false--12-31Q22019000078332586366000008705000000149200000143300000092000000.55250.590.010.013250000003250000003155231923154358206800000399000001500000088000000800000043800000161000009990000017000003800000000090000013000000.00501000.33
 

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 Endedquarterly 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;
Address; and Telephone Number
 
IRS Employer
Identification No.
image0a11.jpg
001-09057 WEC ENERGY GROUP, INC. 39-1391525
(A Wisconsin Corporation)
231 West Michigan Street
P. O. Box 1331
Milwaukee, WI53201
(414) 221-2345


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class  (A Wisconsin Corporation)Trading Symbol(s) Name of Each Exchange on Which Registered
Common Stock, $.01 Par Value 231 West Michigan StreetWEC 
P.O. Box 1331
Milwaukee, WI 53201
(414) 221-2345New York Stock Exchange


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 [X]☒ Accelerated filer [  ]☐
 Non-accelerated filer [  ] (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:date (June 30, 2019):


Common Stock, $.01 Par Value,
315,533,448 315,435,820 shares outstanding at
June 30, 2018
 

WEC ENERGY GROUP, INC.
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 Statements of Comprehensive Income
 
4
 
Condensed Consolidated Balance Sheets
 
5
 
Condensed Consolidated Statements of Cash Flows
 
6
 
Condensed Consolidated Statements of Equity
7
Notes to Condensed Consolidated Financial Statements
 
79
   Page 
 
Note 1
General Information
79
 
 
Note 2
Acquisitions
79
 
 
Note 3
Disposition
810
 
 
Note 4
Operating Revenues
810
 
 
Note 5
Property, Plant,Regulatory Assets and Equipment
13
Note 6
Common EquityLiabilities
14
 
 
Note 76
Short-Term DebtProperty, Plant, and Lines of CreditEquipment
15
 
 
Note 87
Long-Term Debt
15
Note 9
Materials, Supplies, and InventoriesCommon Equity
16
 
 
Note 108
Income TaxesShort-Term Debt and Lines of Credit
16
 
 
Note 119
Fair Value MeasurementsLong-Term Debt
1617
 
 
Note 1210
Derivative InstrumentsLeases
1817
 
 
Note 1311
GuaranteesMaterials, Supplies, and Inventories
20
 
 
Note 1412
Employee BenefitsIncome Taxes
21
 
 
Note 1513
GoodwillFair Value Measurements
2221
 
 
Note 1614
Investment in Transmission AffiliatesDerivative Instruments
2223
 
 
Note 1715
Segment Information
24
Note 18
Variable Interest EntitiesGuarantees
26
 
 
Note 1916
Commitments and ContingenciesEmployee Benefits
26
Note 17
Goodwill
27
 
 
Note 2018
Supplemental Cash Flow InformationInvestment in Transmission Affiliates
3027
 
 
Note 2119
Regulatory EnvironmentSegment Information
29
Note 20
Variable Interest Entities
31
 
 
Note 2221
New Accounting PronouncementsCommitments and Contingencies
3432
Note 22
Supplemental Cash Flow Information
35
Note 23
Regulatory Environment
36
Note 24
New Accounting Pronouncements
38
 
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
3540
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
6168
ITEM 4.
CONTROLS AND PROCEDURES
 
6268
PART II.
OTHER INFORMATION
 
6369
ITEM 1.
LEGAL PROCEEDINGS
 
6369
ITEM 1A.
RISK FACTORS
 
6469
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
6470
ITEM 6.
EXHIBITS
 
6570
SIGNATURE
  
6671




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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
ATC Holdco ATC Holdco LLC
ATC HoldingATC Holding LLC
Bishop Hill IIIBishop Hill Energy III LLC
Bluewater Bluewater Natural Gas Holding, LLC
BostcoCoyote Ridge BostcoCoyote Ridge Wind, LLC
Integrys Integrys Holding, Inc.
MERC Minnesota Energy Resources Corporation
MGU Michigan Gas Utilities Corporation
NSG North Shore Gas Company
PDL WPS Power Development, LLC
PGL The Peoples Gas Light and Coke Company
UMERC Upper Michigan Energy Resources Corporation
WBSUpstream WEC Business ServicesUpstream Wind Energy LLC
WE Wisconsin Electric Power Company
We Power W.E. Power, LLC
WG Wisconsin Gas LLC
WPS Wisconsin Public Service Corporation
   
Federal and State Regulatory Agencies
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
ICC Illinois Commerce Commission
IEPAIllinois Environmental Protection Agency
IRSUnited States Internal Revenue Service
MDEQ Michigan Department of Environmental Quality
MPSC Michigan Public Service Commission
MPUC Minnesota Public Utilities 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
LIFO Last-In, First-Out
OPEB Other Postretirement Employee Benefits
   
Environmental Terms
ACEAffordable Clean Energy
BATWBottom Ash Transport Water
BSERBest System of Emission Reduction
BTABest Technology Available
CAA Clean Air Act
CO2
 Carbon Dioxide
CPPELG Clean Power PlanSteam Electric Effluent Limitation Guidelines
FGDFlue Gas Desulfurization

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Table of Contents

GHG Greenhouse Gas
MATSMercury and Air Toxics Standards
NOV Notice of Violation
WPDESRTR Wisconsin Pollutant Discharge Elimination SystemRisk and Technology Review
VNViolation Notice
   
Measurements
Dth Dekatherm
MW Megawatt
MWh Megawatt-hour
   

06/30/2018 Form 10-QiiWEC Energy Group, Inc.
Table of Contents

Other Terms and Abbreviations
2006 Junior NotesIntegrys's 2006 Junior Subordinated Notes Due 2066
2007 Junior Notes WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067
AGAttorney General
ALJ Administrative Law Judge
D.C. Circuit Court of AppealsAMI United States Court of Appeals for the District of Columbia CircuitAdvanced Metering Infrastructure
Badger Hollow IBadger Hollow Solar Farm I
Badger Hollow IIBadger Hollow Solar Farm II
ERGS Elm Road Generating Station
Exchange Act Securities Exchange Act of 1934, as amended
FTRsFTR Financial Transmission Rights
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
PIPP Presque Isle Power Plant
QIP Qualifying Infrastructure Plant
ROE Return on Equity
SMP Natural Gas System Modernization Program
SMRP System Modernization and Reliability Project
Supreme CourtSSR United States Supreme CourtSystem Support Resource
Tax Legislation Tax Cuts and Jobs Act of 2017
VITATilden Variable Income Tax Adjustment RiderTilden Mining Company




06/30/20182019 Form 10-QiiiWEC Energy Group, Inc.
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, dividend payout ratios, 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 itsany further impact on our orand our subsidiaries’ 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 our generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;


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


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

06/30/2019 Form 10-Q1WEC Energy Group, Inc.
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-Q1WEC Energy Group, Inc.
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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, us, or any of our subsidiaries;


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


Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;


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 financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and Duke-American Transmission Company to obtain the required approvals for their transmission projects;


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 the Integrys acquisition;
 
The risk associated with the values of goodwill and other intangible assets and their possible impairment;


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, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;


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 our enterprise systems;


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-Q2WEC Energy Group, Inc.
Table of Contents


PART I. FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS


WEC ENERGY GROUP, INC.


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 $1,672.5
 $1,631.5
 $3,959.0
 $3,936.0
 $1,590.2
 $1,672.5
 $3,967.6
 $3,959.0
                
Operating expenses                
Cost of sales 547.7
 541.8
 1,519.8
 1,482.9
 491.9
 547.7
 1,501.5
 1,519.8
Other operation and maintenance 537.7
 479.8
 1,049.6
 984.3
 503.6
 537.7
 1,054.2
 1,049.6
Depreciation and amortization 206.7
 197.7
 415.3
 392.3
 229.9
 206.7
 456.3
 415.3
Property and revenue taxes 49.6
 50.0
 98.4
 99.6
 50.2
 49.6
 98.2
 98.4
Total operating expenses 1,341.7
 1,269.3
 3,083.1
 2,959.1
 1,275.6
 1,341.7
 3,110.2
 3,083.1
                
Operating income 330.8
 362.2
 875.9
 976.9
 314.6
 330.8
 857.4
 875.9
                
Equity in earnings of transmission affiliates 28.7
 41.8
 61.5
 83.7
 36.9
 28.7
 73.0
 61.5
Other income, net 31.4
 13.1
 38.9
 31.4
 23.6
 31.4
 54.5
 38.9
Interest expense 108.5
 101.9
 215.2
 206.6
 124.1
 108.5
 248.5
 215.2
Other expense (48.4) (47.0) (114.8) (91.5) (63.6) (48.4) (121.0) (114.8)
                
Income before income taxes 282.4
 315.2
 761.1
 885.4
 251.0
 282.4
 736.4
 761.1
Income tax expense 51.1

115.8
 139.4
 329.1
 15.2

51.1
 80.2
 139.4
Net income 231.3

199.4
 621.7
 556.3
 235.8

231.3
 656.2
 621.7
                
Preferred stock dividends of subsidiary 0.3

0.3
 0.6
 0.6
 0.3

0.3
 0.6
 0.6
Net loss attributed to noncontrolling interests 0.2
 —
 0.2
 —
Net income attributed to common shareholders $231.0
 $199.1
 $621.1
 $555.7
 $235.7
 $231.0
 $655.8
 $621.1
                
Earnings per share                
Basic $0.73
 $0.63
 $1.97
 $1.76
 $0.75
 $0.73
 $2.08
 $1.97
Diluted $0.73
 $0.63
 $1.96
 $1.75
 $0.74
 $0.73
 $2.07
 $1.96
                
Weighted average common shares outstanding                
Basic 315.5
 315.6
 315.5
 315.6
 315.4
 315.5
 315.4
 315.5
Diluted 316.9
 317.4
 316.9
 317.4
 316.7
 316.9
 316.7
 316.9
        
Dividends per share of common stock $0.5525
 $0.5200
 $1.1050
 $1.0400


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




06/30/20182019 Form 10-Q3WEC Energy Group, Inc.
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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Three Months Ended Six Months Ended Three Months Ended Six Months Ended
 June 30 June 30 June 30 June 30
(in millions) 2018 2017 2018 2017 2019 2018 2019 2018
Net income $231.3
 $199.4
 $621.7
 $556.3
 $235.8
 $231.3
 $656.2
 $621.7
                
Other comprehensive (loss) income, net of tax        
Other comprehensive loss, net of tax        
Derivatives accounted for as cash flow hedges                
Reclassification of gains to net income, net of tax (0.4) (0.3) (0.6) (0.6)
Derivative losses, net of tax benefit of $(0.9), $0, $(1.3), and $0, respectively (2.3) —
 (3.5) —
Reclassification of net gains to net income, net of tax (0.3) (0.4) (0.6) (0.6)
Cash flow hedges, net (2.6) (0.4) (4.1) (0.6)
                
Defined benefit plans                
Amortization of pension and OPEB (credits) costs included in net periodic benefit cost, net of tax (1.7) 0.1
 0.2
 0.2
Amortization of pension and OPEB costs (credits) included in net periodic benefit cost, net of tax —
 (1.7) 0.1
 0.2
                
Other comprehensive loss, net of tax (2.1) (0.2) (0.4) (0.4) (2.6) (2.1) (4.0) (0.4)
                
Comprehensive income 229.2
 199.2
 621.3
 555.9
 233.2
 229.2
 652.2
 621.3
                
Preferred stock dividends of subsidiary 0.3
 0.3
 0.6
 0.6
 0.3
 0.3
 0.6
 0.6
Comprehensive loss attributed to noncontrolling interests 0.2
 —
 0.2
 —
Comprehensive income attributed to common shareholders $228.9
 $198.9
 $620.7
 $555.3
 $233.1
 $228.9
 $651.8
 $620.7


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




06/30/20182019 Form 10-Q4WEC Energy Group, Inc.
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WEC ENERGY GROUP, INC.


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 $29.8
 $38.9
 $37.9
 $84.5
Accounts receivable and unbilled revenues, net of reserves of $157.5 and $143.2, respectively 1,086.1
 1,350.7
Accounts receivable and unbilled revenues, net of reserves of $143.3 and $149.2, respectively 1,004.3
 1,280.9
Materials, supplies, and inventories 466.6
 539.0
 461.4
 548.2
Prepayments 178.6
 210.0
 254.8
 256.8
Other 49.3
 74.9
 80.3
 77.2
Current assets 1,810.4
 2,213.5
 1,838.7
 2,247.6
        
Long-term assets        
Property, plant, and equipment, net of accumulated depreciation of $8,512.1 and $8,618.5, respectively 21,078.4
 21,347.0
Property, plant, and equipment, net of accumulated depreciation and amortization of $8,705.0 and $8,636.6, respectively 22,535.8
 22,000.9
Regulatory assets 3,645.9
 2,803.2
 4,007.0
 3,805.1
Equity investment in transmission affiliates 1,596.6
 1,553.4
 1,696.5
 1,665.3
Goodwill 3,052.8
 3,053.5
 3,052.8
 3,052.8
Other 753.5
 619.9
 803.5
 704.1
Long-term assets 30,127.2
 29,377.0
 32,095.6
 31,228.2
Total assets $31,937.6
 $31,590.5
 $33,934.3
 $33,475.8
        
Liabilities and Equity        
Current liabilities        
Short-term debt $1,370.0
 $1,444.6
 $1,262.7
 $1,440.1
Current portion of long-term debt 293.5
 842.1
 766.5
 365.0
Accounts payable 681.0
 859.9
 715.6
 876.4
Accrued payroll and benefits 130.7
 169.1
 159.3
 185.4
Accrued taxes 213.5
 178.5
Other 364.5
 375.1
 457.9
 464.8
Current liabilities 3,053.2
 3,869.3
 3,362.0
 3,331.7
        
Long-term liabilities        
Long-term debt 9,209.3
 8,746.6
 9,921.0
 9,994.0
Deferred income taxes 3,117.1
 2,999.8
 3,598.1
 3,388.1
Deferred revenue, net 531.8
 543.3
 508.7
 520.4
Regulatory liabilities 3,959.2
 3,718.6
 4,243.6
 4,251.6
Environmental remediation liabilities 617.2
 617.4
 631.8
 616.4
Pension and OPEB obligations 490.4
 397.4
 414.0
 422.8
Other 1,203.2
 1,206.3
 1,106.8
 1,108.1
Long-term liabilities 19,128.2
 18,229.4
 20,424.0
 20,301.4
        
Commitments and contingencies (Note 19) 
 
Commitments and contingencies (Note 21) 

 

        
Common shareholders' equity        
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,533,448 and 315,574,624 shares outstanding, respectively 3.2
 3.2
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,435,820 and 315,523,192 shares outstanding, respectively 3.2
 3.2
Additional paid in capital 4,271.0
 4,278.5
 4,197.9
 4,250.1
Retained earnings 5,449.1
 5,176.8
 5,821.7
 5,538.2
Accumulated other comprehensive income 2.5
 2.9
Accumulated other comprehensive loss (6.6) (2.6)
Common shareholders' equity 9,725.8
 9,461.4
 10,016.2
 9,788.9
        
Preferred stock of subsidiary 30.4
 30.4
 30.4
 30.4
Noncontrolling interests 101.7
 23.4
Total liabilities and equity $31,937.6
 $31,590.5
 $33,934.3
 $33,475.8


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


06/30/20182019 Form 10-Q5WEC Energy Group, Inc.
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WEC ENERGY GROUP, INC.


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 $621.7

$556.3
 $656.2

$621.7
Reconciliation to cash provided by operating activities        
Depreciation and amortization 415.3

392.3
 456.3

415.3
Deferred income taxes and investment tax credits, net 31.7

274.6
 96.1

31.7
Contributions and payments related to pension and OPEB plans (9.7) (111.5) (8.3) (9.7)
Equity income in transmission affiliates, net of distributions 4.9
 (14.5) (9.4) 4.9
Change in –        
Accounts receivable and unbilled revenues 235.5
 247.3
 267.9
 235.5
Materials, supplies, and inventories 72.6
 77.9
 87.0
 72.6
Other current assets 78.8
 14.5
 20.0
 78.8
Accounts payable (85.0) (114.0) (222.7) (85.0)
Other current liabilities 0.1
 18.3
 (55.1) 0.1
Other, net 147.5
 (74.3) 3.2
 147.5
Net cash provided by operating activities 1,513.4
 1,266.9
 1,291.2
 1,513.4
        
Investing Activities        
Capital expenditures (915.5)
(790.0) (855.2)
(915.5)
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2 (268.2) —
Acquisition of Forward Wind Energy Center (77.1) —
 —
 (77.1)
Acquisition of Bluewater —
 (226.0)
Capital contributions to transmission affiliates (32.4)
(50.5) (21.9)
(32.4)
Proceeds from the sale of assets and businesses 7.9

20.7
 30.0

7.9
Proceeds from the sale of investments held in rabbi trust 16.5
 8.6
 0.1
 16.5
Reimbursement for ATC's construction costs 32.4
 —
Other, net 3.8

1.0
 16.4

3.8
Net cash used in investing activities (996.8) (1,036.2) (1,066.4) (996.8)
        
Financing Activities        
Exercise of stock options 5.1
 15.6
 50.1
 5.1
Purchase of common stock (19.8) (39.7) (106.3) (19.8)
Dividends paid on common stock (348.7)
(328.3) (372.3)
(348.7)
Issuance of long-term debt 600.0
 210.0
 350.0
 600.0
Retirement of long-term debt (681.4) (14.6) (17.3) (681.4)
Change in short-term debt (74.6) (85.4) (177.4) (74.6)
Other, net (3.8) (2.7) (7.0) (3.8)
Net cash used in financing activities (523.2) (245.1) (280.2) (523.2)
        
Net change in cash, cash equivalents, and restricted cash (6.6) (14.4) (55.4) (6.6)
Cash, cash equivalents, and restricted cash at beginning of period 58.6

72.7
 146.1

58.6
Cash, cash equivalents, and restricted cash at end of period $52.0
 $58.3
 $90.7
 $52.0


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




06/30/20182019 Form 10-Q6WEC Energy Group, Inc.
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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)        
                 
  WEC Energy Group Common Shareholders' Equity      
(in millions, except per share amounts) Common Stock Additional Paid In Capital Retained Earnings Accumulated Other Comprehensive Loss Total Common Shareholders' Equity Preferred Stock of Subsidiary Non-controlling Interests Total Equity
Balance at December 31, 2018 $3.2
 $4,250.1
 $5,538.2
 $(2.6) $9,788.9
 $30.4
 $23.4
 $9,842.7
Net income attributed to common shareholders —
 —
 420.1
 —
 420.1
 —
 —
 420.1
Other comprehensive loss —
 —
 —
 (1.4) (1.4) —
 —
 (1.4)
Common stock dividends of $0.59 per share —
 —
 (186.2) —
 (186.2) —
 —
 (186.2)
Exercise of stock options —
 32.6
 —
 —
 32.6
 —
 —
 32.6
Purchase of common stock —
 (70.7) —
 —
 (70.7) —
 —
 (70.7)
Acquisition of a noncontrolling interest —
 —
 —
 —
 —
 —
 69.0
 69.0
Capital contributions from noncontrolling interest —
 —
 —
 —
 —
 —
 4.8
 4.8
Stock-based compensation and other —
 1.2
 —
 —
 1.2
 —
 —
 1.2
Balance at March 31, 2019 $3.2
 $4,213.2
 $5,772.1
 $(4.0) $9,984.5
 $30.4
 $97.2
 $10,112.1
Net income attributed to common shareholders —
 —
 235.7
 —
 235.7
 —
 —
 235.7
Other comprehensive loss —
 —
 —
 (2.6) (2.6) —
 —
 (2.6)
Common stock dividends of $0.59 per share —
 —
 (186.1) —
 (186.1) —
 —
 (186.1)
Exercise of stock options —
 17.5
 —
 —
 17.5
 —
 —
 17.5
Purchase of common stock —
 (35.6) —
 —
 (35.6) —
 —
 (35.6)
Capital contributions from noncontrolling interest —
 —
 —
 —
 —
 —
 5.4
 5.4
Distributions to noncontrolling interests —
 —
 —
 —
 —
 —
 (0.9) (0.9)
Stock-based compensation and other —
 2.8
 —
 —
 2.8
 —
 —
 2.8
Balance at June 30, 2019 $3.2
 $4,197.9
 $5,821.7
 $(6.6) $10,016.2
 $30.4
 $101.7
 $10,148.3

06/30/2019 Form 10-Q7WEC Energy Group, Inc.
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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) (continued)
        
                 
  WEC Energy Group Common Shareholders' Equity      
(in millions, except per share amounts) Common Stock Additional Paid In Capital Retained Earnings Accumulated Other Comprehensive Income Total Common Shareholders' Equity Preferred Stock of Subsidiary Non-controlling Interests Total Equity
Balance at December 31, 2017 $3.2
 $4,278.5
 $5,176.8
 $2.9
 $9,461.4
 $30.4
 $—
 $9,491.8
Net income attributed to common shareholders —
 —
 390.1
 —
 390.1
 —
 —
 390.1
Other comprehensive income —
 —
 —
 1.7
 1.7
 —
 —
 1.7
Common stock dividends of $0.5525 per share —
 —
 (174.2) —
 (174.2) —
 —
 (174.2)
Exercise of stock options —
 2.1
 —
 —
 2.1
 —
 —
 2.1
Purchase of common stock —
 (15.8) —
 —
 (15.8) —
 —
 (15.8)
Stock-based compensation and other —
 2.5
 —
 —
 2.5
 —
 —
 2.5
Balance at March 31, 2018 $3.2
 $4,267.3
 $5,392.7
 $4.6
 $9,667.8
 $30.4
 $—
 $9,698.2
Net income attributed to common shareholders —
 —
 231.0
 —
 231.0
 —
 —
 231.0
Other comprehensive loss —
 —
 —
 (2.1) (2.1) —
 —
 (2.1)
Common stock dividends of $0.5525 per share —
 —
 (174.5) —
 (174.5) —
 —
 (174.5)
Exercise of stock options —
 3.0
 —
 —
 3.0
 —
 —
 3.0
Purchase of common stock —
 (4.0) —
 —
 (4.0) —
 —
 (4.0)
Stock-based compensation and other —
 4.7
 (0.1) —
 4.6
 —
 —
 4.6
Balance at June 30, 2018 $3.2
 $4,271.0
 $5,449.1
 $2.5
 $9,725.8
 $30.4
 $—
 $9,756.2

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


06/30/2019 Form 10-Q8WEC Energy Group, Inc.
Table of Contents

WEC ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
June 30, 20182019


NOTE 1—GENERAL INFORMATION


WEC Energy Group serves approximately 1.6 million electric customers and 2.9 million natural gas customers, and owns approximately 60% of ATC.


As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, 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 WEC Energy Group and all of its subsidiaries.


On our financial statements, we consolidate our majority-owned subsidiaries and reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of June 30, 2019 related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. We completed the acquisition of an 80% membership interest in Upstream during January 2019. See Note 2, Acquisitions, for more information.

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 18, Investment in Transmission Affiliates, for more information.

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—ACQUISITIONS


All the acquisitions discussed below were accounted for as asset acquisitions.

Acquisition of a Wind Energy Generation Facility in IllinoisNebraska


On June 27, 2018,In January 2019, we signed an agreement forcompleted the acquisition of an 80% membership interest in Upstream, a 132 MW wind generating facility located in Henry County, Illinois, known as Bishop Hill III Wind Energy Center ("Bishop Hill III"), for $148.0 million. Bishop Hill III has a 22-year offtake agreement with an unaffiliated company for the sale of all energy produced by the facility. Under the Tax Legislation, our investment in Bishop Hill III will qualify for production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and is expected to close in the third quarter of 2018. Bishop Hill III will be included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Nebraska

On April 30, 2018, we signed an agreement for the acquisition of an 80% membership interest in acommercially operational 202.5 MW wind generating facility, currently under construction known as Upstream Wind Energy Center (“Upstream”) for $276.0$268.2 million, which included transactions costs and is net of cash and restricted cash acquired of $9.2 million. Upstream is located in Antelope County, Nebraska and will supplysupplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over a 10-year period through an agreement entered into with an unaffiliated third party. Under the Tax Legislation, our investment in Upstream willqualifies for production tax credits and 100% bonus depreciation. Upstream is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Generation Facility in South Dakota

In December 2018, we acquired an 80% ownership interest in Coyote Ridge, a 97.5 MW wind generating facility under construction in Brookings County, South Dakota, for $61.6 million, which included transaction costs. This wind generating facility is expected to be in service by the end of 2019. Upon completion, we expect our total investment in Coyote Ridge to be $145 million. The project has a 12-year offtake agreement with an unaffiliated third party for all of the energy produced by the facility. Under the Tax Legislation, our investment in Coyote Ridge is expected to qualify for production tax credits and 100% bonus depreciation. The transaction is subjectWe are entitled to FERC approval and is expected99% of the tax benefits related to close inthis facility for the first quarter11 years of 2019,commercial operation, after Upstream achieves commercial operation. Upstreamwhich we will be entitled to tax benefits equal to our ownership interest. Coyote Ridge is included in the non-utility energy infrastructure segment.


06/30/2019 Form 10-Q9WEC Energy Group, Inc.
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Acquisition of a Wind Energy Generation Facility in Illinois

In August 2018, we completed the acquisition of an 80% membership interest in a commercially operational 132 MW wind generating facility located in Henry County, Illinois, known as Bishop Hill III, for $144.7 million, which included transaction costs and was net of restricted cash acquired of $4.5 million. In December 2018, we completed the acquisition of an additional 10% membership interest in Bishop Hill III, for $18.2 million. Bishop Hill III has a 22-year offtake agreement with an unaffiliated third party for all of the energy produced by the facility. Under the Tax Legislation, our investment in Bishop Hill III qualifies for production tax credits and 100% bonus depreciation. Bishop Hill III is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Wisconsin


OnIn April 2, 2018, WPS, along with two other unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129138 MW. The aggregate purchase price was $172.9 million of which WPS’s proportionate share was 44.6%, or $77.1 million. In addition, we incurred transaction costs that are recorded to a regulatory asset. Since 2008 and up until the acquisition, WPS purchased 44.6% of the facility’s energy output under a power purchase agreement.


06/30/2018 Form 10-Q7WEC Energy Group, Inc.
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The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base.
(in millions)  
Current assets $0.2
Net property, plant, and equipment 76.9
Total purchase price $77.1


Under a joint ownership agreement with the two other utilities, WPS is entitled to its share of generating capability and output of the facility equal to its ownership interest. WPS is also is paying its ownership share of additional construction costscapital expenditures and operating expenses. Forward Wind Energy Center is included in the Wisconsin segment.

Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, we completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we incurred $4.9 million of acquisition related costs.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy infrastructure segment. See Note 17, Segment Information, for more information.
(in millions)  
Current assets $2.0
Net property, plant, and equipment 218.3
Goodwill 6.6
Current liabilities (0.9)
Total purchase price $226.0


NOTE 3—DISPOSITION


Corporate and Other Segment—Segment – Sale of Bostco Real Estate HoldingsCertain WPS Power Development, LLC Solar Power Generation Facilities


In March 2017,June 2019, we sold the remaining real estate holdings of Bostcothree solar power generation facilities owned by PDL for $20.0 million. These solar facilities were located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space.Massachusetts. During the firstsecond quarter of 2017,2019, we recorded an insignificantafter-tax gain on the sale whichof $4.9 million primarily related to the recognition of deferred investment tax credits. This was included in other income nettax expense on 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 withof these assetsfacilities remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.


NOTE 4—OPERATING REVENUES


Adoption of ASU 2014-09,For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues, from Contracts with Customersin our 2018 Annual Report on Form 10-K.


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.



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

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

Disaggregation of Operating Revenues


The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. 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 segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.

Comparable amounts have not been presented for the three and six months ended June 30, 2017, due to our adoption of this standard under the modified retrospective method.
(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Three Months Ended June 30, 2019  
  
    
    
  
  
Electric $1,021.9
 $—
 $—
 $1,021.9
 $—
 $—
 $—
 $1,021.9
Natural gas 227.3
 232.8
 64.0
 524.1
 9.8
 —
 (9.1) 524.8
Total regulated revenues 1,249.2
 232.8
 64.0
 1,546.0
 9.8
 —
 (9.1) 1,546.7
Other non-utility revenues —
 —
 4.2
 4.2
 15.3
 0.8
 (3.1) 17.2
Total revenues from contracts with customers 1,249.2
 232.8
 68.2
 1,550.2
 25.1
 0.8
 (12.2) 1,563.9
Other operating revenues 4.1
 10.1
 0.6
 14.8
 98.2
 0.1
 (86.8) 26.3
Total operating revenues $1,253.3
 $242.9
 $68.8
 $1,565.0
 $123.3
 $0.9
 $(99.0) $1,590.2

(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Three Months Ended June 30, 2018  
  
    
    
  
  
Electric $1,084.2
 $—
 $—
 $1,084.2
 $—
 $—
 $—
 $1,084.2
Natural gas 236.4
 273.8
 68.9
 579.1
 10.0
 —
 (12.7) 576.4
Total regulated revenues 1,320.6
 273.8
 68.9
 1,663.3
 10.0
 —
 (12.7) 1,660.6
Other non-utility revenues —
 0.1
 3.9
 4.0
 9.3
 2.8
 (3.1) 13.0
Total revenues from contracts with customers 1,320.6
 273.9
 72.8
 1,667.3
 19.3
 2.8
 (15.8) 1,673.6
Other operating revenues 4.9
 (5.9) (0.4) (1.4) 97.7
 0.3
 (97.7) (1.1)
Total operating revenues $1,325.5
 $268.0
 $72.4
 $1,665.9
 $117.0
 $3.1
 $(113.5) $1,672.5


(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated Wisconsin Illinois Other States 
Total Utility
Operations
 Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Three Months Ended June 30, 2018  
  
    
      
  
  
Six Months Ended June 30, 2019  
  
    
    
  
  
Electric $1,084.2
 $—
 $—
 $1,084.2
 $—
 $—
 $—
 $—
 $1,084.2
 $2,083.7
 $—
 $—
 $2,083.7
 $—
 $—
 $—
 $2,083.7
Natural gas 236.4
 273.8
 68.9
 579.1
 —
 10.0
 —
 (12.7) 576.4
 792.2
 777.4
 249.2
 1,818.8
 26.2
 —
 (23.8) 1,821.2
Total utility revenues 1,320.6
 273.8
 68.9
 1,663.3
 —
 10.0
 —
 (12.7) 1,660.6
Total regulated revenues 2,875.9
 777.4
 249.2
 3,902.5
 26.2
 —
 (23.8) 3,904.9
Other non-utility revenues —
 0.1
 3.9
 4.0
 —
 9.3
 2.8
 (3.1) 13.0
 —
 0.1
 8.3
 8.4
 28.6
 2.3
 (3.8) 35.5
Total revenues from contracts with customers 1,320.6
 273.9
 72.8
 1,667.3
 —
 19.3
 2.8
 (15.8) 1,673.6
 2,875.9
 777.5
 257.5
 3,910.9
 54.8
 2.3
 (27.6) 3,940.4
Other operating revenues 4.9
 (5.9) (0.4) (1.4) —
 97.7
 0.3
 (97.7) (1.1) 10.8
 1.9
 (3.5) 9.2
 196.3
 0.3
 (178.6) 27.2
Total operating revenues $1,325.5
 $268.0
 $72.4
 $1,665.9
 $—
 $117.0
 $3.1
 $(113.5) $1,672.5
 $2,886.7
 $779.4
 $254.0
 $3,920.1
 $251.1
 $2.6
 $(206.2) $3,967.6


(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Six Months Ended June 30, 2018  
  
    
      
  
  
Electric $2,151.9
 $—
 $—
 $2,151.9
 $—
 $—
 $—
 $—
 $2,151.9
Natural gas 754.4
 781.4
 241.6
 1,777.4
 —
 24.9
 —
 (15.2) 1,787.1
Total utility revenues 2,906.3
 781.4
 241.6
 3,929.3
 —
 24.9
 —
 (15.2) 3,939.0
Other non-utility revenues —
 0.1
 7.8
 7.9
 —
 16.4
 4.1
 (3.8) 24.6
Total revenues from contracts with customers 2,906.3
 781.5
 249.4
 3,937.2
 —
 41.3
 4.1
 (19.0) 3,963.6
Other operating revenues 8.3
 (6.2) (7.1) (5.0) —
 193.8
 0.4
 (193.8) (4.6)
Total operating revenues $2,914.6
 $775.3
 $242.3
 $3,932.2
 $—
 $235.1
 $4.5
 $(212.8) $3,959.0


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(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Six Months Ended June 30, 2018  
  
    
    
  
  
Electric $2,151.9
 $—
 $—
 $2,151.9
 $—
 $—
 $—
 $2,151.9
Natural gas 754.4
 781.4
 241.6
 1,777.4
 24.9
 —
 (15.2) 1,787.1
Total regulated revenues 2,906.3
 781.4
 241.6
 3,929.3
 24.9
 —
 (15.2) 3,939.0
Other non-utility revenues —
 0.1
 7.8
 7.9
 16.4
 4.1
 (3.8) 24.6
Total revenues from contracts with customers 2,906.3
 781.5
 249.4
 3,937.2
 41.3
 4.1
 (19.0) 3,963.6
Other operating revenues 8.3
 (6.2) (7.1) (5.0) 193.8
 0.4
 (193.8) (4.6)
Total operating revenues $2,914.6
 $775.3
 $242.3
 $3,932.2
 $235.1
 $4.5
 $(212.8) $3,959.0


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 $356.7
 $393.7
 $763.4
 $778.0
Small commercial and industrial 331.3
 353.3
 665.2
 684.0
Large commercial and industrial 217.8
 241.6
 430.1
 445.5
Other 7.3
 7.2
 15.1
 14.9
Total retail revenues 913.1
 995.8
 1,873.8
 1,922.4
Wholesale 44.6
 58.4
 92.3
 113.3
Resale 49.4
 25.1
 90.2
 98.9
Steam 4.3
 4.5
 14.4
 14.2
Other utility revenues 10.5
 0.4
 13.0
 3.1
Total electric utility operating revenues $1,021.9
 $1,084.2
 $2,083.7
 $2,151.9


Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:
  Electric Utility Operating Revenues
(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
Residential $393.7
 $778.0
Small commercial and industrial 353.3
 684.0
Large commercial and industrial 241.6
 445.5
Other 7.2
 14.9
Total retail revenues 995.8
 1,922.4
Wholesale 58.4
 113.3
Resale 25.1
 98.9
Steam 4.5
 14.2
Other utility revenues 0.4
 3.1
Total electric utility operating revenues $1,084.2
 $2,151.9
(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Three Months Ended June 30, 2019  
  
    
Residential $126.2
 $154.1
 $39.3
 $319.6
Commercial and industrial 55.8
 45.1
 20.5
 121.4
Total retail revenues 182.0
 199.2
 59.8
 441.0
Transport 16.2
 46.8
 6.3
 69.3
Other utility revenues * 29.1
 (13.2) (2.1) 13.8
Total natural gas utility operating revenues $227.3
 $232.8
 $64.0
 $524.1


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 Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities 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 utilities 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.



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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.
(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Three Months Ended June 30, 2018  
  
    
Residential $128.1
 $163.7
 $37.9
 $329.7
Commercial and industrial 63.5
 47.3
 18.7
 129.5
Total retail revenues 191.6
 211.0
 56.6
 459.2
Transport 16.4
 54.6
 6.8
 77.8
Other utility revenues * 28.4
 8.2
 5.5
 42.1
Total natural gas utility operating revenues $236.4
 $273.8
 $68.9
 $579.1


Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class for the three and six months ended June 30, 2018:
(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operations Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Three Months Ended June 30, 2018  
  
    
Six Months Ended June 30, 2019  
  
    
Residential $128.1
 $163.7
 $37.9
 $329.7
 $510.1
 $508.1
 $164.5
 $1,182.7
Commercial and industrial 63.5
 47.3
 18.7
 129.5
 255.5
 161.3
 92.5
 509.3
Total retail revenues 191.6
 211.0
 56.6
 459.2
 765.6
 669.4
 257.0
 1,692.0
Transport 16.4
 54.6
 6.8
 77.8
 38.1
 134.0
 17.4
 189.5
Other utility revenues * 28.4
 8.2
 5.5
 42.1
 (11.5) (26.0) (25.2) (62.7)
Total natural gas utility operating revenues $236.4
 $273.8
 $68.9
 $579.1
 $792.2
 $777.4
 $249.2
 $1,818.8


(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Six Months Ended June 30, 2018  
  
    
Residential $484.8
 $496.3
 $161.1
 $1,142.2
Commercial and industrial 251.4
 156.7
 83.4
 491.5
Total retail revenues 736.2
 653.0
 244.5
 1,633.7
Transport 37.4
 132.3
 16.7
 186.4
Other utility revenues * (19.2) (3.9) (19.6) (42.7)
Total natural gas utility operating revenues $754.4
 $781.4
 $241.6
 $1,777.4

(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operations
Six Months Ended June 30, 2018  
  
    
Residential $484.8
 $496.3
 $161.1
 $1,142.2
Commercial and industrial 251.4
 156.7
 83.4
 491.5
Total retail revenues 736.2
 653.0
 244.5
 1,633.7
Transport 37.4
 132.3
 16.7
 186.4
Other utility revenues * (19.2) (3.9) (19.6) (42.7)
Total natural gas utility operating revenues $754.4
 $781.4
 $241.6
 $1,777.4


*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 the tariffs of our regulated utilities. 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.

The transaction price of the performance obligations is valued using rates in the tariffs of our regulated utilities, which 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 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.


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Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WG, and WPS, and provides service to several unaffiliated customers. We recognize revenues using a time-based output method through a monthly fixed service fee.


Other Non-Utility Operating Revenues


Other non-utility operating revenues consist primarily of the following:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
We Power revenues $6.3
 $6.2
 $12.7
 $12.6
Appliance service revenues 4.2
 3.9
 8.3
 7.8
Distributed renewable solar project revenues 0.8
 2.8
 2.3
 4.1
Wind generation revenues * 5.9
 —
 12.1
 —
Other —
 0.1
 0.1
 0.1
Total other non-utility operating revenues $17.2
 $13.0
 $35.5
 $24.6

(in millions) Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
We Power revenues $6.2
 $12.6
Appliance service revenues 3.9
 7.8
Distributed renewable solar project revenues 2.8
 4.1
Other 0.1
 0.1
Total other non-utility operating revenues $13.0
 $24.6

*In 2019, we continued to invest in wind generation facilities and recognize revenues from these wind generation facilities as energy is produced and delivered to the customer within the production month.


As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as deferred revenue, net on our balance sheets and we continually amortize the deferred carrying coststhis contract liability to revenues over the life of the related lease term that We Power has with WE.

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During the three and six months ended June 30, 2019, we recorded $6.3 million and $12.7 million of revenue, respectively, related to amortization of these deferred carrying costs. During the three and six months ended June 30, 2018, we recorded $6.2 million and $12.6 million respectively, of revenue, respectively, related to amortization of these deferred carrying costs, which were included in the contract liability balance at the beginning of the period. This contract liability is presented as deferred revenue, net on our balance sheets.costs.

Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.

Revenues from distributed renewable solar projects consist primarily of sales of renewable energy and solar renewable energy certificates (SRECs) generated by PDL. The sale of SRECs is a distinct performance obligation as they are often sold separately from the renewable energy generated. Although the performance obligation for the sale of renewable energy is recognized over time and the performance obligation for SRECs is recognized at a point-in-time, the timing of revenue recognition is the same, as the generation of renewable energy and sales of SREC's occur concurrently.


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
Alternative revenues * $(14.2) $(30.3) $1.1
 $(14.2) $(18.6) $(30.3)
Late payment charges 11.1
 22.5
 12.0
 11.1
 25.2
 22.5
Leases 2.0
 3.2
Rental revenues 13.2
 2.0
 20.6
 3.2
Total other operating revenues $(1.1) $(4.6) $26.3
 $(1.1) $27.2
 $(4.6)


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



NOTE 5—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 our 2018 Annual Report on Form 10-K.
(in millions) June 30, 2019 December 31, 2018
Regulatory assets    
Pension and OPEB costs $1,153.3
 $1,193.5
Plant retirements * 1,031.7
 832.3
Environmental remediation costs 707.6
 687.1
Income tax related items 424.6
 369.1
SSR 319.0
 316.7
Asset retirement obligations 212.2
 185.4
Uncollectible expense 43.6
 38.7
We Power generation 38.6
 43.0
Electric transmission costs 25.6
 58.1
Energy efficiency programs 8.9
 14.0
Other, net 70.2
 117.9
Total regulatory assets $4,035.3
 $3,855.8
     
Balance sheet presentation    
Other current assets $28.3
 $50.7
Regulatory assets 4,007.0
 3,805.1
Total regulatory assets $4,035.3
 $3,855.8

*On March 31, 2019, the PIPP generating units were retired by WE. See Note 6, Property, Plant, and Equipment, for more information on the retirement of the PIPP units.

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Alternative Revenues
(in millions) June 30, 2019 December 31, 2018
Regulatory liabilities    
Income tax related items $2,389.6
 $2,406.6
Removal costs 1,304.7
 1,329.6
Pension and OPEB costs 231.2
 238.3
Mines deferral 130.5
 120.8
Energy costs refundable through rate adjustments 90.1
 39.6
Decoupling 48.7
 30.5
Energy efficiency programs 42.0
 31.7
Uncollectible expense 31.9
 30.5
Earnings sharing mechanisms 30.0
 30.0
Derivatives 17.5
 16.4
Other, net 14.2
 14.4
Total regulatory liabilities $4,330.4
 $4,288.4
     
Balance sheet presentation    
Other current liabilities $86.8
 $36.8
Regulatory liabilities 4,243.6
 4,251.6
Total regulatory liabilities $4,330.4
 $4,288.4



Alternative revenues are created from programs authorized by regulators that allow our utilities
NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Presque Isle Power Plant

Pursuant to record additional revenues by adjusting rates inMISO's April 2018 approval of the future, usuallyretirement of the PIPP, these units were retired on March 31, 2019. The carrying value of the PIPP units was $167.2 million at June 30, 2019. This amount included the net book value of $178.5 million, which was classified as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenuesregulatory asset on our balance sheets as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Below is a summaryresult of the alternative revenue programs at our utilities:

The ratesretirement of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.
MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.
WE and WPS provide wholesale electric service 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 actualplant. In addition, an $11.3 million cost of service was for the year. The true-up can result in an amount that we will recover from or refundremoval reserve related to the customer. We considerPIPP units remained classified as a regulatory liability at June 30, 2019. After the true-upretirement of the PIPP, a portion of the wholesale electric revenuesregulatory asset and related cost of removal reserve was transferred to be alternative revenues.UMERC for recovery from their retail customers. WE has 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 and UMERC will amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired.


Severance Liability for Plant Retirements
NOTE 5—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired


We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announcedseveral plants within the retirement of the plants identified below.Wisconsin segment. In addition, a severance liability was recorded in other current liabilities on our balance sheets within the Wisconsin segment related to these plant retirements.
(in millions)  
Severance liability at December 31, 2018 $15.7
Severance payments (6.7)
Other (3.1)
Total severance liability at June 30, 2019 $5.9

(in millions)  
Severance liability at December 31, 2017 $29.4
Severance payments (8.7)
Other (3.0)
Total severance liability at June 30, 2018 $17.7


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 continues to amortize this regulatory asset on 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 19, 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


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base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 19, Commitments and Contingencies, and Note 21, Regulatory Environment, for more information.

Pulliam Power Plant

In connection with the MISO ruling received in June 2018, WPS will retire Pulliam Units 7 and 8 on or before October 31, 2018. Retirement of the Pulliam generating units remained probable at June 30, 2018. The carrying value of the Pulliam units was $42.3 million at June 30, 2018. This amount included the net book value of $62.1 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $19.8 million cost of removal reserve related to the Pulliam units was recorded as a regulatory liability at June 30, 2018. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 19, Commitments and Contingencies, for more information.

Edgewater Unit 4

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, retirement of the Edgewater 4 generating unit remained probable at June 30, 2018. The plant must be retired by September 30, 2018. The carrying value of the Edgewater 4 generating unit was $12.3 million at June 30, 2018. This amount included the net book value of WPS's ownership share of this generating unit of $14.2 million, which was classified as plant to be retired within property, plant, and equipment on our balance sheet. In addition, a $1.9 million cost of removal reserve related to the Edgewater 4 generating unit was recorded as a regulatory liability at June 30, 2018. This unit is included in rate base, and WPS continues to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 19, Commitments and Contingencies, for more information regarding the Consent Decree.

NOTE 6—7—COMMON EQUITY


Stock-Based Compensation


During the first quarter of 2018,2019, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:
Award Type Number of Awards
Stock options (1)
 710,710476,418

Restricted shares (2)
 156,34073,571

Performance units 217,560148,036



(1) 
Stock options awarded had a weighted-average exercise price of $65.60$68.18 and a weighted-average grant date fair value of $7.71$8.60 per option.


(2) 
Restricted shares awarded had a weighted-average grant date fair value of $64.20$68.18 per share.


Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, and our non-utility subsidiary, We Power.ATC Holding. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 9,10, 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.


Common Stock Dividends


On July 19, 2018,18, 2019, our Board of Directors declared a quarterly cash dividend of $0.5525$0.59 per share, payable on September 1, 2018,2019, to shareholders of record on August 14, 2018.2019.



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NOTE 7—8—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 $1,262.7
 $1,440.1
Weighted-average interest rate on amounts outstanding 2.58% 2.92%

(in millions, except percentages) June 30, 2018 December 31, 2017
Commercial paper    
Amount outstanding $1,370.0
 $1,444.6
Weighted-average interest rate on amounts outstanding 2.36% 1.77%


Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2018,2019 was $1,240.5$1,267.3 million with a weighted-average interest rate during the period of 2.11%2.76%.



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The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these facilities:
(in millions) Maturity June 30, 2019
WEC Energy Group October 2022 $1,200.0
WE October 2022 500.0
WPS October 2022 400.0
WG October 2022 350.0
PGL October 2022 350.0
Total short-term credit capacity   $2,800.0
Less:    
Letters of credit issued inside credit facilities   $2.5
Commercial paper outstanding   1,262.7
Available capacity under existing agreements   $1,534.8

(in millions) Maturity June 30, 2018
WEC Energy Group October 2022 $1,200.0
WE October 2022 500.0
WPS October 2022 400.0
WG October 2022 350.0
PGL October 2022 350.0
Total short-term credit capacity   $2,800.0
Less:    
Letters of credit issued inside credit facilities   $2.5
Commercial paper outstanding   1,370.0
Available capacity under existing agreements   $1,427.5


NOTE 8—9—LONG-TERM DEBT


WEC Energy Group, Inc.


In June 2018,March 2019, we issued $600.0$350.0 million of 3.375%3.10% Senior Notes due June 15, 2021.  TheMarch 8, 2022. We used the net proceeds were used to repay short-term debt, including short-term debt used to redeem at par all $114.9 million outstanding principal amount of Integrys' 2006 Junior Notes, to repay all $300.0 million of our 1.65% Senior Notes that matured in June 2018, and for working capital and other general corporate purposes.


Wisconsin Electric Power CompanyATC Holding LLC


In July 2018, WE redeemed all $80.02019, ATC Holding secured commitments for $235.0 million outstanding of 3.75% Senior Notes due September 16, 2029. ATC Holding expects to issue the Senior Notes in September 2019. The net proceeds are expected to be used to make a special distribution to WEC Energy Group in order to balance ATC Holding’s capital structure.

NOTE 10—LEASES

In 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 series of tax-exempt pollution control refunding bonds. Since August 2009,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 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 becauseadoption of the new lease guidance.

We did not reassess whether any expired or existing contracts were leases or contained leases.
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 held by WE.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 JuneJanuary 2018, WE's $250.0 millionthe 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 1.70% Debentures matured, andway) represent the outstanding principal was paid with proceeds received from issuing commercial paper.

Integrys Holding, Inc.

In May 2018, Integrys redeemedright 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 par all $114.9 million outstanding of its 2006 Junior Notes.

Interest Rate Swap

In July 2018, we executed two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps will provide a fixed interest rate of 4.9765% on $250.0 milliontime of the $500.0 million outstandingentity's adoption of 2007 Junior Notes through November 15, 2021.Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to


06/30/20182019 Form 10-Q1517WEC Energy Group, Inc.
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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.

Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $49.0 million and $48.8 million, respectively. Regarding our finance lease, while the adoption of Topic 842 changed the classification of expense related to this lease on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the lease asset 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.

Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, through April 2029.
Land we are leasing related to our Rothschild biomass plant through June 2051, and also a land lease related to a non-utility solar facility through December 2034.
Rail cars we are leasing to transport coal to various generating facilities through February 2021.

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 leases contain options to renew past the initial term, as set forth in the lease agreement.

Obligations Under Finance Lease

In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from 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. 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.

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

We recorded our minimum lease payments as purchased power expense on our income statement.
We recorded 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.

In conjunction with our adoption of Topic 842, while the timing of expense recognition related to this finance lease did not change, 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.
In order to ensure the timing of lease expense did not change for this finance lease 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 modified 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.


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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.

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
Finance/capital lease expense (1)
 $2.1
 $1.9
 $4.1
 $3.8
Operating lease expense (2)
 1.4
 1.4
 2.8
 2.8
Short-term lease expense (2)
 0.1
 0.6
 0.1
 0.7
Total lease expense $3.6
 $3.9
 $7.0
 $7.3
         
Other information        
         
Cash paid for amounts included in the measurement of lease liabilities        
Operating cash flows for finance/capital lease (3)
     $1.8
 $3.8
Operating cash flows for operating leases     $3.2
 $3.3
Financing cash flows for finance lease (3)
     $2.3
 $—
         
Non-cash activity – right of use assets obtained in exchange for operating lease liabilities     $49.0
  
         
Remaining lease term – finance lease     2.9 years
  
Weighted-average remaining lease term – operating leases     13.1 years
  
         
Discount rate – finance lease (4)
     15.8%  
Weighted average discount rate – operating leases (4)
     4.4%  

(1)
For the three and six months ended June 30, 2019, finance lease expense included amortization of right of use assets in the amount of $1.2 million and $2.3 million (included in depreciation and amortization expense), respectively and interest on lease liabilities of $0.9 million and $1.8 million (included in interest expense), respectively. For each of the three and six months ended June 30, 2018, total finance lease expense related to the long-term power purchase agreement was included in cost of sales.

(2)
Operating and short-term lease expense were 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 the finance lease 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 lease, the rate implicit in the lease was readily determinable.

The following table summarizes our finance lease right of use asset, which was included in property, plant and equipment on our balance sheets:
(in millions) June 30, 2019 December 31, 2018
Long-term power purchase commitment $140.3
 $140.3
Accumulated amortization (123.7) (120.9)
Total finance lease right of use asset/capital lease asset $16.6
 $19.4


Right of use assets related to operating leases were $44.7 million at June 30, 2019, and were included in other long-term assets on our balance sheets.

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Future minimum lease payments under our operating leases and our finance lease, 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
Six months ending December 31, 2019 $2.7
 $4.1
2020 6.9
 8.8
2021 4.9
 9.4
2022 4.9
 4.2
2023 5.0
 —
2024 4.8
 —
Thereafter 30.5
 —
Total minimum lease payments 59.7
 26.5
Less: Interest (15.3) (5.5)
Present value of minimum lease payments 44.4
 21.0
Less: Short-term lease liabilities (4.3) (5.6)
Long-term lease liabilities $40.1
 $15.4


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.

At December 31, 2018, short-term and long-term liabilities under our capital lease were $4.9 million and $18.4 million, respectively. Short-term and long-term lease liabilities related to our finance/capital lease were included in current portion of long-term debt and long-term debt on the balance sheets, respectively.

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.

Related to our investment in the Two Creeks Solar Project, WPS, along with an unaffiliated utility, entered into several land leases in Manitowoc County, Wisconsin that commenced in the third quarter of 2019. The leases with unaffiliated parties are for a total of approximately 600 acres of land. Each lease has an initial term of 30 years with two optional 10-year extensions.

NOTE 9—11—MATERIALS, SUPPLIES, AND INVENTORIES


Our inventory consisted of:
(in millions) June 30, 2019 December 31, 2018
Materials and supplies $236.0
 $226.6
Natural gas in storage 130.5
 232.9
Fossil fuel 94.9
 88.7
Total $461.4
 $548.2

(in millions) June 30, 2018 December 31, 2017
Natural gas in storage $121.9
 $209.0
Materials and supplies 221.4
 211.2
Fossil fuel 123.3
 118.8
Total $466.6
 $539.0


PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At June 30, 2018,2019, we had a temporary LIFO liquidation creditdebit of $11.1$2.9 million recorded within other current liabilitiesassets on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.



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


NOTE 10—12—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 $52.7
 21.0 % $59.2
 21.0 %
State income taxes net of federal tax benefit 15.6
 6.2 % 17.7
 6.3 %
Tax repairs (30.4) (12.1)% (22.5) (8.0)%
Federal excess deferred tax amortization (7.5) (3.0)% 1.5
 0.5 %
Wind production tax credits (6.2) (2.5)% (2.1) (0.7)%
Excess tax benefits – stock options (4.4) (1.7)% (1.0) (0.3)%
Other (4.6) (1.8)% (1.7) (0.7)%
Total income tax expense $15.2
 6.1 % $51.1
 18.1 %

  Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
  Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $59.2
 21.0 % $159.7
 21.0 %
State income taxes net of federal tax benefit 17.7
 6.3 % 47.6
 6.3 %
Tax repairs (22.5) (8.0)% (48.0) (6.3)%
Federal tax reform 1.5
 0.5 % (14.0) (1.8)%
Other (4.8) (1.7)% (5.9) (0.9)%
Total income tax expense $51.1
 18.1 % $139.4
 18.3 %


  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 $154.6
 21.0 % $159.7
 21.0 %
State income taxes net of federal tax benefit 46.5
 6.3 % 47.6
 6.3 %
Tax repairs (60.0) (8.1)% (48.0) (6.3)%
Federal excess deferred tax amortization (20.7) (2.8)% (14.0) (1.8)%
Wind production tax credits (19.6) (2.7)% (5.9) (0.8)%
Excess tax benefits – stock options (11.6) (1.6)% (1.9) (0.3)%
Other (9.0) (1.2)% 1.9
 0.2 %
Total income tax expense $80.2
 10.9 % $139.4
 18.3 %


The effective tax rates of 6.1% and 10.9% 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 generated from recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment, partially offset by state income taxes.

The effective tax rates of 18.1% and 18.3% 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, partially offset by state income taxes.

The Tax Legislation, signed into law in December 2017, required our regulated utilities to remeasure their deferred income taxes and beginwe began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax reformamortization line above). See Note 21,23, Regulatory Environment, for more information about the impact of the Tax Legislation and 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 11—13—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).


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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.


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


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


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


When possible, we base the valuations of our financial 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 $5.4
 $0.6
 $—
 $6.0
 $2.6
 $2.0
 $—
 $4.6
Petroleum products contracts 0.4
 —
 —
 0.4
FTRs —
 —
 16.7
 16.7
 —
 —
 10.4
 10.4
Coal contracts —
 0.6
 —
 0.6
 —
 0.8
 —
 0.8
Total derivative assets $5.8
 $1.2
 $16.7
 $23.7
 $2.6
 $2.8
 $10.4
 $15.8
                
Investments held in rabbi trust $107.6
 $—
 $—
 $107.6
 $77.1
 $—
 $—
 $77.1
                
Derivative liabilities                
Natural gas contracts $2.1
 $0.2
 $—
 $2.3
 $23.8
 $0.5
 $—
 $24.3
Coal contracts —
 0.3
 —
 0.3
 —
 0.1
 —
 0.1
Interest rate swaps —
 6.7
 —
 6.7
Total derivative liabilities $2.1
 $0.5
 $—
 $2.6
 $23.8
 $7.3
 $—
 $31.1



  December 31, 2018
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $6.3
 $1.8
 $—
 $8.1
FTRs —
 —
 7.4
 7.4
Coal contracts —
 0.4
 —
 0.4
Total derivative assets $6.3
 $2.2
 $7.4
 $15.9
         
Investments held in rabbi trust $65.0
 $—
 $—
 $65.0
         
Derivative liabilities        
Natural gas contracts $4.7
 $0.8
 $—
 $5.5
Coal contracts —
 0.1
 —
 0.1
Interest rate swaps —
 2.3
 —
 2.3
Total derivative liabilities $4.7
 $3.2
 $—
 $7.9



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  December 31, 2017
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $1.8
 $3.9
 $—
 $5.7
Petroleum products contracts 1.2
 —
 —
 1.2
FTRs —
 —
 4.4
 4.4
Coal contracts —
 1.1
 —
 1.1
Total derivative assets $3.0
 $5.0
 $4.4
 $12.4
         
Investments held in rabbi trust $120.7
 $—
 $—
 $120.7
         
Derivative liabilities        
Natural gas contracts $7.0
 $3.8
 $—
 $10.8
Coal contracts —
 0.8
 —
 0.8
Total derivative liabilities $7.0
 $4.6
 $—
 $11.6


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


We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. For the three months ended June 30, 20182019 and 2017,2018, the net unrealized gains included in earnings related to the investments held at the end of the period were $3.5$2.8 million and $2.6$3.5 million, respectively. For the six months ended June 30, 20182019 and 2017,2018, the net unrealized gains included in earnings related to the investments held at the end of the period were $0.4$11.4 million and $7.8$0.4 million, respectively.


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 $3.1
 $1.5
 $7.4
 $4.4
Purchases 12.8
 18.4
 12.8
 18.4
Settlements (5.5) (3.2) (9.8) (6.1)
Balance at the end of the period $10.4
 $16.7
 $10.4
 $16.7

  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Balance at the beginning of the period $1.5
 $1.7
 $4.4
 $5.1
Purchases 18.4
 13.8
 18.4
 13.8
Settlements (3.2) (3.7) (6.1) (7.1)
Balance at the end of the period $16.7
 $11.8
 $16.7
 $11.8


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 of subsidiary $30.4
 $28.2
 $30.4
 $28.3
Long-term debt, including current portion * 10,666.5
 11,543.4
 10,335.7
 10,554.9

  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 * 9,477.6
 9,827.1
 9,561.7
 10,341.9


*The carrying amount of long-term debt excludes finance and capital lease obligations of $25.2$21.0 million and $27.0$23.3 million at June 30, 20182019 and December 31, 2017,2018, respectively.


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


NOTE 12—14—DERIVATIVE INSTRUMENTS


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


06/30/2018 Form 10-Q18WEC Energy Group, Inc.
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We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.



06/30/2019 Form 10-Q23WEC Energy Group, Inc.
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None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. The following table shows our derivative assets and derivative liabilities:
  June 30, 2019 December 31, 2018
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
Natural gas contracts $4.6
 $22.5
 $7.7
 $5.3
FTRs 10.4
 —
 7.4
 —
Coal contracts 0.5
 0.1
 0.2
 0.1
Interest rate swaps —
 1.9
 —
 0.4
Total other current * $15.5
 $24.5

$15.3

$5.8
         
Other long-term        
Natural gas contracts $—
 $1.8
 $0.4
 $0.2
Coal contracts 0.3
 —
 0.2
 —
Interest rate swaps —
 4.8
 —
 1.9
Total other long-term * $0.3
 $6.6

$0.6

$2.1
Total $15.8
 $31.1
 $15.9
 $7.9

  June 30, 2018 December 31, 2017
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
Natural gas contracts $5.6
 $1.8
 $5.6
 $9.4
Petroleum products contracts 0.4
 —
 1.2
 —
FTRs 16.7
 —
 4.4
 —
Coal contracts 0.5
 0.3
 0.6
 0.6
   Total other current * $23.2
 $2.1

$11.8

$10.0
         
Other long-term        
Natural gas contracts $0.4
 $0.5
 $0.1
 $1.4
Coal contracts 0.1
 —
 0.5
 0.2
   Total other long-term * $0.5
 $0.5

$0.6

$1.6
Total $23.7
 $2.6
 $12.4
 $11.6


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


Realized gains (losses) on derivativederivatives not designated as hedging 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 39.9 Dth $(2.3) 25.2 Dth $1.3
 43.8 Dth $(3.1) 39.9 Dth $(2.3)
Petroleum products contracts 1.7 gallons 0.3
 4.9 gallons (0.4) — gallons —
 1.7 gallons 0.3
FTRs 6.8 MWh 3.9
 9.4 MWh 2.2
 8.0 MWh 3.0
 6.8 MWh 3.9
Total   $1.9
   $3.1
   $(0.1)   $1.9


  Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 99.9 Dth $(3.6) 88.0 Dth $(7.5)
Petroleum products contracts — gallons —
 3.8 gallons 0.8
FTRs 16.1 MWh 5.3
 15.0 MWh 7.6
Total   $1.7
   $0.9

  Six Months Ended June 30, 2018 Six Months Ended June 30, 2017
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 88.0 Dth $(7.5) 59.3 Dth $1.0
Petroleum products contracts 3.8 gallons 0.8
 9.8 gallons (0.9)
FTRs 15.0 MWh 7.6
 18.6 MWh 5.2
Total   $0.9
   $5.3


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 $4.8$30.2 million and $16.2$2.7 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At December 31, 2018, we had also received cash collateral of $0.2 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities. We had not received any cash collateral at June 30, 2019.




06/30/20182019 Form 10-Q1924WEC Energy Group, Inc.
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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 $23.7
 $2.6
 $12.4
 $11.6
  $15.8
 $31.1
 $15.9
 $7.9
 
Gross amount not offset on the balance sheet (2.1) (2.1) (4.9) (9.0)* (3.0) (24.2)
(1) 
(4.0)
(2) 
(4.9)
(3) 
Net amount $21.6
 $0.5
 $7.5
 $2.6
  $12.8
 $6.9
 $11.9
 $3.0
 


*
(1)
Includes cash collateral posted of $4.1$21.2 million.


(2)
Includes cash collateral received of $0.2 million.

(3)
Includes cash collateral posted of $1.1 million.

CertainCash Flow Hedges

Effective January 1, 2019, we adopted ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities. The amendments in this update expand the strategies that qualify for hedge accounting, amend the presentation and disclosure requirements related to hedging activities, and provide overall targeted improvements to simplify hedge accounting in certain situations. The adoption of this standard did not have a significant impact on our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the eventfinancial statements.

As of June 30, 2019, we had two interest rate swaps with a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate faircombined notional value of all derivative instruments$250.0 million to hedge the variable interest rate risk associated with specific credit risk-related contingent features that wereour 2007 Junior Notes. The swaps provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes through November 15, 2021. As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses are being deferred in a net liability position was $0.1 millionaccumulated other comprehensive loss and $3.7 million at June 30, 2018 and December 31, 2017, respectively. At June 30, 2018 and December 31, 2017, we had not posted any collateralare being amortized to interest expense as interest is accrued on the 2007 Junior Notes.

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the credit risk-related contingent featuresacquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The table below shows the amounts related to these commodity instruments. If all ofcash flow hedges recorded in other comprehensive loss and in earnings, along with our total interest expense on the credit risk-related contingent features contained in derivative instruments inincome statements:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Derivative losses recognized in other comprehensive loss $(3.2) $—
 $(4.8) $—
Net derivative gains reclassified from accumulated other comprehensive loss to interest expense 0.4
 0.5
 0.8
 1.1
Total interest expense line item on the income statements 124.1
 108.5
 248.5
 215.2


We estimate that during the next twelve months $0.3 million will be reclassified from accumulated other comprehensive loss as a net liability position had been triggered at June 30, 2018, we would not have been requiredreduction to post any collateral. At December 31, 2017, we would have been required to post collateral of $2.7 million.interest expense.



06/30/2019 Form 10-Q25WEC Energy Group, Inc.
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NOTE 13—15—GUARANTEES


The following table shows our outstanding guarantees:
   Expiration    Expiration
(in millions) Total Amounts Committed at June 30, 2018 
Less Than
1 Year
 1 to 3 Years Over 3 Years Total Amounts Committed at June 30, 2019 Less Than 1 Year 1 to 3 Years Over 3 Years
Guarantees                 
Guarantees supporting commodity transactions of subsidiaries (1)
 $5.6
 $5.6
 $—
 $—
  $6.7
 $6.7
 $—
 $—
Standby letters of credit (2)
 103.7
 25.0
 0.2
 78.5
(5) 
 101.3
 1.0
 0.2
 100.1
Surety bonds (3)
 9.2
 9.2
 —
 —
  9.7
 9.6
 0.1
 —
Other guarantees (4)
 11.6
 0.5
 —
 11.1
  10.4
 —
 0.9
 9.5
Total guarantees $130.1
 $40.3
 $0.2
 $89.6
  $128.1
 $17.3
 $1.2
 $109.6


(1) 
PrimarilyIncludes $2.7 million and $4.0 million to support the business operations of Bluewater.Bluewater and UMERC, respectively.


(2) 
At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.


(3) 
Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.


(4) 
Consists of $11.6$10.4 million related to other indemnifications, for which a liability of $11.1$9.5 million related to workers compensation coverage was recorded on our balance sheets.


(5)
Consists of standby letters of credit that automatically renew each year unless proper termination notice is given.


06/30/2018 Form 10-Q20WEC Energy Group, Inc.
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NOTE 14—16—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 $11.8
 $10.4
 $23.8
 $22.1
 $11.8
 $11.8
 $23.1
 $23.8
Interest cost 28.7
 30.2
 57.0
 61.4
 30.2
 28.7
 60.8
 57.0
Expected return on plan assets (48.8) (48.5) (98.4) (98.1) (48.2) (48.8) (96.9) (98.4)
Loss on plan settlement 0.3
 5.3
 0.7
 5.3
 1.0
 0.3
 1.8
 0.7
Amortization of prior service cost 0.6
 0.8
 1.3
 1.5
 0.5
 0.6
 1.1
 1.3
Amortization of net actuarial loss 23.9
 21.1
 47.0
 43.0
 18.7
 23.9
 37.7
 47.0
Net periodic benefit cost $16.5
 $19.3
 $31.4
 $35.2
 $14.0
 $16.5
 $27.6
 $31.4


  OPEB Costs
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Service cost $3.8
 $5.6
 $8.2
 $11.8
Interest cost 6.3
 7.4
 12.8
 14.9
Expected return on plan assets (13.6) (14.8) (27.3) (29.7)
Amortization of prior service credit (3.8) (3.9) (7.7) (7.7)
Amortization of net actuarial (gain) loss (2.0) 0.2
 (2.7) 0.5
Net periodic benefit credit $(9.3) $(5.5) $(16.7) $(10.2)

  OPEB Costs
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Service cost $5.6
 $5.6
 $11.8
 $11.9
Interest cost 7.4
 8.4
 14.9
 16.9
Expected return on plan assets (14.8) (13.6) (29.7) (27.3)
Amortization of prior service credit (3.9) (2.8) (7.7) (5.6)
Amortization of net actuarial loss 0.2
 0.1
 0.5
 1.6
Net periodic benefit credit $(5.5) $(2.3) $(10.2) $(2.5)


During the six months ended June 30, 2018,2019, we made contributions and payments of $7.0$6.9 million related to our pension plans and $2.7$1.4 million related to our OPEB plans. We expect to make contributions and payments of $65.6$4.9 million related to our pension plans and $5.4$5.3 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 components of net benefit costs:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Non-service credit components $(5.3) $—
 $(12.5) $(2.6)

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

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



06/30/20182019 Form 10-Q2126WEC Energy Group, Inc.
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NOTE 15—17—GOODWILL


Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table below shows changes to our goodwill balances by segment for the six months ended June 30, 2019. We had no changes to the carrying amount of goodwill during the six months ended June 30, 2018:2019.
(in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total
Goodwill balance as of January 1, 2018 $2,104.3
 $758.7
 $183.2
 $7.3
 $3,053.5
Adjustment to Bluewater purchase price allocation (1)
 —
 —
 —
 (0.7) (0.7)
Goodwill balance as of June 30, 2018 (2)
 $2,104.3
 $758.7
 $183.2
 $6.6
 $3,052.8
(in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total
Goodwill balance * $2,104.3
 $758.7
 $183.2
 $6.6
 $3,052.8


(1)
See Note 2, Acquisitions, for more information on the acquisition of Bluewater.
(2)
*		We had no accumulated impairment losses related to our goodwill as of June 30, 2018.2019.


NOTE 16—18—INVESTMENT IN TRANSMISSION AFFILIATES


We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:
 Three Months Ended June 30, 2018 Three Months Ended June 30, 2019
(in millions) ATC ATC Holdco Total ATC ATC Holdco Total
Balance at beginning of period $1,561.1
 $37.8
 $1,598.9
 $1,630.6
 $40.0
 $1,670.6
Add: Earnings (loss) from equity method investment 29.8
 (1.1) 28.7
 37.4
 (0.5) 36.9
Add: Capital contributions 18.1
 1.5
 19.6
 18.1
 0.4
 18.5
Less: Distributions 50.7
 —
 50.7
 29.4
 —
 29.4
Add: Other 0.1
 —
 0.1
Less: Other 0.1
 —
 0.1
Balance at end of period $1,558.4
 $38.2
 $1,596.6
 $1,656.6
 $39.9
 $1,696.5


 Three Months Ended June 30, 2017 Three Months Ended June 30, 2018
(in millions) ATC ATC Holdco Total ATC ATC Holdco Total
Balance at beginning of period $1,515.6
 $(2.3) $1,513.3
 $1,561.1
 $37.8
 $1,598.9
Add: Earnings (loss) from equity method investment 42.8
 (1.0) 41.8
 29.8
 (1.1) 28.7
Add: Capital contributions 15.1
 7.8
 22.9
 18.1
 1.5
 19.6
Less: Distributions 34.0
 —
 34.0
 50.7
 —
 50.7
Add: Other 0.1
 —
 0.1
Balance at end of period $1,539.5
 $4.5
 $1,544.0
 $1,558.4
 $38.2
 $1,596.6


  Six Months Ended June 30, 2019
(in millions) ATC ATC Holdco Total
Balance at beginning of period $1,625.3
 $40.0
 $1,665.3
Add: Earnings (loss) from equity method investment 73.9
 (0.9) 73.0
Add: Capital contributions 21.1
 0.8
 21.9
Less: Distributions 63.6
 —
 63.6
Less: Other 0.1
 —
 0.1
Balance at end of period $1,656.6
 $39.9
 $1,696.5



06/30/2019 Form 10-Q27WEC Energy Group, Inc.
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  Six Months Ended June 30, 2018
(in millions) ATC ATC Holdco Total
Balance at beginning of period $1,515.8
(1) 
$37.6
 $1,553.4
Add: Earnings (loss) from equity method investment 63.2
 (1.7) 61.5
Add: Capital contributions 30.1
 2.3
 32.4
Less: Distributions 50.7
(2) 
—
 50.7
Balance at end of period $1,558.4
 $38.2
 $1,596.6


(1) 
Distributions of $39.9 million, received in the first quarter of 2018, were approved and recorded as a receivable from ATC in other current assets at December 31, 2017.


(2) 
Distributions of $24.2 million, received in the third quarter of 2018, were approved and recorded as a receivable from ATC in accounts receivable at June 30, 2018.


06/30/2018 Form 10-Q22WEC Energy Group, Inc.
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  Six Months Ended June 30, 2017
(in millions) ATC ATC Holdco Total
Balance at beginning of period * $1,443.9
 $—
 $1,443.9
Add: Earnings (loss) from equity method investment 90.5
 (6.8) 83.7
Add: Capital contributions 39.2
 11.3
 50.5
Less: Distributions 34.0
 —
 34.0
Less: Other 0.1
 —
 0.1
Balance at end of period $1,539.5
 $4.5
 $1,544.0

*Distributions of $35.2 million, received in the first quarter of 2017, were approved and recorded as a receivable from ATC in other current assets at December 31, 2016.


We pay ATC for network 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. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.


The following table summarizes our significant related party transactions with ATC:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Charges to ATC for services and construction $3.3
 $4.1
 $7.3
 $8.7
Charges from ATC for network transmission services 87.0
 84.6
 174.1
 169.1
Refund from ATC related to a FERC audit —
 22.0
 —
 22.0

  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Charges to ATC for services and construction $4.1
 $3.7
 $8.7
 $7.9
Charges from ATC for network transmission services 84.6
 87.3
 169.1
 174.6
Refund from ATC related to a FERC audit 22.0
 —
 22.0
 —
Refund from ATC per FERC ROE order —
 —
 —
 28.3


Our balance sheets included the following receivables and payables relatedfor services received from or provided to ATC:
(in millions) June 30, 2019 December 31, 2018
Accounts receivable for services provided to ATC $2.3
 $3.4
Accounts payable for services received from ATC 29.0
 28.2
Amounts due from ATC for transmission infrastructure upgrades* —
 29.4

(in millions) June 30, 2018 December 31, 2017
Accounts receivable    
Services provided to ATC $1.8
 $1.5
Other current assets    
Dividends receivable from ATC 24.2
 39.9
Accounts payable    
Services received from ATC 28.2
 31.2

*In connection with UMERC's construction of the new natural gas-fired generation in the Upper Peninsula of Michigan, UMERC was required to initially fund the construction of the transmission infrastructure upgrades owned by ATC that are needed for the new generation. In the second quarter of 2019, ATC fully reimbursed UMERC for these costs.


Summarized financial data for ATC is included in the following tables:
  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2019 2018 2019 2018
Income statement data        
Operating revenues $182.2
 $165.5
 $359.9
 $330.9
Operating expenses 93.6
 91.5
 184.0
 176.4
Other expense, net 28.6
 25.4
 57.4
 53.0
Net income $60.0
 $48.6
 $118.5
 $101.5

  Three Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 2018 2017
Income statement data        
Operating revenues $165.5
 $176.6
 $330.9
 $351.3
Operating expenses 91.5
 83.0
 176.4
 165.7
Other expense, net 25.4
 25.4
 53.0
 51.5
Net income $48.6
 $68.2
 $101.5

$134.1




06/30/20182019 Form 10-Q2328WEC Energy Group, Inc.
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(in millions) June 30, 2019 December 31, 2018
Balance sheet data    
Current assets $88.8
 $87.2
Noncurrent assets 5,100.7
 4,928.8
Total assets $5,189.5
 $5,016.0
     
Current liabilities $562.1
 $640.0
Long-term debt 2,213.0
 2,014.0
Other noncurrent liabilities 294.4
 295.3
Shareholders' equity 2,120.0
 2,066.7
Total liabilities and shareholders' equity $5,189.5
 $5,016.0

(in millions) June 30, 2018 December 31, 2017
Balance sheet data    
Current assets $97.1
 $87.7
Noncurrent assets 4,764.3
 4,598.9
Total assets $4,861.4
 $4,686.6
     
Current liabilities $700.3
 $767.2
Long-term debt 1,914.3
 1,790.6
Other noncurrent liabilities 288.0
 240.3
Shareholders' equity 1,958.8
 1,888.5
Total liabilities and shareholders' equity $4,861.4
 $4,686.6


NOTE 17—19—SEGMENT INFORMATION


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


The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, WPS, and UMERC.


The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG.


The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.


•
The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.
The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.


The non-utility energy infrastructure segment includes includes:

◦We Power, which owns and leases generating facilities to WE,
◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities,
◦
Our 90% membership interest in Bishop Hill III, a wind generating facility located in Henry County, Illinois,
◦
Our 80% membership interest in Coyote Ridge, a wind generating facility under construction in Brookings County, South Dakota, and
◦
Our 80% membership interest in Upstream, a wind generating facility located in Antelope County, Nebraska.

See Note 2, Acquisitions, for more information on Bishop Hill III, Coyote Ridge, and leases generating facilities to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities.Upstream.


The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco, Wisvest LLC, Wisconsin Energy Capital Corporation, WBS,WEC Business Services LLC, and PDL. In the first quarter


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Table of 2017, we sold substantially all of the remaining assets of Bostco. See Note 3, Disposition, for more information on this sale.Contents


All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three and six months ended June 30, 20182019 and 2017:2018:
  Utility Operations          
(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Three Months Ended  
  
    
      
  
  
June 30, 2019                  
External revenues $1,253.3
 $242.9
 $68.8
 $1,565.0
 $—
 $24.3
 $0.9
 $—
 $1,590.2
Intersegment revenues —
 —
 —
 —
 —
 99.0
 —
 (99.0) —
Other operation and maintenance 363.9
 107.0
 23.4
 494.3
 —
 6.8
 1.8
 0.7
 503.6
Depreciation and amortization 152.9
 45.0
 6.7
 204.6
 —
 22.9
 6.0
 (3.6) 229.9
Operating income (loss) 270.2
 42.6
 4.6
 317.4
 —
 91.3
 (7.1) (87.0) 314.6
Equity in earnings of transmission affiliates —
 —
 —
 —
 36.9
 —
 —
 —
 36.9
Interest expense 142.7
 13.9
 1.9
 158.5
 2.7
 15.5
 36.5
 (89.1) 124.1

  Utility Operations          
(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Three Months Ended  
  
    
      
  
  
June 30, 2018                  
External revenues $1,325.5
 $268.0
 $72.4
 $1,665.9
 $—
 $3.5
 $3.1
 $—
 $1,672.5
Intersegment revenues —
 —
 —
 —
 —
 113.5
 —
 (113.5) —
Other operation and maintenance 502.4
 104.1
 24.9
 631.4
 —
 4.5
 2.2
 (100.4) 537.7
Depreciation and amortization 134.6
 41.8
 4.5
 180.9
 —
 18.3
 7.5
 —
 206.7
Operating income (loss) 195.1
 41.7
 8.1
 244.9
 —
 92.4
 (6.5) —
 330.8
Equity in earnings of transmission affiliates —
 —
 —
 —
 28.7
 —
 —
 —
 28.7
Interest expense 48.5
 12.3
 2.1
 62.9
 —
 16.0
 30.3
 (0.7) 108.5




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 Utility Operations           Utility Operations          
(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Three Months Ended  
  
    
      
  
  
June 30, 2017                  
Six Months Ended  
  
    
      
  
  
June 30, 2019                  
External revenues $1,303.2
 $253.2
 $65.7
 $1,622.1
 $—
 $6.2
 $3.2
 $—
 $1,631.5
 $2,886.7
 $779.4
 $254.0
 $3,920.1
 $—
 $44.9
 $2.6
 $—
 $3,967.6
Intersegment revenues —
 —
 —
 —
 —
 112.6
 —
 (112.6) —
 —
 —
 —
 —
 —
 206.2
 —
 (206.2) —
Other operation and maintenance * 459.7
 102.4
 23.3
 585.4
 —
 2.7
 4.3
 (112.6) 479.8
Other operation and maintenance 756.6
 235.2
 51.0
 1,042.8
 —
 10.6
 0.8
 —
 1,054.2
Depreciation and amortization 130.3
 37.5
 6.1
 173.9
 —
 17.4
 6.4
 —
 197.7
 303.9
 89.5
 13.2
 406.6
 —
 45.5
 12.4
 (8.2) 456.3
Operating income (loss) * 222.6
 43.9
 4.7
 271.2
 —
 98.7
 (7.7) —
 362.2
Operating income (loss) 632.0
 180.5
 46.1
 858.6
 —
 184.0
 (11.0) (174.2) 857.4
Equity in earnings of transmission affiliates —
 —
 —
 —
 41.8
 —
 —
 —
 41.8
 —
 —
 —
 —
 73.0
 —
 —
 —
 73.0
Interest expense 48.2
 10.9
 1.9
 61.0
 —
 15.2
 26.8
 (1.1) 101.9
 286.1
 28.7
 4.2
 319.0
 5.3
 31.2
 71.6
 (178.6) 248.5


*Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 14, Employee Benefits, for more information on this new standard.
  Utility Operations          
(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Six Months Ended  
  
    
      
  
  
June 30, 2018                  
External revenues $2,914.6
 $775.3
 $242.3
 $3,932.2
 $—
 $22.3
 $4.5
 $—
 $3,959.0
Intersegment revenues —
 —
 —
 —
 —
 212.8
 —
 (212.8) —
Other operation and maintenance 970.9
 216.3
 51.5
 1,238.7
 —
 6.2
 1.9
 (197.2) 1,049.6
Depreciation and amortization 269.7
 82.7
 11.1
 363.5
 —
 36.6
 15.2
 —
 415.3
Operating income (loss) 468.8
 189.3
 44.3
 702.4
 —
 185.4
 (11.9) —
 875.9
Equity in earnings of transmission affiliates —
 —
 —
 —
 61.5
 —
 —
 —
 61.5
Interest expense 97.9
 24.6
 4.2
 126.7
 —
 32.1
 58.3
 (1.9) 215.2



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  Utility Operations          
(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Electric Transmission Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Six Months Ended  
  
    
      
  
  
June 30, 2017                  
External revenues $2,915.3
 $778.5
 $223.6
 $3,917.4
 $—
 $12.5
 $6.1
 $—
 $3,936.0
Intersegment revenues —
 —
 —
 —
 —
 221.6
 —
 (221.6) —
Other operation and maintenance * 925.4
 222.0
 51.5
 1,198.9
 —
 3.1
 3.9
 (221.6) 984.3
Depreciation and amortization 259.6
 73.7
 12.1
 345.4
 —
 34.9
 12.0
 —
 392.3
Operating income (loss) * 552.1
 200.6
 38.2
 790.9
 —
 196.1
 (10.1) —
 976.9
Equity in earnings of transmission affiliates —
 —
 —
 —
 83.7
 —
 —
 —
 83.7
Interest expense 96.9
 22.0
 4.2
 123.1
 —
 30.5
 55.9
 (2.9) 206.6

*Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 14, Employee Benefits, for more information on this new standard.


NOTE 18—20—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.


Investment in Transmission Affiliates


We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. WeTherefore, we account for ATC as an equity method investment. The significant assetsAt June 30, 2019 and liabilities related to ATC recorded on our balance sheets wereDecember 31, 2018, our equity investment distributions receivable, and accounts payable. At June 30, 2018 and December 31, 2017, our equity investmentin ATC was $1,558.4$1,656.6 million and $1,515.8$1,625.3 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had receivables

06/30/2019 Form 10-Q31WEC Energy Group, Inc.
Table of $24.2 million and $39.9 million recorded at June 30, 2018 and December 31, 2017, respectively, for distributions from ATC. We also had $28.2 million and $31.2 million of accounts payable due to ATC at June 30, 2018 and December 31, 2017, respectively, for network transmission services.Contents



We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a variable interest entity but that consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. WeTherefore, we account for ATC Holdco as an equity method investment. The only significant asset or liability related to ATC Holdco recorded on our balance sheets wasAt June 30, 2019 and December 31, 2018, our equity investment of $38.2in ATC Holdco was $39.9 million and $37.6$40.0 million, at June 30, 2018 and December 31, 2017, respectively. Our equity investmentrespectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.


See Note 16,18, Investment in Transmission Affiliates, for more information.information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.



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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 19—21—COMMITMENTS AND CONTINGENCIES


We and our subsidiaries 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


Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities 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 non-utility energy infrastructure generation facilities have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. These projects also enter into related easements and other agreements associated with the generating facilities.

Our minimum future commitments related to these purchase obligations as of June 30, 2018,2019, including those of our subsidiaries, were $11,216.1 million.approximately $11.9 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.



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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 territories were designated as partial nonattainment: Door, 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.


Mercury and Air Toxics Standards

In December 2018, the EPA 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 CAA. As a result, under the proposed rule, the emission standards and other 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 2015,July 2019, the EPA issued a finalpublished the ACE rule, regulating GHG emissions fromwhich provides existing coal-fired generating units referred to aswith standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, and final performance standards(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 generating units and new fossil-fueled power plants. In October 2015, following publication ofThe EPA determined that the CPP, numerous states (including WisconsinBSER for new, modified, and Michigan)reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and other parties filed lawsuits challengingsubcritical steam conditions for smaller units. This proposed BSER would replace the finaldetermination from the previous 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 Appealswhich identified BSER as partial carbon capture and to the extent that further appellate review is sought, at the Supreme Court. storage.

In April 2017, pursuant to motions made by the EPA,

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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 EPA2019, we issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. The EPA is expected to issue a proposed CPP replacement rule, or decide to rescind the CPP without replacing it, during the third quarter of 2018.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs forclimate report, which analyzes our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. In addition, our new long-term goal is to reduce CO2 emissions by approximately 80% below 2005 levels by 2050. We have implemented and continue to evaluate numerous options in order to meet our CO2reduction goals. Options considered include increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of our generation reshaping plan, we expect to retire 1,800 MW of coal generation by 2020, including Pleasant Prairie power plant (retired in April 2018), PIPP, Pulliam power plant, and the jointly-owned Edgewater Unit 4 generation units. See Note 5, 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. We will continue to update this analysis as climate-change policies and relevant technologies evolve over time with a focus on preserving fuel diversity, lowering costs for customers, and reducing long-term GHG emissions.


Our plan is to work with our industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO2 emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. As a result of our generation reshaping plan, we retired approximately 1,800 MW of coal generation since the beginning of 2018. This plan included the March 31, 2019 retirement of the PIPP as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. See Note 6, Property, Plant, and Equipment, for more 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, except for Pulliam Units 7 and 8, satisfy the IM BTA requirements. WPS will retire Pulliam Units 7 and 8 on or before October 31, 2018. See Note 5, Property, Plant, and Equipment, for more information. Therefore, the WPDES permit reissued by the WDNR on June 29, 2018, will not require WPS to make alterations to the existing water intake at Pulliam Units 7 and 8. Based on the reissued WPDES permit for Weston, the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use
06/30/2019 Form 10-Q33WEC Energy Group, Inc.
Table of the unit.Contents


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, for our intake modification at Valley power plant. There has also been an interim EM BTA determination made by the WDNR as part of the reissued WPDES permitdeterminations for Weston Units 2, 3, and 4 and we intend to extrapolate these results to assess Weston Unit 2. The entrainment study and other technical information will be used by the WDNR to make a final 316(b) determination during the next five year WPDES permit term. At this time, we expect that the WDNR will conclude that the existing cooling tower systems for Weston Units 3 and 4 are BTA for both impingement and entrainment reduction. In addition, the WDNR has initially indicated that based on the low capacity utilization of Weston Unit 2, impingement mortality reduction technology will not be required and further entrainment reduction will not be necessary. Due to the retirement of Pleasant Prairie Power Plant and our plans to retire Pulliam Units 7 and 8 and PIPP, we do not believe that BTA determinations for EM will be necessary for these units.Valley power plant. Although we currently believe that existing technologies at Port Washington Generating Station 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

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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. For Pulliam Units 7address 316(b) compliance at WE and 8, in light of the pending facility retirement, the reissued WPDES permit included an interim BTA determination for the existing barrier net system. WPS, will not be required to conduct monitoring for IM or EM or to submit additional 316(b) information until the next permit renewal application in December 2022.

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


Steam Electric Effluent Limitation Guidelines


The EPA's final steam electric effluent limitation guidelines (ELG)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 WE and WPS 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 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,at WE and WPS, 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 Due to completed generating unit retirements, we believe the only facilities that would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium,require bottom ash system modifications are Weston Unit 3 and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubberOC 7 and OC 8. One wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvementssystem modification may be required for the wet FGD discharges from the six units that make up 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 systems are required by the new rule, and modifications would be required at OC 7, OC 8, and Weston Unit 3. We are beginningBased on preliminary engineering, forthe estimated rule compliance with the rule and estimatecost is approximately $70 million would be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the planned retirements of certain of our generation plants as a result of our generation reshaping plan discussed in Climate Change above.million.


Land Quality


Manufactured Gas Plant Remediation


We have identified sites at which our utilities 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. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.


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


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



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We have established the following regulatory assets and reserves related to manufactured gas plant sites:
(in millions) June 30, 2019 December 31, 2018
Regulatory assets $707.6
 $687.1
Reserves for future remediation 631.8
 616.4

(in millions) June 30, 2018 December 31, 2017
Regulatory assets $669.9
 $676.6
Reserves for future remediation 617.2
 617.2


Consent Decrees


Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam Power Plants


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

WPS will retireretired Pulliam Units 7 and 8 on or beforein October 31, 2018. See Note 5, Property, Plant,WPS also completed the mitigation projects required and Equipment, for more information aboutreceived a completeness letter from the retirement.EPA in October 2018. We have started the process to terminate the WPS Consent Decree.


Joint Ownership Power Plants Consent Decree – Columbia and Edgewater


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

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit must bewas retired byin September 30, 2018. See Note 5, Property, Plant, and Equipment, for more information about the retirement.


Enforcement and Litigation Matters


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


NOTE 20—22—SUPPLEMENTAL CASH FLOW INFORMATION
  Six Months Ended June 30
(in millions) 2018 2017
Cash (paid) for interest, net of amount capitalized $(215.6) $(209.3)
Cash (paid) received for income taxes, net (47.6) 9.5
Significant non-cash transactions    
Accounts payable related to construction costs 77.4
 155.5
Portion of Bostco real estate holdings sale financed with note receivable * —
 7.0
Amortization of deferred revenue 12.6
 12.4
  Six Months Ended June 30
(in millions) 2019 2018
Cash (paid) for interest, net of amount capitalized $(247.9) $(215.6)
Cash (paid) for income taxes, net (15.1) (47.6)
Significant non-cash investing and financing transactions:    
Accounts payable related to construction costs 137.3
 77.4
Non-cash capital contributions from noncontrolling interest 10.2
 —

*See Note 3, Disposition, for more information on this sale.



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Effective January 1, 2018, we adopted ASU 2016-18, Restricted Cash. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on theThe statements of cash flows. As a result, we no longer present transfers betweenflows include our activity related to cash, and cash equivalents, and restricted cash andcash. Our restricted cash equivalents in the statements of cash flows. Instead, changes in restricted cash are classified as either operating activities, investing activities, or financing activities.

The majority of our restricted cashprimarily consists of amountsthe cash held in the Integrys rabbi trust, which areis used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. The adoption of ASU 2016-18 resulted in an increase of $12.3 million in net cash flows used by investing activities from what was previously reported for the six months ended June 30, 2017.

See the following table for a reconciliation of cash and cash equivalents andOur restricted cash reported withinalso includes the balance sheets to the sum of the total of the same amounts shownrestricted cash we received when we acquired ownership interests in the statements of cash flows at June 30:
(in millions) 2018 2017
Cash and cash equivalents $29.8
 $36.5
Restricted cash included in other long term assets 22.2
 21.8
Cash, cash equivalents, and restricted cash $52.0
 $58.3

Effective January 1, 2018, we adopted ASU 2016-15, Classification of Certain Cash ReceiptsBishop Hill III and Cash Payments. There are eight main provisions of this ASU for which current GAAP either was unclear or did not include specific guidance. The adoption of this guidance had no impact on our financial statements for the six months ended June 30,Upstream during August 2018 and 2017.

ASU 2016-15 provides an accounting policy electionJanuary 2019, respectively. This cash is restricted as it can only be used to pay for classifying distributions received from equity method investments. We adoptedany remaining costs associated with the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities. We did not receive any excess distributions during the six months ended June 30, 2018 and 2017.

NOTE 21—REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

Our regulated utilities deferred for return to ratepayers, through future refunds, bill credits, riders, or reductions in other regulatory assets, the estimated tax benefit of $2,450 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018, is also being deferred for return to ratepayers.

We have received written orders from the PSCW and the MPSC addressing the refunding of certainconstruction of these tax benefits to ratepayers in Wisconsin and Michigan, respectively, and the ICC has approved the VITA in Illinois.wind generation facilities. See the Variable Income Tax Adjustment Rider discussion belowNote 2, Acquisitions, for more information on the Illinois rider. A summaryacquisitions of the WisconsinBishop Hill III and Michigan orders and our proposed approach in Minnesota is outlined below.Upstream.


Wisconsin

In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires WE's and WPS’s electric utility operations to use 80% and 40%, respectively, of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 20% and 60% at WE and WPS, respectively, is to be returned to electric customers in the form of bill credits. For our Wisconsin natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce certain regulatory assets for our electric utilities and is being deferred at our natural gas utilities. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes at our electric and natural gas utilities was not addressed and will be


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determined in a future rate proceeding. DuringThe following table reconciles the six months endedcash, cash equivalents, and restricted cash amounts reported within the balance sheets at June 30 2018, we reduced our regulatory assets by $46.9 million as a result of the PSCW order.
Michigan

In February 2018, the MPSC issued an order requiring Michigan utilities to make three filings related to the Tax Legislation. The firsttotal of those filings, which was filed in March 2018, prospectively addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21%. UMERC and MGU proposed providing a volumetric bill credit, subject to reconciliation and true up. In May 2018, the MPSC issued orders approving settlements that resulted in volumetric bill credits for all of UMERC's and MGU's customers effective July 1, 2018. The second filing, which was filed in July 2018, addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21% from January 1, 2018 until July 1, 2018. UMERC and MGU proposed to return the tax savings from these months to customers via volumetric bill credits over multiple months. The third filing, which is due in October 2018, will address the remaining impacts of the Tax Legislation on base rates – most notably the re-measurement of deferred tax balances. UMERC and MGU have not yet made a proposalamounts shown on the third filing.statements of cash flows:

(in millions) 2019 2018
Cash and cash equivalents $37.9
 $29.8
Restricted cash included in other long term assets 52.8
 22.2
Cash, cash equivalents, and restricted cash $90.7
 $52.0

WE, which serves one retail electric customer in Michigan, has reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addresses all base rate impacts of the Tax Legislation, which will be returned to the customer through bill credits.

MinnesotaNOTE 23—REGULATORY ENVIRONMENT

MERC is currently in an active rate case for 2018 and expects to address all aspects of the Tax Legislation, including the re-measurement of deferred tax balances, in that rate case. MERC expects that all impacts of the Tax Legislation will be incorporated into base rates when they are approved by the MPUC during its current rate proceeding.


Wisconsin Electric Power Company, Wisconsin Gas LLC, and Wisconsin Public Service Corporation


2020 and 2021 Rates

In March 2019, WE, WG, and WPS filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. The WE and WPS proposals are targeting effective electric rate increases of approximately $83 million (2.9%) and $49 million (4.9%), respectively, in 2020, and additional increases of $83 million (2.9%) and $49 million (4.9%), respectively, in 2021. For WE’s, WG’s, and WPS’s natural gas customers, the proposals are targeting effective rate increases of approximately $15 million (3.9%), $11 million (1.8%), and $7 million (2.4%), respectively, in 2020. WPS is proposing an additional effective natural gas rate increase of $7 million (2.4%) in 2021. The WE proposal also targets a $1 million (4.5%) effective increase in its steam rates in 2020. The proposals for WE, WG, and WPS reflect a ROE of 10.35%, 10.30%, and 10.35%, respectively. All three of these Wisconsin utilities proposed a common equity component average of 52.0% on a financial basis and proposed to continue having an earnings sharing mechanism through 2021.
The proposed increase in electric rates at WE was driven by higher transmission charges, recovery of SSR revenues that were assumed in WE's 2015 rate order but were not received, and an increase in costs associated with a purchased power agreement previously approved by the PSCW. WE's proposed electric rates reflect its request to partially offset these increases with approximately $111 million of previously deferred tax benefits from the Tax Legislation. WE's proposal also includes its request for approval to continue 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 remaining carrying value of the plants.
The proposed increase in electric rates at WPS was driven by the inclusion of WPS's SMRP, the Forward Wind Energy Center, and WPS's investments in two solar projects in rates, along with continued investments in system reliability and the recovery of various regulatory deferrals, including the deferral of the revenue requirement for ReACT™ costs above a previously authorized level. WPS's proposed electric rates reflect its request to use $40 million of previously deferred tax benefits from the Tax Legislation to partially offset these increases. WPS's proposal also includes its request for approval to continue collecting the carrying value of Pulliam units 7 and 8 and the Edgewater 4 generating unit using the current approved composite depreciation rates, in addition to a return on the remaining carrying value of the units.
The proposed increases at our Wisconsin natural gas utilities were driven by continued investment in our natural gas distribution systems. WPS’s proposed 2020 natural gas rate increase is net of approximately $7 million of previously deferred tax benefits from the Tax Legislation.
Final orders are expected from the PSCW by the end of 2019, with rates effective January 1, 2020.

2018 and 2019 Rates


During April 2017, WE, WG, and WPS filed an application with the PSCW for approval of a settlement agreement they made with several of their 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 electric, natural gas, and steam customers of WE, WG, and WPS. Based on the PSCW order, the authorized ROE for WE, WG, and WPS remains at 10.2%, 10.3%, and 10.0%, respectively, and the current capital cost structure for all of our Wisconsin utilities 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 at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE will flow through the tax benefit of its repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels.

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While WE would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate makingrate-making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits 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.


The agreement also allows WPS to extend through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to WPS's electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to bewas $342 million.


Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that has been in place for WE and WG since January 2016, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its 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.


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Wisconsin Public Service Corporation Proposed Solar Generation Projects


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. WE's 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.

On May 31, 2018, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar FarmI will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $260 million. The PSCW approved the acquisition of these two projects in April 2019. Commercial operation for both projects is targeted for the end of 2020.


The Peoples Gas Light and Coke Company and North Shore Gas Company


Illinois Proceedings


In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program, and issued a final order in January 2018. The order did not have a significant impact on PGL's existing SMP design and execution. An appeal related to the final order was filed by the Illinois Attorney GeneralAG in April 2018. On June 28, 2019, the Illinois Appellate Court issued its ruling affirming the ICC’s final order.


Qualifying Infrastructure Plant Rider


In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides PGL with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014.


PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2018,2019, PGL filed its 20172018 reconciliation with the ICC, which, along with the 20162017 and 20152016 reconciliations, are still pending. In February 2018,June 2019, PGL agreed to a settlement of the 20142015 reconciliation, which includes a rate base reduction of $5.4$7.0 million and a $4.7$7.3 million refund to ratepayers. The ICC approved the settlement on July 17, 2019. The settlement will not have a material impact on earnings.


As of June 30, 2018,2019, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.


Variable Income Tax Adjustment Rider

In April 2018, the ICC approved the VITA proposed by PGL and NSG. The VITA recovers or refunds changes in income tax expense resulting from differences in income tax rates and amortization of deferred tax excesses and deficiencies (in accordance with the Tax Legislation) from the amounts used in the last PGL and NSG rate case, effective January 25, 2018.

Minnesota Energy Resources Corporation

2018 Minnesota Rate Case

In October 2017, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $12.6 million (5.05%). MERC's request reflected a 10.3% ROE and a common equity component average of 50.9%. In November 2017, the MPUC approved an interim rate order, effective January 1, 2018, authorizing a retail natural gas rate increase of $9.5 million (3.78%). In March 2018, to reflect changes in MERC's effective tax rate as a result of the enactment of the Tax Legislation, the MPUC approved a $2.5 million reduction in interim retail natural gas rates to $7.0 million (2.81%), effective April 1, 2018. The interim rates reflect a 9.1% ROE and a common equity component average of 50.9%. The interim rate increase is subject to refund pending the final written rate order, which is expected in the first half of 2019.



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Minnesota Energy Resources Corporation

2018 Minnesota Rate Case

In October 2017, MERC initiated a rate proceeding with the MPUC. In December 2018, the MPUC issued a final written order for MERC. The order authorized a retail natural gas rate increase of $3.1 million (1.26%). The rates reflect a 9.7% ROE and a common equity component average of 50.9%. The final rates were implemented on July 1, 2019. The final approved rate increase was lower than the interim rates collected from customers during 2018 and through June 30, 2019. Therefore, as of June 30, 2019, we estimated that $7.6 million will be refunded to MERC's customers in September 2019.

The final order addressed the various impacts of the Tax Legislation, including the remeasurement of deferred tax balances. All of the impacts from the Tax Legislation have been included in base rates. The order also approved MERC's continued use of its decoupling mechanism for residential customers. Effective January 1, 2019, MERC's small commercial and industrial customers are no longer included in the decoupling mechanism.

Upper Michigan Energy Resources Corporation

Formation of Upper and Michigan Energy ResourcesGas Utilities Corporation


Tax Cuts and Jobs Act of 2017

In December 2016, bothFebruary 2018, the MPSC issued an order requiring Michigan utilities to make three filings related to the Tax Legislation. The first of those filings, which was filed in March 2018, prospectively addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21%. UMERC and MGU proposed providing a volumetric bill credit, subject to reconciliation and true up. In May 2018, the PSCW approvedMPSC issued orders approving settlements that resulted in volumetric bill credits for all of UMERC's and MGU's customers effective July 1, 2018. The bill credits will remain in effect until each company's next rate proceeding.

The second filing, which was filed in July 2018, addressed the operation of UMERC as a stand-alone utilityimpact on base rates for the change in tax expense resulting from the Upper Peninsula of Michigan, and UMERC became operational effectivefederal tax rate reduction from 35% to 21% from January 1, 2017. This utility holds2018 until July 1, 2018. UMERC and MGU proposed to return the electric and natural gas distribution assets, previously held by WE and WPS, locatedtax savings from these months to customers via volumetric bill credits over multiple months. The MPSC issued orders approving settlements in the Upper Peninsula of Michigan.

September 2018. In August 2016, we entered into an agreementaccordance with the Tilden Mining Company (Tilden), under which Tilden will purchase electric powersettlement orders, the savings were returned to UMERC's and MGU's customers via volumetric bill credits that were in effect from UMERC for its iron ore mine for 20 years, contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generationOctober 1, 2018 through December 31, 2018.

The third filing was filed in October 2018 and addressed the Upper Peninsula of Michigan.

In October 2017, the MPSC approved both the agreement with Tilden and UMERC's application for a certificate of necessity to begin constructionremaining impacts of the Tax Legislation on base rates – most notably the re-measurement of deferred tax balances. UMERC and MGU proposed generation. The estimated costproviding a volumetric bill credit, subject to reconciliation and true up, to return these remaining impacts of this project is $266 million ($277 million with AFUDC), 50% of which is expectedthe Tax Legislation to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers. The new units are expectedMPSC issued orders approving settlements in May 2019. The settlement orders provide for volumetric bill credits to begin commercial operation during the second quarter ofUMERC’s and MGU’s customers effective June 1, 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. TildenThe bill credits will remain a customer of WEin effect until this new generation begins commercial operation.each company's next rate proceeding.


NOTE 22—24—NEW ACCOUNTING PRONOUNCEMENTS

Leases

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


Financial Instruments Credit Losses


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




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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 diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin) and, Bluewater (which owns underground natural gas storage facilities in Michigan), a 90% ownership interest in Bishop Hill III (a wind generating facility in Illinois), and an 80% ownership interest in Upstream (a wind generating facility in Nebraska).


In December 2018, WEC Energy Group acquired an 80% ownership interest in Coyote Ridge, a 97.5 MW wind farm under construction in Brookings County, South Dakota. This wind farm is expected to be in service by the end of 2019, and is included in the non-utility energy infrastructure segment. See Note 2, Acquisitions, for more information.

Corporate Strategy


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


Reshaping Our Generation Fleet


The planned reshaping of our generation fleet 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, we set a new long-term goal of reducing CO2 emissions2030 and by approximately 80% below 2005 levels by 2050. We expect to retireretired approximately 1,800 MW of coal generation by 2020,since the beginning of 2018, and expect to add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. 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. The Edgewater 4 generating unit was retired in September 2018, the Pulliam power plant was retired in October 2018, and the Presque Isle power plant (PIPP) was retired in March 2019. See Note 5,6, Property, Plant, and Equipment, for information related to the Pleasant Prairie power plant retirement and planned retirements of certainPIPP retirement.

As part of our other coal-fueled power plants.commitment to invest in zero-carbon generation, we plan to invest in utility scale solar up to 350 MW within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm I will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the output of each project for a total of 200 MW. The Public Service Commission of Wisconsin (PSCW) approved the acquisition of these two projects in April 2019. Commercial operation for both projects is targeted for the end of 2020. Wisconsin Electric Power Company (WE) has 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 WE's 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 WE's portfolio, and allowing these larger customers to meet their sustainability and renewable energy goals.

As the cost of renewable energy generation continues to decline, both the WPS solar projects and the WE pilots have become cost effective opportunities for WEC Energy Group and our customers to participate in renewable energy.

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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, as the most reliable utility in the Midwest.row.


Below are a few examples of reliability projects that were recently completed or are currently underway.


Upper Michigan Energy Resources Corporation (UMERC), our Michigan electric and natural gas utility, is moving forward withhas completed its long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan callscalled for UMERC to construct and operate approximately 180 MW of natural gas-fueled generation located in the Upper Peninsula. The new generation is expected to achieveachieved commercial operation during the second quarter ofon March 31, 2019, and provideis providing the region with affordable, reliable electricity that generates less emissions than the Presque Isle power plant (PIPP). In accordancePIPP. Consistent with a written approval letter received from the Midcontinent Independent System Operator, we must retirethe PIPP by Maywas retired on March 31, 2019.


The Peoples Gas Light and Coke Company continues to work on its Natural Gas System Modernization Program, which primarily involves replacing old cast and ductile iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.


Wisconsin Public Service Corporation (WPS)WPS continues work on its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing

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facilities to improve the reliability of electric service WPS provides to its customers. WPS, Wisconsin Electric Power CompanyWE, and Wisconsin Gas LLC also continue to upgrade their electric and natural gas distribution systems to enhance reliability.


Operating Efficiency


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


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


Financial Discipline


A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, 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, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.
See Note 2, Acquisitions, for information about our acquisitions of natural gas storage facilities in Michigan and portions of wind energy generation facilities in Wisconsin, Illinois, and Nebraska.

See Note 3, Disposition, for information on the sale of Bostco LLC's real estate holdings.

•
See Note 2, Acquisitions, for information about our acquisitions of portions of wind energy generation facilities in Wisconsin, Illinois, Nebraska, and South Dakota.
•
See Note 3, Disposition, for information on the sale of certain WPS Power Development, LLC solar power generation facilities.
Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be almost $12$12.7 billion from 20182019 to 2022.2023. Specific projects are discussed in more detail below under Liquidity and Capital Resources.



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From 20182019 to 2022,2023, we expect capital contributions to ATC and ATC Holdco to be approximately $280$250 million. ATC Holdco is a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. Capital investments at ATC and ATC Holdco will be funded utilizing these capital contributions, in addition to cash generated from operations and debt. We currently forecast that our share of ATC's and ATC Holdco's projected capital expenditures over the next five years will be $1.3$1.2 billion inside the traditional ATC footprint and $300$250 million outside of the traditional ATC footprint.


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, through which employees of our utility subsidiaries 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. Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.




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RESULTS OF OPERATIONS


THREE MONTHS ENDED 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, except per share data) 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)
Wisconsin $195.1
 $222.6
 $(27.5) $(30.9) $(19.2) $22.6
 $270.2
 $195.1
 $75.1
 $(11.1) $87.9
 $(1.7)
Illinois 41.7
 43.9
 (2.2) —
 (3.2) 1.0
 42.6
 41.7
 0.9
 —
 —
 0.9
Other states 8.1
 4.7
 3.4
 —
 (0.6) 4.0
 4.6
 8.1
 (3.5) —
 —
 (3.5)
Non-utility energy infrastructure 92.4
 98.7
 (6.3) —
 (12.6) 6.3
 91.3
 92.4
 (1.1) —
 —
 (1.1)
Corporate and other (6.5) (7.7) 1.2
 —
 —
 1.2
 (7.1) (6.5) (0.6) —
 —
 (0.6)
Reconciling eliminations * (87.0) —
 (87.0) —
 (87.0) —
Total operating income 330.8
 362.2
 (31.4) (30.9) (35.6) 35.1
 314.6
 330.8
 (16.2) (11.1) 0.9
 (6.0)
Equity in earnings of transmission affiliates 28.7
 41.8
 (13.1) —
 (9.4) (3.7) 36.9
 28.7
 8.2
 —
 —
 8.2
Other income, net 31.4
 13.1
 18.3
 —
 —
 18.3
 23.6
 31.4
 (7.8) —
 —
 (7.8)
Interest expense 108.5
 101.9
 (6.6) —
 —
 (6.6) 124.1
 108.5
 (15.6) —
 (0.9) (14.7)
Income before income taxes 282.4
 315.2
 (32.8) (30.9) (45.0) 43.1
 251.0
 282.4
 (31.4) (11.1) —
 (20.3)
Income tax expense 51.1
 115.8
 64.7
 30.9
 41.4
 (7.6) 15.2
 51.1
 35.9
 11.1
 —
 24.8
Preferred stock dividends of subsidiary 0.3
 0.3
 —
 —
 —
 —
 0.3
 0.3
 —
 —
 —
 —
Net loss attributed to noncontrolling interests 0.2
 —
 0.2
 —
 —
 0.2
Net income attributed to common shareholders $231.0
 $199.1
 $31.9
 $—
 $(3.6) $35.5
 $235.7
 $231.0
 $4.7
 $—
 $—
 $4.7
                        
Diluted earnings per share $0.73
 $0.63
 $0.10
       $0.74
 $0.73
 $0.01
      


*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, $87.0 million of minimum lease payments that were billed from We Power to WE were no longer classified within operation and maintenance, but were instead recorded as interest expense in accordance with Topic 842. The We Power lease does not impact our financial statements as all amounts associated with the lease are eliminated at the consolidated level.

Earnings increased $31.9$4.7 million during the second quarter of 2018,2019, compared with 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 Topic 842, effective January 1, 2019. As shown in the table above, the changes related to these items did not have a significanthad no impact on net income attributed to common shareholders. See Note 10, Income Taxes, and Note 21,23, Regulatory Environment, for more information.information on the flow through of tax repairs and Note 10, Leases, for more information on the adoption of Topic 842.


The significant factors impacting the remaining$4.7 million increase in earnings were:


•
A $24.8 million remaining decrease in income tax expense, primarily driven by impacts from the Tax Legislation, lower income before income taxes, an increase in wind production tax credits related to recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment, and the recognition of deferred investment tax credits related to the sale of certain PDL solar power generation facilities completed during the second quarter of 2019.

•
An $8.2 million increase in earnings from our ownership interests in transmission affiliates, primarily due to continued capital investment by ATC and the impact of the refund ATC was required to provide customers in the second quarter of 2018 as a result of the FERC financial audit completed in February 2018.
A $22.6 million pre-tax ($16.4 million after tax) remaining increase in operating income at the Wisconsin segment. The increase was driven by higher electric and natural gas margins, which were primarily due to higher retail sales volumes as a result of favorable weather and higher weather-normalized use per customer.
An $18.3 million pre-tax ($13.3 million after tax) increase in other income, net, driven by the timing of the recognition of returns related to certain regulatory assets and higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 14, Employee Benefits, for more information on our benefit costs.

A $6.3 million pre-tax ($4.6 million after tax) remaining increase in operating income at the non-utility energy infrastructure segment, driven by the inclusion of the operations of Bluewater following its acquisition on June 30, 2017.

These increases in earnings were partially offset by a $6.6 million pre-tax ($4.8 million after tax) increase in interest expense, driven by higher short-term debt balances, primarily used to fund capital investments, and higher interest rates on short-term debt.



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These increases in earnings were partially offset by:

•
A $14.7 million remaining increase in interest expense, driven by higher debt balances, primarily used to fund capital investments, and higher interest rates on short-term debt.

•
A $7.8 million decrease in other income, net, primarily driven by a 2018 item that was offset in other operation and maintenance expense and lower gains on the investments held in the Integrys rabbi trust. The gains from the investments held in the rabbi trust partially offset benefits costs related to deferred compensation included in operating income. See Note 13, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

•
A $3.5 million decrease in operating income at the other states segment, driven by lower natural gas margins primarily due to the timing of interim rate recognition at MERC in 2018.

Non-GAAP Financial MeasureMeasures


The discussions below address the operating income contribution of each of our segments and include 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 segments 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 segment operating performance. Operating income for the second quarter of 20182019 and 20172018 for each of our segments is presented in the “Consolidated Earnings” table above.


Each applicable segment operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to segment operating income.


Wisconsin Segment Contribution to Operating Income
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Electric revenues $1,087.5
 $1,090.7
 $(3.2) $1,024.4
 $1,087.5
 $(63.1)
Fuel and purchased power 328.2
 345.0
 16.8
 310.7
 328.2
 17.5
Total electric margins 759.3
 745.7
 13.6
 713.7
 759.3
 (45.6)
            
Natural gas revenues 238.0
 212.5
 25.5
 228.9
 238.0
 (9.1)
Cost of natural gas sold 124.9
 105.1
 (19.8) 116.4
 124.9
 8.5
Total natural gas margins 113.1
 107.4
 5.7
 112.5
 113.1
 (0.6)
            
Total electric and natural gas margins 872.4
 853.1
 19.3
 826.2
 872.4
 (46.2)
            
Other operation and maintenance 502.4
 459.7
 (42.7) 363.9
 502.4
 138.5
Depreciation and amortization 134.6
 130.3
 (4.3) 152.9
 134.6
 (18.3)
Property and revenue taxes 40.3
 40.5
 0.2
 39.2
 40.3
 1.1
Operating income $195.1
 $222.6
 $(27.5) $270.2
 $195.1
 $75.1



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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 $188.4
 $189.8
 $1.4
 $154.9
 $188.4
 $33.5
We Power (1)
 125.9
 127.1
 1.2
 34.2
 125.9
 91.7
Transmission (2)
 104.5
 106.1
 1.6
 103.6
 104.5
 0.9
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)
 36.1
 36.7
 0.6
 37.2
 36.1
 (1.1)
Earnings sharing mechanisms (6)
 3.7
 —
 (3.7) —
 3.7
 3.7
Total other operation and maintenance $502.4
 $459.7
 $(42.7) $363.9
 $502.4
 $138.5


(1) 
Represents costs associated with the We Power generation units, including operating and maintenance costs incurredrecognized by WE, as well asWE. For the three months ended June 30, 2018, the amount also included the lease payments that arewere billed from We Power to WE and then recovered in WE's 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 with WE 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. The We Power lease does not impact our financial statements as all amounts associated with the lease are eliminated at the consolidated level.

During the three months ended June 30, 2019, $45.6 million of operating and maintenance costs were billed to or incurred by WE 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, $126.1 million of both lease and 2017,operating and maintenance costs were billed to or incurred by WE 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.

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$126.1 million and $139.2 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, 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 ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS 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, $97.3$119.5 million and $118.6$97.3 million, respectively, of costs were billed by transmission providers to our electric utilities.utilities by transmission providers.


(3) 
Represents additional transmission expense associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. See Note 21,23, Regulatory Environment, for more information.


(4) 
As a result ofRepresents additional transmission expense associated with the May 2018 PSCW order requiring WE to use 80% of its current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce its transmission regulatory asset balance, our transmission expense increased during the second quarter of 2018 with a corresponding offset in income taxes. See Note 21, 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.


(6) 
See Note 21,23, Regulatory Environment, for more information about our earnings sharing mechanisms.



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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 2,565.6
 2,455.2
 110.4
 2,336.8
 2,565.6
 (228.8)
Small commercial and industrial * 3,221.0
 3,113.6
 107.4
 3,054.8
 3,221.0
 (166.2)
Large commercial and industrial * 3,263.3
 3,224.4
 38.9
 3,155.1
 3,263.3
 (108.2)
Other 38.1
 39.9
 (1.8) 39.2
 38.1
 1.1
Total retail * 9,088.0
 8,833.1
 254.9
 8,585.9
 9,088.0
 (502.1)
Wholesale 875.9
 933.7
 (57.8) 820.8
 875.9
 (55.1)
Resale 793.1
 1,240.6
 (447.5) 1,789.2
 793.1
 996.1
Total sales in MWh * 10,757.0
 11,007.4
 (250.4) 11,195.9
 10,757.0
 438.9


*Includes distribution sales for customers who purchased power from an alternative electric supplier in Michigan.
 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 169.5
 135.4
 34.1
 170.7
 169.5
 1.2
Commercial and industrial 121.9
 91.8
 30.1
 108.1
 121.9
 (13.8)
Total retail 291.4
 227.2
 64.2
 278.8
 291.4
 (12.6)
Transport 322.2
 293.6
 28.6
 320.9
 322.2
 (1.3)
Total sales in therms 613.6
 520.8
 92.8
 599.7
 613.6
 (13.9)


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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)
WE and WG (1)
            
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)%
            
WPS (2)
            
Heating (937 normal) 1,081
 834
 29.6%
Cooling (133 normal) 215
 125
 72.0%
Heating (951 normal) 1,040
 1,081
 (3.8)%
Cooling (136 normal) 78
 215
 (63.7)%
            
UMERC (3)
            
Heating (1,166 normal) 1,206
 1,141
 5.7%
Cooling (77 normal) 138
 47
 193.6%
Heating (1,178 normal) 1,333
 1,206
 10.5 %
Cooling (79 normal) 49
 138
 (64.5)%


(1) 
Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.


(2) 
Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.


(3) 
Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.



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Electric Utility Margins


Electric utility margins at the Wisconsin segment increased $13.6decreased $45.6 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 $33.9 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% and 63.7% cooler than the same quarter in 2018 in the Milwaukee area and Green Bay area, respectively. As measured by heating degree days, the second quarter of 2019 was 4.9% and 3.8% warmer than the same quarter in 2018 in the Milwaukee area and Green Bay area, respectively.

A $17.4$23.5 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, with a corresponding increaseother regulatory assets. This decrease in margins was offset by the net impact of $16.3 million decrease in transmission expense, as a result of$12.3 million decrease in income taxes, and a $5.1 million increase in depreciation and amortization expense. We received the PSCW'sPSCW order in May 2018, associated with the Tax Legislation. The PSCW orderwhich required WE and WPS to applyuse 80% and 40%, respectively, of itsthe current 2018 and 2019 tax benefit against its 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 bill credits and instead applied the tax savings by reducing the regulatory assets.

•
A $4.6 million decrease in margins associated with WE's flow through of tax benefits of its 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 23, Regulatory Environment, for more information.

These decreases in margins were partially offset by a result of the order. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.

A $15.7 million increase related to higher retail sales volumes during the second quarter of 2018, primarily driven by favorable weather and higher overall use per retail customer. A colder than normal April and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the second quarter of 2018 was 36.8% and 29.6% colder than the same quarter in 2017 in the Milwaukee area and Green Bay area, respectively. As measured by cooling degree days, the second quarter of 2018 was 6.9% and 72.0% warmer than the same quarter in 2017 in the Milwaukee area and Green Bay area, respectively.

A $3.1$14.1 million quarter-over-quarter positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

These increases in margins were partially offset by:

A $20.9 million decrease in margins related to a settlement agreement with the PSCW to flow through the tax benefit of WE's repair-related deferred tax liabilities through reductions in certain regulatory assets, which are amortized to revenues, as discussed in Note 21, Regulatory Environment.

A $3.7 million decrease in wholesale margins driven both by lower sales volumes at WPS and reduced capacity rates at WE and WPS reflecting the Tax Legislation.


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Natural Gas Utility Margins


Natural gas utility margins at the Wisconsin segment increased $5.7decreased $0.6 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 $10.7 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 $5.6 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.2018.


Operating Income


Operating income at the Wisconsin segment decreased $27.5increased $75.1 million during the second quarter of 2018,2019, compared with the same quarter in 2017.2018. This decreaseincrease was driven by $46.8$121.3 million of higherlower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $19.3$46.2 million of higherdecrease in margins discussed above.


The significant factors impacting the increasedecrease in operating expenses during the second quarter of 2018,2019, compared with the same quarter in 2017,2018, were:


A $33.8$90.6 million increasedecrease in transmission expense, with a corresponding offset in income taxes, associated with the May 2018 orderother operation and maintenance resulting from the PSCWadoption 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 WE to change the income statement classification of its lease payments related to the benefits associatedWe Power leases. For the second quarter of 2019, the minimum lease payments that were billed from We Power to WE were no longer classified within other operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with the Tax Legislation, as discussed in the table above.Topic 842.


•
A $16.7 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, Edgewater Unit 4 in September 2018, Pulliam Units 7 and 8 in October 2018, and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the second quarter of 2019. See Note 6, Property, Plant, and Equipment, for more information on the retirement of the PIPP.

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A $10.0$9.9 million increasedecrease in transmissionoperation and maintenance expense relateddue to a 2018 item that was offset in other income, net and had no impact on net income for the flow through of tax repairs,quarter.

•
A $9.8 million net decrease in transmission expense. This was 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.

•
A $3.7 million decrease in operation and maintenance expense related to the earnings sharing mechanism in place at WG. See Note 23, Regulatory Environment, for more information.

These decreases in the table above.

A $4.3operating expenses were partially offset by an $18.3 million increase in depreciation and amortization, driven by capital expenditures as we continue to execute on our capital plan, an overall increase in utility plant in service, WBS's transfer of an information technology project to WPS in June 2017, and the implementation of an enterprise resource planning system in January 2018. This increase in depreciation and amortization was partially offset by a decrease related to the reduction of certain WPS regulatory deferralsassets as a result of the PSCW's May 2018 order addressing the Tax Legislation.

A $3.9 million increase in benefit costs.

A $3.7 million increase in expensesLegislation, and additional expense recognized related to the earnings sharing mechanismadoption of Topic 842, as discussed in place at WG. See Note 21, Regulatory Environment, for more information.
the other operation and maintenance table above.

These increases in operating expenses were partially offset by:

A $5.0 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 other expected plant retirements. This resulted in lower maintenance and labor costs during the second quarter of 2018. See Note 5, Property, Plant, and Equipment, for more information on the plant retirements.

A $4.4 million decrease in electric and natural gas distribution expenses, primarily related to lower expenses incurred related to storm damage during the second quarter of 2018.


Illinois Segment Contribution to Operating Income

Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Natural gas revenues $268.0
 $253.2
 $14.8
 $242.9
 $268.0
 $(25.1)
Cost of natural gas sold 75.3
 64.1
 (11.2) 42.8
 75.3
 32.5
Total natural gas margins 192.7
 189.1
 3.6
 200.1
 192.7
 7.4
            
Other operation and maintenance 104.1
 102.4
 (1.7) 107.0
 104.1
 (2.9)
Depreciation and amortization 41.8
 37.5
 (4.3) 45.0
 41.8
 (3.2)
Property and revenue taxes 5.1
 5.3
 0.2
 5.5
 5.1
 (0.4)
Operating income $41.7
 $43.9
 $(2.2) $42.6
 $41.7
 $0.9


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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 the line items below $85.7
 $82.1
 $(3.6) $91.5
 $85.7
 $(5.8)
Riders * 18.1
 19.4
 1.3
 15.6
 18.1
 2.5
Regulatory amortizations * (0.4) 0.5
 0.9
 (0.3) (0.4) (0.1)
Other 0.7
 0.4
 (0.3) 0.2
 0.7
 0.5
Total other operation and maintenance $104.1
 $102.4
 $(1.7) $107.0
 $104.1
 $(2.9)


*These riders and regulatory amortizations 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 salesdelivered volumes by customer class and weather statistics:
 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 138.4
 108.6
 29.8
 126.7
 138.4
 (11.7)
Commercial and industrial 59.5
 51.8
 7.7
 57.4
 59.5
 (2.1)
Total retail 197.9
 160.4
 37.5
 184.1
 197.9
 (13.8)
Transport 169.1
 141.4
 27.7
 141.0
 169.1
 (28.1)
Total sales in therms 367.0
 301.8
 65.2
 325.1
 367.0
 (41.9)


 Three Months Ended June 30 Three Months Ended June 30
 Degree Days Degree Days
Weather * 2018 2017 B (W) 2019 2018 B (W)
Heating (689 Normal) 836
 602
 38.9%
Heating (710 Normal) 771
 836
 (7.8)%


*Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.


Natural Gas Utility Margins


Natural gas utility margins at the Illinois segment, net of the $1.3$2.5 million impact of the riders referenced in the table above, increased $4.9$9.9 million during the second quarter of 2018,2019, compared with the same quarter in 2017,2018, driven by ana $7.2 million increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. This increase was partially offset by a $3.2 million decrease in margins related to amounts being returned to customers through the VITA in connection with the Tax Legislation signed into law in December 2017. See Note 10, Income Taxes, and Note 21,23, Regulatory Environment, for more information.


Operating Income


Operating income at the Illinois segment decreased $2.2increased $0.9 million during the second quarter of 2018,2019, compared with the same quarter in 2017.2018. This decreaseincrease was due to a $7.1primarily driven by the $9.9 million net increase in margins discussed above. This increase in margins was partially offset by $9.0 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenuesrevenue taxes), net of the impact of the riders referenced in the table above, partially offset byabove.

The significant factors impacting the $4.9 million net increase in margins discussed above. The increase in operating expenses wasduring the second quarter of 2019, compared with the same quarter in 2018 were:

A $3.6 million increase in natural gas maintenance costs, primarily due to the continuation of maintenance work resulting from colder than normal weather in the first quarter of 2019.

A $3.5 million increase in benefit costs, primarily related to deferred compensation.

A $3.2 million increase in depreciation expense, primarily driven by higher depreciation expense at PGL primarily due toPGL's continued capital investment in the SMP project.




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Other States Segment Contribution to Operating Income
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018
2017 B (W) 2019
2018 B (W)
Natural gas revenues $72.4
 $65.7
 $6.7
 $68.8
 $72.4
 $(3.6)
Cost of natural gas sold 31.0
 27.4
 (3.6) 29.9
 31.0
 1.1
Total natural gas margins 41.4
 38.3
 3.1
 38.9
 41.4
 (2.5)
     

     

Other operation and maintenance 24.9
 23.3
 (1.6) 23.4
 24.9
 1.5
Depreciation and amortization 4.5
 6.1
 1.6
 6.7
 4.5
 (2.2)
Property and revenue taxes 3.9
 4.2
 0.3
 4.2
 3.9
 (0.3)
Operating income $8.1
 $4.7
 $3.4
 $4.6
 $8.1
 $(3.5)


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 item below $18.9
 $18.2
 $(0.7) $18.9
 $18.9
 $—
Regulatory amortizations and other pass through expenses * 6.0
 5.1
 (0.9) 4.5
 6.0
 1.5
Total other operation and maintenance $24.9
 $23.3
 $(1.6) $23.4
 $24.9
 $1.5


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


The following tables provide information on sales volumes by customer class and weather statistics:
 Three Months Ended 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 47.0
 39.6
 7.4
 47.8
 47.0
 0.8
Commercial and industrial 31.3
 27.7
 3.6
 33.1
 31.3
 1.8
Total retail 78.3
 67.3
 11.0
 80.9
 78.3
 2.6
Transport 168.1
 167.6
 0.5
 174.8
 168.1
 6.7
Total sales in therms 246.4
 234.9
 11.5
 255.7
 246.4
 9.3


 Three Months Ended June 30 Three Months Ended June 30
 Degree Days Degree Days
Weather * 2018 2017 B (W) 2019 2018 B (W)
MERC            
Heating (927 Normal) 1,064
 886
 20.1%
Heating (942 Normal) 1,074
 1,064
 0.9 %
            
MGU   

     

  
Heating (775 Normal) 858
 667
 28.6%
Heating (768 Normal) 805
 858
 (6.2)%


*Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective service territories.


Natural Gas Utility Margins


Natural gas utility margins increased $3.1decreased $2.5 million during the second quarter of 2018,2019, compared to the same quarter last year. The increasedecrease was primarily driven by a colder than normal Aprillower natural gas margins related to the timing of recognition of interim rates at MERC in 2018 as well as the MERC interim rate increase. See Note 21, Regulatory Environment, for more information on the interim rate increase.2018.




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Operating Income


Operating income at the other states segment increased $3.4decreased $3.5 million during the second quarter of 2018,2019, compared to the same quarter last year. This increasedecrease was driven by the $3.1$2.5 million increasedecrease in margins discussed above, andas well as a $0.3$1.0 million decreaseincrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenuesrevenue taxes). The decreaseincrease in operating expenses is primarily due to the positive impact on 2018 depreciation and amortization expense reflects the impact of a new depreciation study approved by the MPUC in the second quarter of 2018. TheThese rates were effective retroactive to January 2017.


Non-Utility Energy Infrastructure Segment Contribution to Operating Income
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Operating income $92.4
 $98.7
 $(6.3) $91.3
 $92.4
 $(1.1)

Operating income at the non-utility energy infrastructure segment decreased $6.3 million during the second quarter of 2018, compared with the same quarter in 2017. The decrease was driven by a $12.6 million decrease in revenue related to the Tax Legislation signed into law in December 2017. As a result of the Tax Legislation, the lease payments charged by We Power to WE were reduced. The reduction in the lease payments was offset by a decrease in income tax expense, resulting in no impact on net income. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information. Partially offsetting the impact of the Tax Legislation was a $5.7 million contribution to operating income from Bluewater during the second quarter of 2018. Bluewater was acquired on June 30, 2017. See Note 2, Acquisitions, for more information.


Corporate and Other Segment Contribution to Operating Income
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Operating loss $(6.5) $(7.7) $1.2
 $(7.1) $(6.5) $(0.6)


Electric Transmission Segment Operations
 Three Months Ended June 30 Three Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Equity in earnings of transmission affiliates $28.7
 $41.8
 $(13.1) $36.9
 $28.7
 $8.2


Earnings from our ownership interests in transmission affiliates decreased $13.1increased $8.2 million during the second quarter of 2018,2019, compared with the same quarter in 2017,2018, primarily due to the Tax Legislation signed into law in December 2017. The $9.4 million decrease in our equity earnings from the Tax Legislation did not affect our net income as it was offsetcontinued capital investment by an equal reduction in our income tax expense. See Note 10, Income Taxes,and Note 21, Regulatory Environment, for more information.ATC. Also contributing to the decreaseincrease in our equity earnings was the impact of the refund ATC was required to provide customers in the second quarter of 2018 as a result of the FERC financial audit completed in February 2018.


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 $3.7
 $2.9
 $0.8
 $2.4
 $3.7
 $(1.3)
Non-service components of net periodic benefit costs 9.6
 5.3
 4.3
Other, net 27.7
 10.2
 17.5
 11.6
 22.4
 (10.8)
Other income, net $31.4
 $13.1
 $18.3
 $23.6
 $31.4
 $(7.8)


Other income, net increased $18.3decreased $7.8 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 ofquarter. Additionally, lower gains on the recognition of returnsinvestments held in the Integrys rabbi trust also contributed to the decrease. These investment gains partially offset benefits costs related to certain regulatory assets anddeferred compensation included in operating income. See Note 13, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

These decreases in other income, net were partially offset by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 14,16, Employee Benefits, for more information on our benefitpension and OPEB costs.



Consolidated Interest Expense
  Three Months Ended June 30
(in millions) 2019 2018 B (W)
Interest expense $124.1
 $108.5
 $(15.6)


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Consolidated Interest Expense
  Three Months Ended June 30
(in millions) 2018 2017 B (W)
Interest expense $108.5
 $101.9
 $(6.6)


Interest expense increased $6.6$15.6 million during the second quaterquarter of 2018,2019, compared with the same quarter in 2017,2018, primarily due to higher short-term debt balances and higher interest rates on short-term debt. ThisThe increase in debt balances is primarily related to continued capital investments.


Consolidated Income Tax Expense
  Three Months Ended June 30
  2018 2017 B (W)
Effective tax rate 18.1% 36.7% 18.6%
  Three Months Ended June 30
  2019 2018 B (W)
Effective tax rate 6.1% 18.1% 12.0%
 
Our effective tax rate decreased by 18.6%12.0% when compared with the second quarter of 2017,2018, primarily due to the impact of the Tax Legislation. Contributing 8.0% to the decrease in the effective tax rate isincreased benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease was the impact of the Tax Legislation, an increase in wind production tax credits related to recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment, and the recognition of deferred investment tax credits related to the sale of certain PDL solar power generation facilities completed during the second quarter of 2019. See Note 10,3, Disposition, Note 12, Income Taxes, and Note 21,23, Regulatory Environment, for more information.


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, except per share data) 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)
Wisconsin $468.8
 $552.1
 $(83.3) $(66.0) $(70.1) $52.8
 $632.0
 $468.8
 $163.2
 $(16.7) $176.0
 $3.9
Illinois 189.3
 200.6
 (11.3) —
 (19.1) 7.8
 180.5
 189.3
 (8.8) —
 —
 (8.8)
Other states 44.3
 38.2
 6.1
 —
 (6.1) 12.2
 46.1
 44.3
 1.8
 —
 —
 1.8
Non-utility energy infrastructure 185.4
 196.1
 (10.7) —
 (25.2) 14.5
 184.0
 185.4
 (1.4) —
 —
 (1.4)
Corporate and other (11.9) (10.1) (1.8) —
 —
 (1.8) (11.0) (11.9) 0.9
 —
 —
 0.9
Reconciling eliminations * (174.2) —
 (174.2) —
 (174.2) —
Total operating income 875.9
 976.9
 (101.0) (66.0) (120.5) 85.5
 857.4
 875.9
 (18.5) (16.7) 1.8
 (3.6)
Equity in earnings of transmission affiliates 61.5
 83.7
 (22.2) —
 (20.1) (2.1) 73.0
 61.5
 11.5
 —
 —
 11.5
Other income, net 38.9
 31.4
 7.5
 —
 —
 7.5
 54.5
 38.9
 15.6
 —
 —
 15.6
Interest expense 215.2
 206.6
 (8.6) —
 —
 (8.6) 248.5
 215.2
 (33.3) —
 (1.8) (31.5)
Income before income taxes 761.1
 885.4
 (124.3) (66.0) (140.6) 82.3
 736.4
 761.1
 (24.7) (16.7) —
 (8.0)
Income tax expense 139.4
 329.1
 189.7
 66.0
 133.4
 (9.7) 80.2
 139.4
 59.2
 16.7
 —
 42.5
Preferred stock dividends of subsidiary 0.6
 0.6
 —
 —
 —
 —
 0.6
 0.6
 —
 —
 —
 —
Net loss attributed to noncontrolling interests 0.2
 —
 0.2
 —
 —
 0.2
Net income attributed to common shareholders $621.1
 $555.7
 $65.4
 $—
 $(7.2) $72.6
 $655.8
 $621.1
 $34.7
 $—
 $—
 $34.7
     

           

      
Diluted Earnings Per Share
 $1.96
 $1.75
 $0.21
       $2.07
 $1.96
 $0.11
      


*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 six months ended June 30, 2019, $174.2 million of minimum lease payments that were billed from We Power to WE were no longer classified within operation and maintenance, but were instead recorded as interest expense in accordance with Topic 842. The We Power lease does not impact our financial statements as all amounts associated with the lease are eliminated at the consolidated level.


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Earnings increased $65.4$34.7 million during the six months ended June 30, 2018,2019, compared with 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 Topic 842, effective January 1, 2019. As shown in the table above, the changes related to these items did not have a significanthad no impact on net income attributed to common shareholders. See Note 10, Income Taxes, and Note 21,23, Regulatory Environment, for more information.information on the flow through of tax repairs and Note 10, Leases, for more information on the adoption of Topic 842.


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The significant factors impacting the remaining$34.7 million increase in earnings were:


•
A $42.5 million remaining decrease in income tax expense, primarily due to an increase in wind production tax credits related to recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment, the impact of the Tax Legislation, the recognition of deferred investment tax credits related to the sale of certain PDL solar power generation facilities completed during the second quarter of 2019, and lower income before income taxes.

•
A $15.6 million increase in other income, net, driven by higher gains on the investments held in the Integrys rabbi trust and higher net credits from the non-service components of our net periodic pension and OPEB costs. The gains on the investments held in the rabbi trust partially offset benefits costs related to deferred compensation included in operating income. See Note 13, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust, and Note 16, Employee Benefits, for more information on our pension and OPEB costs.
A $52.8 million pre-tax ($38.3 million after tax) remaining increase in operating income at the Wisconsin segment. The increase was driven by higher electric and natural gas margins, which were primarily due to higher retail sales volumes as a result of favorable weather and higher weather-normalized use per customer.
•
An $11.5 million increase in earnings from our ownership interests in transmission affiliates, primarily due to continued capital investment by ATC and the impact of the refund ATC was required to provide customers in the second quarter of 2018 as a result of the FERC financial audit completed in February 2018.

A $14.5 million pre-tax ($10.5 million after tax) remaining increase in operating income at the non-utility energy infrastructure segment, primarily driven by the inclusion of the operations of Bluewater following its acquisition on June 30, 2017.

A $12.2 million pre-tax ($8.8 million after tax) remaining increase in operating income at the other states segment. The increase was driven by higher natural gas margins, which were primarily a result of the colder winter weather in 2018 as well as customer growth.

A $7.8 million pre-tax ($5.7 million after tax) remaining increase in operating income at the Illinois segment. The increase was driven by higher natural gas margins at PGL due to continued capital investment in the SMP project under its QIP rider.


These increases in earnings were partially offset by an $8.6a $31.5 million pre-tax ($6.2 million after tax)remaining increase in interest expense. The increase in interest expense was driven by higher short-term debt balances, primarily used to fund capital investments, and higher interest rates on short-term debt.


Non-GAAP Financial MeasureMeasures


The discussions below address the operating income contribution of each of our segments and include 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 segments 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 segment operating performance. Operating income for the six months ended June 30, 20182019 and 20172018 for each of our segments is presented in the “Consolidated Earnings” table above.


Each applicable segment operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to segment operating income.




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Wisconsin Segment Contribution to Operating Income
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Electric revenues $2,156.6
 $2,206.0
 $(49.4) $2,091.0
 $2,156.6
 $(65.6)
Fuel and purchased power 680.5
 695.5
 15.0
 649.5
 680.5
 31.0
Total electric margins 1,476.1
 1,510.5
 (34.4) 1,441.5
 1,476.1
 (34.6)
 

 

 

 

 

 

Natural gas revenues 758.0
 709.3
 48.7
 795.7
 758.0
 37.7
Cost of natural gas sold 444.6
 401.7
 (42.9) 469.0
 444.6
 (24.4)
Total natural gas margins 313.4
 307.6
 5.8
 326.7
 313.4
 13.3
     

     

Total electric and natural gas margins 1,789.5
 1,818.1
 (28.6) 1,768.2
 1,789.5
 (21.3)
            
Other operation and maintenance 970.9
 925.4
 (45.5) 756.6
 970.9
 214.3
Depreciation and amortization 269.7
 259.6
 (10.1) 303.9
 269.7
 (34.2)
Property and revenue taxes 80.1
 81.0
 0.9
 75.7
 80.1
 4.4
Operating income $468.8
 $552.1
 $(83.3) $632.0
 $468.8
 $163.2


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 $365.4
 $379.5
 $14.1
 $331.0
 $365.4
 $34.4
We Power (1)
 253.1
 254.7
 1.6
 70.1
 253.1
 183.0
Transmission (2)
 209.2
 210.0
 0.8
 209.4
 209.2
 (0.2)
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)
 81.0
 81.2
 0.2
 81.6
 81.0
 (0.6)
Earnings sharing mechanism (6)
 3.7
 —
 (3.7) —
 3.7
 3.7
Total other operation and maintenance $970.9
 $925.4
 $(45.5) $756.6
 $970.9
 $214.3


(1) 
Represents costs associated with the We Power generation units, including operating and maintenance costs incurredrecognized by WE, as well asWE. For the six months ended June 30, 2018, the amount also included the lease payments that arewere billed from We Power to WE and then recovered in WE's 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, $182.4 million of lease expense related to the We Power leases with WE 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 bothin accordance with Topic 842. The We Power lease and operating and maintenance costs were billed to or incurred by WE,does not impact our financial statements as all amounts associated with the difference in costs billed or incurred and expenses recognized, either deferred or deducted fromlease are eliminated at the regulatory asset.consolidated level.

During the six months ended June 30, 2019, $76.4 million of operating and maintenance costs were billed to or incurred by WE 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 WE 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 ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS 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, $191.6$238.1 million and $201.5$191.6 million, respectively, of costs were billed by transmission providers to our electric utilities.utilities by transmission providers.


(3) 
Represents additional transmission expense associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. See Note 21,23, Regulatory Environment, for more information.


(4) 
As a result ofRepresents additional transmission expense associated with the May 2018 PSCW order requiring WE to use 80% of its current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce its transmission regulatory asset balance, our transmission expense increased during the six months ended June 30, 2018, with a corresponding offset in income taxes. See Note 21, Regulatory Environment, for more information.balance.



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


(6) 
See Note 21,23, Regulatory Environment, for more information about our earnings sharing mechanisms.


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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 5,282.5
 5,053.5
 229.0
 5,147.5
 5,282.5
 (135.0)
Small commercial and industrial * 6,415.3
 6,306.2
 109.1
 6,235.9
 6,415.3
 (179.4)
Large commercial and industrial * 6,376.7
 6,304.8
 71.9
 6,241.9
 6,376.7
 (134.8)
Other 84.3
 87.1
 (2.8) 84.2
 84.3
 (0.1)
Total retail * 18,158.8
 17,751.6
 407.2
 17,709.5
 18,158.8
 (449.3)
Wholesale 1,732.8
 1,876.6
 (143.8) 1,664.5
 1,732.8
 (68.3)
Resale 3,236.7
 3,517.7
 (281.0) 3,144.7
 3,236.7
 (92.0)
Total sales in MWh * 23,128.3
 23,145.9
 (17.6) 22,518.7
 23,128.3
 (609.6)


*Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
 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 693.8
 602.9
 90.9
 747.2
 693.8
 53.4
Commercial and industrial 438.7
 372.6
 66.1
 446.2
 438.7
 7.5
Total retail 1,132.5
 975.5
 157.0
 1,193.4
 1,132.5
 60.9
Transport 735.2
 676.3
 58.9
 752.1
 735.2
 16.9
Total sales in therms 1,867.7
 1,651.8
 215.9
 1,945.5
 1,867.7
 77.8


 Six Months Ended June 30 Six Months Ended June 30
 Degree Days Degree Days
Weather 2018 2017 B(W) 2019 2018 B (W)
WE and WG (1)
            
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)%
            
WPS (2)
            
Heating (4,561 normal) 4,717
 4,107
 14.9%
Cooling (133 normal) 215
 125
 72.0%
Heating (4,597 normal) 4,881
 4,717
 3.5 %
Cooling (136 normal) 78
 215
 (63.7)%
            
UMERC (3)
            
Heating (5,097 normal) 5,242
 4,803
 9.1%
Cooling (77 normal) 138
 47
 193.6%
Heating (5,131 normal) 5,637
 5,242
 7.5 %
Cooling (79 normal) 49
 138
 (64.5)%


(1) 
Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.


(2) 
Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.


(3) 
Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.


Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $34.4 million during the six months ended June 30, 2018, compared with the same period in 2017. The significant factors impacting the lower electric utility margins were:

A $41.3 million decrease in margins related to a settlement agreement with the PSCW to flow through WE's tax benefit of its repair-related deferred tax liabilities through reductions in certain regulatory assets, which are amortized to revenues, as discussed in Note 21, Regulatory Environment.


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Electric Utility Margins

A $16.4 million decrease inElectric utility margins related to amounts expected to be refunded to customers through refunds, bill credits, or reductions in other regulatory assets, driven byat the Tax Legislation. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.

A $7.7Wisconsin segment decreased $34.6 million decrease in wholesale margins driven both by lower sales volumes at WPS and reduced capacity rates at WE and WPS reflecting the Tax Legislation.

These decreases in margins were partially offset by:

A $30.0 million increase related to higher retail sales volumes during the six months ended June 30, 2018, primarily driven by favorable weather and higher overall use per retail customer. Colder winter weather and a warmer start to summer in 2018 contributed to the increase. As measured by heating degree days, the six months ended June 30, 2018, were 18.1% and 14.9% colder than2019, compared with the same period in 2017 in2018. The significant factors impacting the Milwaukee area and Green Bay area, respectively. As measured by cooling degree days, the six months ended June 30, 2018, were 6.9% and 72.0% warmer than the same period in 2017 in the Milwaukee area and Green Bay area, respectively.
lower electric utility margins were:


•
A $27.6 million decrease 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% and 63.7% cooler than the same period in 2018 in the Milwaukee area and Green Bay area, respectively.
A $5.4 million period-over-period positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.
•
A $9.6 million decrease in margins associated with WE's flow through of tax benefits of its 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 23, Regulatory Environment, for more information.


Natural Gas Utility Margins


Natural gas utility margins at the Wisconsin segment increased $5.8$13.3 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 a $28.3 million increase related to higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per commercial and industrialresidential customer and customer growth. This increaseduring the six months ended June 30, 2019, compared with the same period in margins was partially offset by $22.6 million of amounts expected to be returned to customers through refunds or bill credits, driven by the Tax Legislation. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.2018.


Operating Income


Operating income at the Wisconsin segment decreased $83.3increased $163.2 million during the six months ended June 30, 2018,2019, compared with the same period in 2017.2018. This decreaseincrease was driven by the $28.6 million net decrease in margins discussed above and $54.7$184.5 million of higherlower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes)., partially offset by the $21.3 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 WE to change the income statement classification of its lease payments related to the We Power leases. For the six months ended June 30, 2019, the minimum lease payments that were billed from We Power to WE were no longer classified within other operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842.

•
A $32.1 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, Edgewater Unit 4 in September 2018, Pulliam Units 7 and 8 in October 2018, and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the six months ended June 30, 2019. See Note 6, 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 six months endedJune 30, 2019.

•
A $3.7 million decrease in operation and maintenance expense related to the earnings sharing mechanism in place at WG. See Note 23, Regulatory Environment, for more information.

These decreases in operating expenses were partially offset by:

•
A $34.2 million increase in depreciation and amortization, driven by capital expenditures as we continue to execute on our capital plan, an increase related to the reduction of certain regulatory assets as a result of the PSCW's May 2018 order addressing the Tax legislation, and additional expense recognized related to the adoption of Topic 842, as discussed in the other operation and maintenance table above.

A $33.8$22.7 million increase in transmission expense, with a corresponding offset in income taxes, associated with the May 2018 order from the PSCWbenefit costs, primarily related to the benefits associated with the Tax Legislation, as discussed in the table above.deferred compensation.


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A $24.7$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 $10.1 million increase in depreciation and amortization, driven by an overall increase in utility plant in service, WBS's transfer of an information technology project to WPS in June 2017, and the implementation of an enterprise resource planning system in January 2018. This increase in depreciation and amortization was partially offset by a decrease related to the reduction of certain WPS regulatory deferrals as a result of the PSCW's May 2018 order addressing the Tax Legislation.

A $3.7 million increase in expenses related to the earnings sharing mechanism in place at WG. See Note 21, Regulatory Environment, for more information.

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These increases in operating expenses were partially offset by:

A $9.5 million decrease in electric and natural gas distribution expenses, primarily related to lower expenses incurred related to storm damage during the six months ended June 30, 2018.

A $6.1 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 other expected plant retirements. This resulted in lower maintenance and labor costs during the six months ended June 30, 2018. See Note 5, Property, Plant, and Equipment, for more information on the plant retirements.


Illinois Segment Contribution to Operating Income

Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Natural gas revenues $775.3
 $778.5
 $(3.2) $779.4
 $775.3
 $4.1
Cost of natural gas sold 277.0
 271.8
 (5.2) 262.6
 277.0
 14.4
Total natural gas margins 498.3
 506.7
 (8.4) 516.8
 498.3
 18.5
            
Other operation and maintenance 216.3
 222.0
 5.7
 235.2
 216.3
 (18.9)
Depreciation and amortization 82.7
 73.7
 (9.0) 89.5
 82.7
 (6.8)
Property and revenue taxes 10.0
 10.4
 0.4
 11.6
 10.0
 (1.6)
Operating income $189.3
 $200.6
 $(11.3) $180.5
 $189.3
 $(8.8)


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 the line items below $159.4
 $158.6
 $(0.8) $179.5
 $159.4
 $(20.1)
Riders * 56.6
 61.7
 5.1
 56.1
 56.6
 0.5
Regulatory amortizations * (0.7) 1.2
 1.9
 (0.7) (0.7) —
Other 1.0
 0.5
 (0.5) 0.3
 1.0
 0.7
Total other operation and maintenance $216.3
 $222.0
 $5.7
 $235.2
 $216.3
 $(18.9)


*These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on operating income.


The following tables provide information on sales volumes by customer class and weather statistics:
 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 567.0
 458.0
 109.0
 575.7
 567.0
 8.7
Commercial and industrial 227.9
 195.1
 32.8
 232.3
 227.9
 4.4
Total retail 794.9
 653.1
 141.8
 808.0
 794.9
 13.1
Transport 525.7
 467.4
 58.3
 528.9
 525.7
 3.2
Total sales in therms 1,320.6
 1,120.5
 200.1
 1,336.9
 1,320.6
 16.3


 Six Months Ended June 30 Six Months Ended June 30
 Degree Days Degree Days
Weather * 2018 2017 B (W) 2019 2018 B (W)
Heating (3,826 Normal) 3,949
 3,263
 21.0%
Heating (3,878 Normal) 4,158
 3,949
 5.3%


*Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.


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Natural Gas Utility Margins


Natural gas utility margins at the Illinois segment, net of the $5.1$0.5 million impact of the riders referenced in the table above, decreased $3.3increased $19.0 million during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, driven by a $19.1$15.3 million decrease in margins related to amounts being returned to customers through the VITA in connection with the Tax Legislation signed into law in December 2017. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information. This decrease was partially offset by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related

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to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. See Note 23, Regulatory Environment, for more information.


Operating Income


Operating income at the Illinois segment decreased $11.3$8.8 million during the six months ended June 30, 2018,2019, compared with the same period in 2017.2018. This decrease was due to an $8.0driven by a $27.8 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenuesrevenue taxes), net of the impact of the riders referenced in the table above, and the $3.3 million net decrease in margins discussed above. TheThis increase in operating expenses was drivenpartially offset by higher depreciation expense at PGLthe $19.0 million net increase in margins discussed above.

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

A $10.5 million increase in benefit costs, primarily related to deferred compensation.

•
An $8.8 million increase in natural gas maintenance costs, primarily due to maintenance work resulting from colder than normal weather during the six months ended June 30, 2019, compared with the same period in 2018.

A $6.8 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.


Other States Segment Contribution to Operating Income
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Natural gas revenues $242.3
 $223.6
 $18.7
 $254.0
 $242.3
 $11.7
Cost of natural gas sold 127.4
 113.8
 (13.6) 135.4
 127.4
 (8.0)
Total natural gas margins 114.9
 109.8
 5.1
 118.6
 114.9
 3.7
     

     

Other operation and maintenance 51.5
 51.5
 —
 51.0
 51.5
 0.5
Depreciation and amortization 11.1
 12.1
 1.0
 13.2
 11.1
 (2.1)
Property and revenue taxes 8.0
 8.0
 —
 8.3
 8.0
 (0.3)
Operating income $44.3
 $38.2
 $6.1
 $46.1
 $44.3
 $1.8


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 item below $36.3
 $37.7
 $1.4
 $37.7
 $36.3
 $(1.4)
Regulatory amortizations and other pass through expenses * 15.2
 13.8
 (1.4) 13.3
 15.2
 1.9
Total other operation and maintenance $51.5
 $51.5
 $—
 $51.0
 $51.5
 $0.5


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


The following tables provide information on sales volumes by customer class and weather statistics:
 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 217.4
 173.4
 44.0
 219.8
 217.4
 2.4
Commercial and industrial 135.1
 111.6
 23.5
 144.1
 135.1
 9.0
Total retail 352.5
 285.0
 67.5
 363.9
 352.5
 11.4
Transport 392.3
 359.0
 33.3
 403.5
 392.3
 11.2
Total sales in therms 744.8
 644.0
 100.8
 767.4
 744.8
 22.6




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 Six Months Ended June 30 Six Months Ended June 30
 Degree Days Degree Days
Weather * 2018 2017 B (W) 2019 2018 B (W)
MERC     

     

Heating (4,799 Normal) 5,149
 4,436
 16.1%
Heating (4,843 Normal) 5,456
 5,149
 6.0%
            
MGU            
Heating (3,959 Normal) 3,993
 3,384
 18.0%
Heating (3,974 Normal) 4,103
 3,993
 2.8%


*Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective service territories.


Natural Gas Utility Margins


Natural gas utility margins increased $5.1$3.7 million during the six months ended June 30, 2018,2019, compared to the same period last year.in 2018. The increase was primarily driven by higher sales volumes as a result of colder winter weather in 2018 as well asand customer growth, partially offset by a $6.1 million decrease in margins related to amounts expected to be returned to customers through bill credits or reductions in future rates, related to the Tax Legislation signed into law in December 2017. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.growth.


Operating Income


Operating income at the other states segment increased $6.1$1.8 million during the six months ended June 30, 2018,2019, compared with the same period in 2017.2018. The increase was driven by the $5.1$3.7 million increase in margins discussed above, partially offset by a $1.9 million increase in operating expenses (which include other operation and a $1.0 million decrease inmaintenance, depreciation and amortization, expense.and property and revenue taxes). The decreaseincrease in operating expenses is primarily due to the positive impact on 2018 depreciation and amortization expense reflects the impact of a new depreciation study approved by the MPUC in the second quarter of 2018. TheThese rates were effective retroactive to January 2017.


Non-Utility Energy Infrastructure Segment Contribution to Operating Income
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Operating income $185.4
 $196.1
 $(10.7) $184.0
 $185.4
 $(1.4)

Operating income at the non-utility energy infrastructure segment decreased $10.7 million during the six months ended June 30, 2018, compared with the same period in 2017. The decrease was driven by a $25.2 million decrease in revenue related to the Tax Legislation signed into law in December 2017. As a result of the Tax Legislation, the lease payments charged by We Power to WE were reduced. The reduction in the lease payments was offset by a decrease in income tax expense, resulting in no impact on net income. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information. Partially offsetting the impact of the Tax Legislation was a $13.5 million contribution to operating income from Bluewater during the six months ended June 30, 2018. Bluewater was acquired on June 30, 2017. See Note 2, Acquisitions, for more information.


Corporate and Other Segment Contribution to Operating Income
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Operating loss $(11.9) $(10.1) $(1.8) $(11.0) $(11.9) $0.9


Electric Transmission Segment Operations
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Equity in earnings of transmission affiliates $61.5
 $83.7
 $(22.2) $73.0
 $61.5
 $11.5


Earnings from our ownership interests in transmission affiliates decreased $22.2increased $11.5 million during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, primarily due to the Tax Legislation signed into law in December 2017. The $20.1 million decrease in our equity earnings from the Tax Legislation did not affect our net income as it was offsetcontinued capital investment by an equal reduction in our

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income tax expense. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.ATC. Also contributing to the decreaseincrease in our equity earnings was the impact of the refund ATC was required to provide customers in the second quarter of 2018 as a result of the FERC financial audit completed in February 2018.


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 $7.0
 $5.3
 $1.7
 $7.3
 $7.0
 $0.3
Non-service components of net periodic benefit costs 17.9
 12.5
 5.4
Other, net 31.9
 26.1
 5.8
 29.3
 19.4
 9.9
Other income, net $38.9
 $31.4
 $7.5
 $54.5
 $38.9
 $15.6


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Other income, net increased $7.5$15.6 million during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018. The increase was primarily driven by higher gains on the investments held in the Integrys rabbi trust. These investment gains partially offset benefits costs related to deferred compensation included in operating income. See Note 13, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. Also contributing to the increase in other income were higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 14,16, Employee Benefits, for more information on our benefitpension and OPEB costs. This increase was partially offset by lower gains on investments held in our rabbi trust during the six months ended June 30, 2018.


Consolidated Interest Expense
 Six Months Ended June 30 Six Months Ended June 30
(in millions) 2018 2017 B (W) 2019 2018 B (W)
Interest expense $215.2
 $206.6
 $(8.6) $248.5
 $215.2
 $(33.3)


Interest expense increased $8.6$33.3 million during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, primarily due to higher short-term debt balances and higher interest rates on short-term debt. This increase in debt balances is primarily related to continued capital investments.


Consolidated Income Tax Expense
  Six Months Ended June 30
  2018 2017 B (W)
Effective tax rate 18.3% 37.2% 18.9%
  Six Months Ended June 30
  2019 2018 B (W)
Effective tax rate 10.9% 18.3% 7.4%


Our effective tax rate decreased by 18.9%7.4% when compared with the six months ended June 30, 2017,2018, primarily due to the increased benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement, an increase in wind production tax credits related to recent acquisitions of wind generation facilities in our non-utility energy infrastructure segment, the impact of the Tax Legislation. Contributing 6.3%Legislation, and the recognition of deferred investment tax credits related to the decrease insale of certain PDL solar power generation facilities completed during the second quarter of 2019. See Note 3, Disposition, Note 12, Income Taxes, and Note 23, Regulatory Environment, for more information.

We expect our 2019 annual effective tax rate isto be between 10.5% and 11.5%, which includes an estimated 9.5% effective tax rate benefit due to the flow through of tax repairs in connection with the Wisconsin rate settlement. See Note 10, Income Taxes, and Note 21, Regulatory Environment, for more information.

We expect our 2018 annualExcluding the impact of the tax repairs, the expected 2019 effective tax rate towould be between 15%20% and 16%, which includes an estimated 7% effective tax rate benefit due to the flow through of tax repairs.21%.


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 $1,513.4
 $1,266.9
 $246.5
 $1,291.2
 $1,513.4
 $(222.2)
Investing activities (996.8) (1,036.2) 39.4
 (1,066.4) (996.8) (69.6)
Financing activities (523.2) (245.1) (278.1) (280.2) (523.2) 243.0



Operating Activities

Net cash provided by operating activities decreased $222.2 million during the six months ended June 30, 2019, compared with the same period in 2018, driven by:

•
A $222.1 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.


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•
A $48.0 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.
Operating Activities
•
A $32.3 million decrease in cash due to an increase in payments for interest related to higher long-term debt balances and higher interest rates on short-term debt during the six months ended June 30, 2019, compared with the same period in 2018.

Net cash provided by operating activities increased $246.5 million during the six months ended June 30, 2018, compared with the same period in 2017, driven by:

A $190.5 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 $120.7 million increase in cash from lower payments for other operation and maintenance costs. During the six months endedJune 30, 2018, our payments related to transmission, electric and natural gas distribution, and plant maintenance and labor costs decreased.

A $101.8 millionincrease in cash due to lower contributions and payments to our pension and OPEB plans during the six months endedJune 30, 2018, compared with the same period in 2017.


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


•
A $32.5 million net increase in cash paid for income taxes during the six months ended June 30, 2019, compared with the same period in 2018. This increase in cash was primarily due to the uncertainty of bonus depreciation eligibility for our regulated utilities as a result of the Tax Legislation which, increased our 2017 extension payment made in 2018.

•
A $29.6 million increase in cash primarily related to lower payments for fuel and purchased power during the six months ended June 30, 2019, compared with the same period in 2018, due to the retirements of the Pleasant Prairie power plant in April 2018, Edgewater Unit 4 in September 2018, Pulliam Units 7 and 8 in October 2018, and the PIPP in March 2019.
A $100.4 million decrease in cash resulting from higher payments during thesix months endedJune 30, 2018, compared with the same period in 2017, for natural gas we purchased at the end of 2017 and during thesix months endedJune 30, 2018, to meet the requirements of our customers during the colder winter weather.

A $57.1 million net decrease in cash related to $47.6 million of cash paid for income taxes during thesix months endedJune 30, 2018, compared with $9.5 million of cash received for income taxes during the same period in 2017. This decrease in cash was primarily due to the repeal of bonus depreciation for our regulated utilities as a result of the Tax Legislation.


Investing Activities


Net cash used in investing activities decreased $39.4increased $69.6 million during the six months ended June 30, 2018,2019, compared with the same period in 2017, driven by:

2018. The acquisition of Bluewater during June 2017 for $226.0 million. See Note 2, Acquisitions, for more information.

An $18.1 million decrease in our capital contributions to ATC and ATC Holdco during the six months endedJune 30, 2018, compared with the same period in 2017. Our capital contributions decreased due to the refunds ATC paid in 2017 as a result of the ATC ROE complaints filed with the FERC, which were partially funded by capital contributions. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.

These decreasesincrease in net cash used in investing activities were partially offset by:

A $125.5was driven by the acquisition of an 80% ownership interest in Upstream in January 2019 for $268.2 million, increase in cash paid for capital expenditures during the six months endedJune 30, 2018, compared with the same period in 2017, which is discussed in more detail below.

The acquisitionnet of Forward Wind Energy Center during April 2018 for $77.1 million. cash and restricted cash acquired of $9.2 million. See Note 2, Acquisitions, for more information.
information.


A $12.8 million decreaseThis increase in the proceeds received from the sale of assets and businesses during the six months endedJune 30, 2018, compared with the same periodnet cash used in 2017. See Note 3, Disposition, for more information.
investing activities was partially offset by:



06/30/•
The acquisition of Forward Wind Energy Center in April 2018 Form 10-Q
54WEC Energy Group, Inc.for $77.1 million. See Note 2, Acquisitions, for more information.

•
A $60.3 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 $32.4 million increase in cash related to a reimbursement from ATC for construction costs during the six months ended June 30, 2019. See Note 18, Investment in Transmission Affiliates, for more information.
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•
A $22.1 million increase in proceeds received from the sale of assets and businesses during the six months ended June 30, 2019, compared with the same period in 2018. See Note 3, Disposition, for more information on the sale of the three power generation facilities previously owned by PDL.


Capital Expenditures


Capital expenditures by segment for the six months ended June 30 were as follows:
Reportable Segment
(in millions)
 2018 2017 Change in 2018 Over 2017 2019 2018 Change in 2019 Over 2018
Wisconsin $612.3
 $463.4
 $148.9
 $541.2
 $612.3
 $(71.1)
Illinois 228.1
 204.7
 23.4
 242.5
 228.1
 14.4
Other states 35.9
 30.8
 5.1
 45.0
 35.9
 9.1
Non-utility energy infrastructure 16.7
 13.0
 3.7
 19.7
 16.7
 3.0
Corporate and other 22.5
 78.1
 (55.6) 6.8
 22.5
 (15.7)
Total capital expenditures $915.5
 $790.0
 $125.5
 $855.2
 $915.5
 $(60.3)


The increasedecrease in cash paid for capital expenditures at the Wisconsin segment during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, was primarily driven by a project to construct a new natural gas-fired generation facility in the Upper Peninsulaimplementation of Michigan and upgrades toan enterprise resource planning system, our electric distribution systems. Our advanced metering infrastructureAMI program and various other software projects, also contributedprojects at the OCPP, and upgrades to WE's electric distribution system during the increasesix months ended June 30, 2018. These decreases in ourcash paid for capital expenditures.expenditures were partially offset by increased capital expenditures related to upgrades to WPS's natural gas distribution system and an information technology project created to improve WE's and WG's billing, call center, and credit collection functions during the six months ended June 30, 2019.



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The increase in cash paid for capital expenditures at the Illinois segment during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, was driven by increased construction activity related to NSG's natural gas pipeline distribution system.an increase in facilities projects at PGL during the six months ended June 30, 2019.


The decrease in cash paid for capital expenditures at the corporate and other segment during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, was primarily driven by lower capital expenditures related to a newthe implementation of an enterprise resource planning system which was implemented during the first quarter ofsix months ended June 30, 2018. Also contributing to the decrease in capital expenditures was the completion of an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries during 2017 and various other software projects, the majority of which were completed during 2017.


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


Financing Activities


Net cash used in financing activities increased $278.1decreased $243.0 million during the six months ended June 30, 2018,2019, compared with the same period in 2017,2018, driven by:


•
A $664.1 million increase in cash related to lower long-term debt repayments during the six months ended June 30, 2019, compared with the same period in 2018.

•
A $45.0 million increase in cash from stock options exercised during the six months ended June 30, 2019, compared with the same period in 2018.
A $666.8 million decrease in cash related to higher long-term debt repayments during the six months endedJune 30, 2018, compared with the same period in 2017.

A $20.4 million increase in dividends paid on our common stock during the six months endedJune 30, 2018, compared with the same period in 2017. In January 2018, our Board of Directors increased our quarterly dividend by $0.0325 per share (6.25%) effective with the first quarter of 2018 dividend payment.


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


•
A $250.0 million decrease in cash due to lower issuances of long-term debt during the six months ended June 30, 2019, compared with the same period in 2018.

•
A $102.8 million decrease in cash related to higher net repayments of commercial paper during the six months ended June 30, 2019, compared with the same period in 2018.
A $390.0 million increase in cash due to the issuance of more long-term debt during the six months endedJune 30, 2018, compared with the same period in 2017.
•
An $86.5 million decrease in cash due to an increase in shares of our common stock purchased during the six months ended June 30, 2019, compared with the same period in 2018, to satisfy requirements of our stock-based compensation plans.

•
A $23.6 million decrease in cash due to higher dividends paid on our common stock during the six months ended June 30, 2019, compared with the same period in 2018. In January 2019, our Board of Directors increased our quarterly dividend by $0.0375 per share (6.79%) effective with the first quarter of 2019 dividend payment.

A $19.9 million increase in cash due to fewer shares of our common stock purchased during the six months endedJune 30, 2018, compared with the same period in 2017, to satisfy requirements of our stock-based compensation plans.


Significant Financing Activities


For more information on our financing activities, see Note 7,8, Short-Term Debt and Lines of Credit, and Note 8,9, Long-Term Debt.



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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.


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


WEC Energy Group, WE, WG, WPS, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit

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facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 7,8, Short-Term Debt and Lines of Credit, for more information about these credit facilities.


The following table shows our capitalization structure as of June 30, 2018,2019, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:
(in millions) Actual Adjusted Actual Adjusted
Common shareholders' equity $9,725.8
 $9,975.8
 $10,016.2
 $10,266.2
Preferred stock of subsidiary 30.4
 30.4
 30.4
 30.4
Long-term debt (including current portion) 9,502.8
 9,252.8
 10,687.5
 10,437.5
Short-term debt 1,370.0
 1,370.0
 1,262.7
 1,262.7
Total capitalization $20,629.0
 $20,629.0
 $21,996.8
 $21,996.8
        
Total debt $10,872.8
 $10,622.8
 $11,950.2
 $11,700.2
        
Ratio of debt to total capitalization 52.7% 51.5% 54.3% 53.2%


Included in long-term debt on our balance sheet as of June 30, 2018,2019, is $500.0 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.


The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the 2007 Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.


Working Capital


As of June 30, 2018,2019, our current liabilities exceeded our current assets by $1,242.8$1,523.3 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.

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

In January 2018, Moody's downgraded the rating outlook for WG to negative from stable as a result of the new Tax Legislation. We do not believe the change in rating outlook will have a material impact on our ability to access capital markets.

In July 2018, Moody's downgraded the ratings of WEC Energy Group (senior unsecured), Wisconsin Energy Capital Corporation (senior unsecured), and Integrys (senior unsecured) to Baa1 from A3. Moody's also downgraded the ratings of WEC Energy Group (junior subordinated), and Integrys (junior subordinated) to Baa2 from Baa1. Reduced cash flow due to Tax Legislation, which impacts the majority of companies in our industry, was a catalyst for the downgrade. Moody's affirmed the commercial paper ratings of WEC Energy Group (senior unsecured, P-2), and Integrys (senior unsecured, P-2) and changed the rating outlook for WEC Energy Group, Wisconsin Energy Capital Corporation, and Integrys, to stable from rating under review.


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 additional 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 or our subsidiaries’ credit ratings on negative outlook or additional downgrading of our or our subsidiaries' credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us and our subsidiaries to issue future debt securities and certain other types of financing and could increase borrowing costs under our and our subsidiaries’ credit facilities.



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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 and acquisitions for the next three years are as follows:
(in millions) 2018 2019 2020 2019 2020 2021
Wisconsin $1,430.1
 $1,152.0
 $1,850.2
 $1,344.9
 $1,677.5
 $1,559.1
Illinois 633.8
 629.2
 676.5
 765.2
 684.0
 602.4
Other states 99.6
 116.1
 110.6
 155.4
 135.8
 105.5
Non-utility energy infrastructure 193.8
 336.5
 51.9
 424.2
 418.8
 242.8
Corporate and other 20.7
 13.2
 0.8
 15.7
 11.0
 1.1
Total $2,378.0
 $2,247.0
 $2,690.0
 $2,705.4
 $2,927.1
 $2,510.9


WPS is continuing work on the SMRP. This project includes modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WPS expects to invest approximately $250$185 million between 20182019 and 2021 on this project. WE, WPS, and WG will also continue to upgrade their 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.


As part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar of up to 350 MW within our Wisconsin segment. WPS has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar FarmI will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $260 million. Commercial operation for both projects is targeted for the end of 2020. WE has 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. WE's 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.


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In connection with the formation of UMERC, we entered into an agreement with Tilden Mining Company under which it will purchase electric power from UMERC for 20 years, contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new generation is expected to beginbegan commercial operation during the second quarter ofon March 31, 2019. The estimated cost of this project is approximately $266$242 million ($277255 million including AFUDC).See Note 21, Regulatory Environment, for more information about UMERC and this new generation., 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers.


PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. PGL's projected average annual investment through 20202021 is between $280 million and $300 million. See Note 21,23, Regulatory Environment, for more informationon the SMP.


The non-utility energy infrastructure segment includes the investmentline item in the Bishop Hill III Wind Energy Centertable above includes our investments in Coyote Ridge and Upstream Wind Energy Center.Upstream. See Note 2, Acquisitions, for more information on these wind projects.


We expect to provide total capital contributions to ATC and ATC Holdco (not included in the above table) of approximately $200$185 million from 20182019 through 2020.2021.


Common Stock Dividends


Our current quarterly dividend rate is $0.5525$0.59 per share, which equates to an annual dividend of $2.21$2.36 per share. For information related to our most recent common stock dividend declared, see Note 6,7, Common Equity.



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Off-Balance Sheet Arrangements


We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 7,8, Short-Term Debt and Lines of Credit, Note 13,15, Guarantees, and Note 18,20, 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 businesses and the environments in which those businesses 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 20172018 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.


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Regulatory Recovery


Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities.


Due to the Tax Legislation signed into law in December 2017, our regulated utilities remeasured their deferred taxes and recorded a tax benefit of $2,529 million. Our utilities have been returning the amortization of this tax benefit to ratepayers through refunds, bill credits, riders, and reductions to other regulatory assets, which we expect to continue.

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


•
In June 2016, the PSCW approved the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, was $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. WPS cannot collect these deferred costs without prior approval from the PSCW. WPS has requested approval for collection of these deferred costs in the rate proposal it filed with the PSCW in March 2019. See Note 23, Regulatory Environment, for more information.

In June 2016, the PSCW approved the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 21, Regulatory Environment, for more information. WPS will be required to obtain a separate approval for collection of these deferred costs in a future rate case.

Prior to its acquisition by us, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing,

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call center, and credit collection functions. As of June 30, 20182019, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.

In January 2014, WPS has requested recovery of these costs in the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2018, PGLrate proposal it filed its 2017 reconciliation with the ICC, which, along with the 2016 and 2015 reconciliations, are still pending. In February 2018, PGL agreed to a settlement of the 2014 reconciliation, which includes a rate base reduction of $5.4 million and a $4.7 million refund to ratepayers. As of June 30, 2018, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC.
PSCW in March 2019.


•
In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2019, PGL filed its 2018 reconciliation with the ICC, which, along with the 2017 and 2016 reconciliations, are still pending. In June 2019, PGL agreed to a settlement of the 2015 reconciliation, which includes a rate base reduction of $7.0 million and a $7.3 million refund to ratepayers. The ICC approved the settlement on July 17, 2019. It will not have a material impact on earnings. As of June 30, 2019, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

See Note 21,23, Regulatory Environment, for more information regarding recent andour pending rate proceedings, previously issued rate orders, and investigations involving our utilities.


Environmental Matters


See Note 19,21, 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. TheIn 2018 and 2019, the PSCW and the MPSC have issued written orders regarding how to refund certain tax savings from the Tax Legislation to our ratepayers in Wisconsin and Michigan, respectively, and the ICC has approved the VITA in Illinois.respectively. We expect that the MPUC to address how we should return the tax savings fromvarious remaining impacts of the Tax Legislation toon our Wisconsin operations will be addressed in the pending rate case we filed with the PSCW in March 2019. In addition, the ICC approved the Variable Income Tax Adjustment Rider in Illinois during April 2018, and, in Minnesota, ratepayersthe MPUC included the various impacts of the Tax Legislation in MERC's currently activefinal 2018 rate case.order. In July 2019, the FERC approved WPS's formula rate tariff, which incorporated the impact of the Tax Legislation. Formula rate customers of WPS will receive a monthly bill credit through the end of 2019, which will include the customer's tax savings, including interest. We are also working with the FERC to modify ourWE's 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 21,23, Regulatory Environment, for more information.

American Transmission Company Allowed Return on Equity Complaints


In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision

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recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a finalan order related to this complaint affirming the use of the ROE stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also required ATC to provide refunds, with interest, for the 15-month refund period from November 12, 2013, through February 11, 2015. The refunds$28.3 million refund that ATC provided to WE and WPS for transmission costs paid during the refund period reduced the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense and resulted in a net regulatory liability for WPS. See Note 16, Investment in Transmission Affiliates, for more information.


In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015. In June 2016, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. We are uncertain when a FERC order related to this matter will be issued.


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The MISO transmission owners have filed various appeals related to several of the FERC orders with the D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit as well as requests for rehearing.



In November 2018, the FERC issued an order directing MISO transmission owners, including ATC, to submit briefs on a proposed change to the methodology used to calculate their base ROE. In March 2019, the FERC issued two new orders expanding its ROE inquiries to solicit comments from all potential stakeholders, including those outside of MISO. If the proposed methodology is approved, ATC’s base ROE for the period from November 12, 2013 through February 11, 2015 would be 10.28% instead of the 10.32% approved by the FERC in September 2016. The proposed methodology would also impact the second complaint filed in February 2015 and ATC’s base ROE going forward. We are uncertain when a final FERC order related to the proposed methodology will be issued.


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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 11,13, Fair Value Measurements, Note 12,14, Derivative Instruments, and Note 13,15, 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, we completed an enterprise resource planning (ERP) system integration project to bring all of our subsidiaries 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 19,21, Commitments and Contingencies, and Note 21,23, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us and our subsidiaries.


In addition to those legal proceedings discussed in Note 19,21, Commitments and Contingencies, Note 21,23, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.


Environmental Matters

Sheboygan River Matter

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


Manlove Field Matter


In September 2017, the Illinois Department of Natural Resources, (Illinois DNR), Office of Oil and Gas Resource Management, issued a NOVVN to PGL related to a leak of natural gas thatfrom a well located at the PGL identified at its Manlove Gas Storage Field in December 2016. PGL quickly containedshut down and permanently plugged the well to contain the leak after it was discovered. The leak resulted in the migration of natural gas from athe well located at the facility to the Mahomet Aquifer located in central Illinois which may haveand impacted residential freshwater wells. PGL has been working with theresidents potentially impacted homeowners and other residents that may have been impacted by the natural gas leak, as well asand the Illinois DNR and other state agencies to investigate and remediate the impacts of the natural gas leak to the Mahomet Aquifer. In October 2017, the Illinois Attorney General (AG)AG filed a complaint against PGL alleging certain violations of the Illinois Environmental Protection Act and the Oil and Gas Act. PGL entered into an interim agreed order with the State of Illinois in October 2017 whereby PGL agreed, among other things, to continue actions it was already undertaking proactively.

In addition, in December 2017, the Illinois Environmental Protection Agency servedIEPA issued a NOVVN to PGL alleging the same violations as the AG, andAG. Lastly, in January 2018, servedthe IEPA issued a NOVVN alleging certain violations of Illinois air emission rules arising from the construction and operation of flaring equipment at the leak site. Both of the IEPA VN matters have been referred to the AG for enforcement.


In the complaint, as is customary in these types of actions, the AG cited to the statutory penalties allowed by law. Ultimately, the pursuit of any civil penalties is at the AG’s discretion. In the event the AG wishes to consider such penalties, we believe that PGL's high level of cooperation and quick action to remedy the situation and to work with the potentially impacted homeowners would be taken into account. At this time, we believe that civil penalties, if any, will not have a material impact on our financial statements.


Presque Isle Power Plant Matter

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


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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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended June 30, 2018:2019:


Issuer Purchases of Equity Securities
2018 Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
2019 Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 – April 30 4,012
 $63.08
 —
 $—
 —
 $—
 —
 $—
May 1 – May 31 500
 64.51
 —
 —
 500
 77.70
 —
 —
June 1 – June 30 —
 —
 —
 —
 —
 —
 —
 —
Total * 4,512
 $63.24
 —
   500
 $77.70
 —
  


*All shares were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.



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ITEM 6. EXHIBITS
Number Exhibit
4Instruments defining the rights of security holders, including indentures
4.1
Securities Resolution No. 7 of WEC Energy Group, dated as of June 4, 2018, under the Indenture for Debt Securities, dated as of March 15, 1999, between WEC Energy Group and the Bank of New York Mellon Trust Company, N.A. (as successor to The First National Bank of Chicago), as Trustee. (Exhibit 4.1 to WEC Energy Group's Form 8-K filed June 7, 2018).
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.






  WEC ENERGY GROUP, INC.
  (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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