million. We have been returning the amortization of this tax benefit to ratepayers through bill credits and reductions to other regulatory assets, which we expect to continue.

See Note 18, Regulatory Environment, for more information regarding our pending rate proceeding and previously issued rate order.

Environmental Matters


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


Other Matters


Tax Cuts and Jobs Act of 2017


In December 2017, the Tax Legislation was signed into law. As a result,In May 2018, the PSCW issued a written order in May 2018 regarding how we shouldto refund thecertain tax savings from the Tax Legislation to our ratepayers in Wisconsin. In addition, in May 2018, the MPSCMichigan Public Service Commission approved a settlement with our oneTilden, who owns the iron ore mine located in the Upper Peninsula of Michigan we provided retail electric customer in Michiganservice to prior to April 1, 2019, that addressesaddressed all base rate impacts of the Tax Legislation. We expect that the various remaining impacts of the Tax Legislation on our Wisconsin operations will be addressed in our pending rate case we filed with the PSCW in March 2019. See Note 18, Regulatory Environment, for more information on our pending rate case. We are also working with the FERC to modify our formula rate tariffs for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariffs in 2019. See Note 18, Regulatory Environment, for more information.




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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


There have been no material changes related to market risk from the disclosures presented in our 20172018 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 10, Fair Value Measurements, and Note 11, Derivative Instruments, and Note 12, Guarantees, in this report for information concerning our market risk exposures.



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ITEM 4. CONTROLS AND PROCEDURES


Disclosure Controls and Procedures


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


Changes in Internal Control Over Financial Reporting


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

With the exception of the ERP system implementation described above, thereThere were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the second quarter of 20182019 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 20172018 Annual Report on Form 10-K. See Note 16, Commitments and Contingencies, and Note 18, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us.


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

Presque Isle Power Plant Matter

In March 2018, the EPA issued a Finding of Violation to us regarding alleged violations of mercury emission limits for PIPP Units 5, 6, 8, and 9, as well as failure to conduct mercury tests on our low emitting electric utility generating units once every 12 months. We are cooperating with the EPA, and we do not expect this matter to have a material impact on our financial statements.


ITEM 1A. RISK FACTORS


There were no material changes from the risk factors presented in our 2018 Annual Report on Form 10-K for the year ended December 31, 2017.10-K. See Item 1A. Risk Factors in Part I of our 2017 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.



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ITEM 6. EXHIBITS
Number Exhibit
12Statements re Computation of Ratios
12.1
Ratio of Earnings to Fixed Charges
31 Rule 13a-14(a) / 15d-14(a) Certifications
    
  
31.1
Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
  
31.2
Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
32 Section 1350 Certifications
    
  
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
  
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
101 Interactive Data 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 ELECTRIC POWER COMPANY
  (Registrant)
   
  /s/ WILLIAM J. GUC
Date:August 3, 20186, 2019William J. Guc
  Vice President and Controller
   
  (Duly Authorized Officer and Chief Accounting Officer)




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