false--12-31Q3201900007833258636600000880770000014920000013780000000450000092000000.55250.55250.55250.590.590.590.010.01325000000325000000315523192315435595790000036700000229000001247000007800000378000002390000013770000013000005100000006500000050000003000000500000010000010000020000015000000.00501001.00.330.00250.0050 0000783325 us-gaap:CarryingReportedAmountFairValueDisclosureMember 2019-09-30

 

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 September 30, 20172019


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.
image0a15.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 (September 30, 2019):


Common Stock, $.01 Par Value,
315,575,562 315,435,595 shares outstanding at
September 30, 2017
 

Table of Contents

WEC ENERGY GROUP, INC.
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 20172019
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
7
Note 2
Acquisitions
7
Note 3
Dispositions
8
Note 4
Property, Plant, and Equipment
8
Note 5
Common Equity
9
 
 
Note 62
Short-Term Debt and Lines of CreditAcquisitions
9
Note 3
Disposition
10
 
 
Note 74
Long-Term DebtOperating Revenues
10
 
 
Note 85
Materials, Supplies,Regulatory Assets and InventoriesLiabilities
1114
 
 
Note 96
Fair Value Measurements
11
Note 10
Derivative Instruments
13
Note 11
GuaranteesProperty, Plant, and Equipment
15
 
 
Note 127
Employee Benefits
15
Note 13
GoodwillCommon Equity
16
 
 
Note 148
Investment in American Transmission CompanyShort-Term Debt and Lines of Credit
16
 
 
Note 159
Segment InformationLong-Term Debt
17
 
 
Note 1610
Variable Interest EntitiesLeases
1918
 
 
Note 1711
CommitmentsMaterials, Supplies, and ContingenciesInventories
2022
 
 
Note 1812
Supplemental Cash Flow InformationIncome Taxes
2422
 
 
Note 1913
Regulatory EnvironmentFair Value Measurements
2423
 
 
Note 2014
New Accounting PronouncementsDerivative Instruments
2625
Note 15
Guarantees
27
Note 16
Employee Benefits
27
Note 17
Goodwill
28
Note 18
Investment in Transmission Affiliates
28
Note 19
Segment Information
30
Note 20
Variable Interest Entities
32
Note 21
Commitments and Contingencies
33
Note 22
Supplemental Cash Flow Information
36
Note 23
Regulatory Environment
37
Note 24
New Accounting Pronouncements
41
 
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
2942
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
5372
ITEM 4.
CONTROLS AND PROCEDURES
 
5372
PART II.
OTHER INFORMATION
 
5473
ITEM 1.
LEGAL PROCEEDINGS
 
5473
ITEM 1A.
RISK FACTORS
 
5473
ITEM 5.6.
OTHER INFORMATIONEXHIBITS
 
5474
ITEM 6.
EXHIBITS
55
SIGNATURE
  
5675




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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 HoldcoATC 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.
ITFIntegrys Transportation Fuels, LLC
MERC Minnesota Energy Resources Corporation
MGU Michigan Gas Utilities Corporation
NSG North Shore Gas Company
PDLWPS Power Development, LLC
PGL The Peoples Gas Light and Coke Company
ThunderheadThunderhead Wind Energy LLC
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
WisvestWisvest LLC
WPS Wisconsin Public Service Corporation
   
Federal and State Regulatory Agencies
EGLEMichigan Department of Environment, Great Lakes, and Energy (previously Michigan Department of Environmental Quality)
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
ICC Illinois Commerce Commission
MDEQIEPA Michigan Department ofIllinois Environmental QualityProtection Agency
IRSUnited States Internal Revenue Service
MPSC Michigan Public Service Commission
MPUC Minnesota Public Utilities Commission
PSCW Public Service Commission of Wisconsin
SEC United States Securities and Exchange Commission
WDNR Wisconsin Department of Natural Resources
   
Accounting Terms
AFUDC Allowance for Funds Used During Construction
ASU Accounting Standards Update
FASB Financial Accounting Standards Board
GAAP United States Generally Accepted Accounting Principles
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
CSAPRCross-State Air Pollution Rule
GHGGreenhouse Gas
NAAQSNational Ambient Air Quality Standards
NOVNotice of Violation
NOxNitrogen Oxide
SO2
Sulfur Dioxide


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CO2
Carbon Dioxide
ELGSteam Electric Effluent Limitation Guidelines
FGDFlue Gas Desulfurization
GHGGreenhouse Gas
MATSMercury and Air Toxics Standards
NOVNotice of Violation
RTRRisk and Technology Review
VNViolation Notice
Measurements
Dth Dekatherm
MW Megawatt
MWh Megawatt-hour
   
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
CNGAMI Compressed Natural GasAdvanced Metering Infrastructure
D.C. Circuit Court of AppealsBadger Hollow I United States Court of Appeals for the District of Columbia CircuitBadger 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
MCPPGUIC Milwaukee County Power PlantGas Utility Infrastructure Costs
LNGLiquefied Natural Gas
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
VAPPTax Legislation Valley Power PlantTax Cuts and Jobs Act of 2017
TildenTilden Mining Company
Two CreeksTwo Creeks Solar Project




09/30/20172019 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 2018 Annual Report on Form 10-K, for the year ended December 31, 2016, and those identified below:


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


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


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

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

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

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


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


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

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

The impact of federal, state, and local legislative and/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, energy efficiency mandates, and tax laws that affect our ability to use production tax credits and investment tax credits;

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

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,

09/30/2019 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;


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;advances, that could prevent us from paying our common stock dividends, taxes, and other expenses, and meeting our debt obligations;


09/30/2017 Form 10-Q1WEC Energy Group, Inc.
Table of Contents


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 incidents,attacks and cyber security intrusions, as well as the threat of terroristsuch incidents, and cyber security intrusion, 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.




09/30/20172019 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 Nine Months Ended Three Months Ended Nine Months Ended
 September 30 September 30
CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) September 30 September 30
 2017
2016 2017 2016 2019
2018 2019 2018
Operating revenues $1,657.5
 $1,712.5
 $5,593.5
 $5,509.3
 $1,608.0
 $1,643.7
 $5,575.6
 $5,602.7
                
Operating expenses                
Cost of sales 542.7
 554.7
 2,025.6
 1,901.9
 484.3
 524.1
 1,985.8
 2,043.9
Other operation and maintenance 471.7
 517.5
 1,453.4
 1,571.0
 529.2
 553.1
 1,583.4
 1,602.7
Depreciation and amortization 201.2
 191.6
 593.5
 569.5
 233.8
 212.8
 690.1
 628.1
Property and revenue taxes 48.3
 49.7
 147.9
 146.5
 49.8
 51.0
 148.0
 149.4
Total operating expenses 1,263.9
 1,313.5
 4,220.4
 4,188.9
 1,297.1
 1,341.0
 4,407.3
 4,424.1
                
Operating income 393.6
 399.0
 1,373.1
 1,320.4
 310.9
 302.7
 1,168.3
 1,178.6
                
Equity in earnings of transmission affiliate 39.2
 38.3
 122.9
 107.7
Equity in earnings of transmission affiliates 38.7
 33.7
 111.7
 95.2
Other income, net 16.4
 7.5
 45.2
 72.6
 21.8
 26.1
 76.3
 65.0
Interest expense 103.8
 99.1
 310.4
 300.1
 125.8
 112.0
 374.3
 327.2
Other expense (48.2) (53.3) (142.3) (119.8) (65.3) (52.2) (186.3) (167.0)
                
Income before income taxes 345.4
 345.7
 1,230.8
 1,200.6
 245.6
 250.5
 982.0
 1,011.6
Income tax expense 129.7

128.4
 458.8
 455.1
 11.3

17.0
 91.5
 156.4
Net income 215.7

217.3
 772.0
 745.5
 234.3

233.5
 890.5
 855.2
                
Preferred stock dividends of subsidiary 0.3

0.3
 0.9
 0.9
 0.3

0.3
 0.9
 0.9
Net loss attributed to noncontrolling interests 0.3
 —
 0.5
 —
Net income attributed to common shareholders $215.4
 $217.0
 $771.1
 $744.6
 $234.3
 $233.2
 $890.1
 $854.3
                
Earnings per share                
Basic $0.68
 $0.69
 $2.44
 $2.36
 $0.74
 $0.74
 $2.82
 $2.71
Diluted $0.68
 $0.68
 $2.43
 $2.35
 $0.74
 $0.74
 $2.81
 $2.70
                
Weighted average common shares outstanding                
Basic 315.6
 315.6
 315.6
 315.6
 315.4
 315.5
 315.4
 315.5
Diluted 317.5
 316.9
 317.5
 317.0
 316.8
 316.9
 316.7
 316.9
        
Dividends per share of common stock $0.520
 $0.495
 $1.560
 $1.485


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




09/30/20172019 Form 10-Q3WEC Energy Group, Inc.
Table of Contents


WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30 September 30 September 30 September 30
(in millions) 2017 2016 2017 2016 2019 2018 2019 2018
Net income $215.7
 $217.3
 $772.0
 $745.5
 $234.3
 $233.5
 $890.5
 $855.2
                
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) (1.0) (0.9)
Derivative (losses) gains, net of tax of $(0.2), $0.1, $(1.5), and $0.1, respectively (0.3) 0.3
 (3.8) 0.3
Reclassification of net gains to net income, net of tax (0.2) (0.4) (0.8) (1.0)
Cash flow hedges, net (0.5) (0.1) (4.6) (0.7)
                
Defined benefit plans                
Amortization of pension and OPEB costs (credits) included in net periodic benefit cost, net of tax 0.3
 (0.4) 0.5
 —
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax —
 —
 0.1
 0.2
                
Other comprehensive loss, net of tax (0.1) (0.7) (0.5) (0.9) (0.5) (0.1) (4.5) (0.5)
                
Comprehensive income 215.6
 216.6
 771.5
 744.6
 233.8
 233.4
 886.0
 854.7
                
Preferred stock dividends of subsidiary 0.3
 0.3
 0.9
 0.9
 0.3
 0.3
 0.9
 0.9
Comprehensive loss attributed to noncontrolling interests 0.3
 —
 0.5
 —
Comprehensive income attributed to common shareholders $215.3
 $216.3
 $770.6
 $743.7
 $233.8
 $233.1
 $885.6
 $853.8


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




09/30/20172019 Form 10-Q4WEC Energy Group, Inc.
Table of Contents


WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in millions, except share and per share amounts)
 September 30, 2017 December 31, 2016 September 30, 2019 December 31, 2018
Assets        
Current assets        
Cash and cash equivalents $18.1
 $37.5
 $20.0
 $84.5
Accounts receivable and unbilled revenues, net of reserves of $112.7 and $108.0, respectively 948.0
 1,241.7
Accounts receivable and unbilled revenues, net of reserves of $137.8 and $149.2, respectively 911.8
 1,280.9
Materials, supplies, and inventories 672.2
 587.6
 593.3
 548.2
Prepayments 142.0
 204.4
 166.1
 256.8
Other 43.0
 97.5
 81.8
 77.2
Current assets 1,823.3
 2,168.7
 1,773.0
 2,247.6
        
Long-term assets        
Property, plant, and equipment, net of accumulated depreciation of $8,525.5 and $8,214.6, respectively 20,882.9
 19,915.5
Property, plant, and equipment, net of accumulated depreciation and amortization of $8,807.7 and $8,636.6, respectively 23,035.1
 22,000.9
Regulatory assets 3,107.7
 3,087.9
 3,999.9
 3,805.1
Equity investment in transmission affiliate 1,560.8
 1,443.9
Equity investment in transmission affiliates 1,720.4
 1,665.3
Goodwill 3,053.5
 3,046.2
 3,052.8
 3,052.8
Other 584.8
 461.0
 796.0
 704.1
Long-term assets 29,189.7
 27,954.5
 32,604.2
 31,228.2
Total assets $31,013.0
 $30,123.2
 $34,377.2
 $33,475.8
        
Liabilities and Equity        
    
Current liabilities        
Short-term debt $993.5
 $860.2
 $686.4
 $1,440.1
Current portion of long-term debt 709.3
 157.2
 692.6
 365.0
Accounts payable 743.9
 861.5
 769.0
 876.4
Accrued payroll and benefits 136.8
 163.8
 167.0
 185.4
Other 442.6
 388.9
 503.4
 464.8
Current liabilities 3,026.1
 2,431.6
 2,818.4
 3,331.7
        
Long-term liabilities        
Long-term debt 8,785.8
 9,158.2
 10,897.3
 9,994.0
Deferred income taxes 5,616.0
 5,146.6
 3,613.8
 3,388.1
Deferred revenue, net 549.2
 566.2
 502.8
 520.4
Regulatory liabilities 1,534.9
 1,563.8
 4,198.8
 4,251.6
Environmental remediation liabilities 617.7
 633.6
 631.8
 616.4
Pension and OPEB obligations 463.2
 498.6
 411.5
 422.8
Other 1,194.4
 1,164.4
 1,116.4
 1,108.1
Long-term liabilities 18,761.2
 18,731.4
 21,372.4
 20,301.4
        
Commitments and contingencies (Note 17) 
 
Commitments and contingencies (Note 21) 

 

        
Common shareholders' equity        
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,575,562 and 315,614,941 shares outstanding, respectively 3.2
 3.2
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,435,595 and 315,523,192 shares outstanding, respectively 3.2
 3.2
Additional paid in capital 4,281.4
 4,309.8
 4,185.0
 4,250.1
Retained earnings 4,908.3
 4,613.9
 5,869.9
 5,538.2
Accumulated other comprehensive income 2.4
 2.9
Accumulated other comprehensive loss (7.1) (2.6)
Common shareholders' equity 9,195.3
 8,929.8
 10,051.0
 9,788.9
        
Preferred stock of subsidiary 30.4
 30.4
 30.4
 30.4
Noncontrolling interests 105.0
 23.4
Total liabilities and equity $31,013.0
 $30,123.2
 $34,377.2
 $33,475.8


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



09/30/20172019 Form 10-Q5WEC Energy Group, Inc.
Table of Contents


WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended Nine Months Ended
 September 30 September 30
(in millions) 2017
2016 2019
2018
Operating Activities    
Operating activities    
Net income $772.0

$745.5
 $890.5

$855.2
Reconciliation to cash provided by operating activities        
Depreciation and amortization 593.5

581.5
 690.1

628.1
Deferred income taxes and investment tax credits, net 444.4

439.5
 58.8

34.4
Contributions and payments related to pension and OPEB plans (115.4) (23.5) (12.1) (13.8)
Equity income in transmission affiliate, net of distributions (18.5) (35.8)
Equity income in transmission affiliates, net of distributions (17.8) (4.5)
Change in –    ��   
Accounts receivable and unbilled revenues 310.5
 185.2
 360.2
 312.1
Materials, supplies, and inventories (84.1) 33.8
 (44.9) (69.0)
Other current assets 57.9
 88.5
 110.4
 112.7
Accounts payable (111.2) (94.7) (192.3) (71.2)
Other current liabilities 23.4
 (92.9) (1.8) 42.5
Other, net (125.8) (105.2) (0.4) 181.7
Net cash provided by operating activities 1,746.7
 1,721.9
 1,840.7
 2,008.2
        
Investing Activities    
Investing activities    
Capital expenditures (1,309.2)
(1,000.1) (1,511.5)
(1,490.5)
Acquisition of Bluewater (226.0) —
Capital contributions to transmission affiliate (63.3)
(27.1)
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2 (268.2) —
Acquisition of Bishop Hill III, net of restricted cash acquired of $4.5 —
 (143.5)
Acquisition of Forward Wind Energy Center —
 (77.1)
Capital contributions to transmission affiliates (37.3)
(43.7)
Proceeds from the sale of assets and businesses 22.7

161.2
 32.2

10.9
Withdrawal of restricted cash from rabbi trust for qualifying payments 18.7
 23.8
Proceeds from the sale of investments held in rabbi trust 0.2
 16.6
Reimbursement for ATC's construction costs 32.4
 —
Other, net 5.1

0.6
 17.7

7.3
Net cash used in investing activities (1,552.0) (841.6) (1,734.5) (1,720.0)
        
Financing Activities    
Financing activities    
Exercise of stock options 25.6
 40.4
 66.1
 13.9
Purchase of common stock (60.6) (105.6) (138.2) (42.0)
Dividends paid on common stock (492.4)
(468.6) (558.4)
(523.0)
Issuance of long-term debt 210.0
 200.0
 1,320.0
 600.0
Retirement of long-term debt (26.9) (253.5) (106.0) (694.4)
Change in short-term debt 133.3
 (305.6) (753.7) 343.7
Other, net (3.1) (12.2) (15.5) (4.8)
Net cash used in financing activities (214.1) (905.1) (185.7) (306.6)
        
Net change in cash and cash equivalents (19.4) (24.8)
Cash and cash equivalents at beginning of period 37.5

49.8
Cash and cash equivalents at end of period $18.1
 $25.0
Net change in cash, cash equivalents, and restricted cash (79.5) (18.4)
Cash, cash equivalents, and restricted cash at beginning of period 146.1

58.6
Cash, cash equivalents, and restricted cash at end of period $66.6
 $40.2


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




09/30/20172019 Form 10-Q6WEC Energy Group, Inc.
Table of Contents


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
Net loss attributed to noncontrolling interests —
 —
 —
 —
 —
 —
 (0.2) (0.2)
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 —
 —
 —
 —
 —
 —
 5.5
 5.5
Distributions to noncontrolling interests —
 —
 —
 —
 —
 —
 (0.9) (0.9)
Stock-based compensation and other —
 2.8
 —
 —
 2.8
 —
 0.1
 2.9
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
Net income attributed to common shareholders —
 —
 234.3
 —
 234.3
 —
 —
 234.3
Net loss attributed to noncontrolling interests —
 —
 —
 —
 —
 —
 (0.3) (0.3)
Other comprehensive loss —
 —
 —
 (0.5) (0.5) —
 —
 (0.5)
Common stock dividends of $0.59 per share —
 —
 (186.1) —
 (186.1) —
 —
 (186.1)
Exercise of stock options —
 16.0
 —
 —
 16.0
 —
 —
 16.0
Purchase of common stock —
 (31.9) —
 —
 (31.9) —
 —
 (31.9)
Capital contributions from noncontrolling interest —
 —
 —
 —
 —
 —
 4.3
 4.3
Distributions to noncontrolling interests —
 —
 —
 —
 —
 —
 (0.6) (0.6)
Stock-based compensation and other —
 3.0
 —
 —
 3.0
 —
 (0.1) 2.9
Balance at September 30, 2019 $3.2
 $4,185.0
 $5,869.9
 $(7.1) $10,051.0
 $30.4
 $105.0
 $10,186.4

09/30/2019 Form 10-Q7WEC Energy Group, Inc.
Table of Contents



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
Net income attributed to common shareholders —
 —
 233.2
 —
 233.2
 —
 —
 233.2
Other comprehensive loss —
 —
 —
 (0.1) (0.1) —
 —
 (0.1)
Common stock dividends of $0.5525 per share —
 —
 (174.3) —
 (174.3) —
 —
 (174.3)
Exercise of stock options —
 8.8
 —
 —
 8.8
 —
 —
 8.8
Purchase of common stock —
 (22.2) —
 —
 (22.2) —
 —
 (22.2)
Acquisition of a noncontrolling interest —
 —
 —
 —
 —
 —
 37.0
 37.0
Stock-based compensation and other —
 4.0
 0.1
 —
 4.1
 —
 —
 4.1
Balance at September 30, 2018 $3.2
 $4,261.6
 $5,508.1
 $2.4
 $9,775.3
 $30.4
 $37.0
 $9,842.7

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


09/30/2019 Form 10-Q8WEC Energy Group, Inc.
Table of Contents

WEC ENERGY GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 20172019


NOTE 1—GENERAL INFORMATION


WEC Energy Group serves approximately 1.6 million electric customers and 2.82.9 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 September 30, 2019 related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. 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, 2016.2018. 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 nine months ended September 30, 2017,2019, are not necessarily indicative of expected results for 20172019 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 Wind Generation Facilities in Nebraska

In August 2019, we signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million. The project has a 12-year offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility. Under the Tax Legislation, our investment in Thunderhead is expected to qualify for production tax credits and 100% bonus depreciation. The transaction is subject to FERC approval and commercial operation is expected to begin at the end of 2020, at which time the transaction is expected to close. Thunderhead will be included in the non-utility energy infrastructure segment.

In January 2019, we completed the acquisition of an 80% ownership interest in Upstream, a commercially operational 202.5 MW wind generating facility, for $268.2 million, which included transaction costs and is net of cash and restricted cash acquired of $9.2 million. Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over a 10-year period through an agreement with an unaffiliated third party. Under the Tax Legislation, our investment in Upstream qualifies for production tax credits and 100% bonus depreciation. Upstream is included in the non-utility energy infrastructure segment.


09/30/2019 Form 10-Q9WEC Energy Group, Inc.
Table of Contents

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. We are entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Coyote Ridge is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Illinois

In August 2018, we completed the acquisition of an 80% ownership 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% ownership 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


In October 2017,April 2018, WPS, along with two other2 unaffiliated utilities, entered into an agreement tocompleted the purchase theof Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129 MWs.138 MW. The aggregate purchase price is approximately $174was $172.9 million of which WPS’s proportionate share iswas 44.6%, or approximately $78$77.1 million. In addition, we incurred transaction costs that are recorded to a regulatory asset. Since 2008 and up until the acquisition, WPS currently purchasespurchased 44.6% of the facility’s energy output under a power purchase agreement. The transaction

Under a joint ownership agreement with the 2 other utilities, WPS is subjectentitled to PSCWgenerating capability and FERC approvals and is expected to close in the spring of 2018.

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 will provide approximately one-thirdoutput of the current storage needs for our Wisconsin natural gas utilities. In addition, we incurred $4.9 millionfacility equal to its ownership interest. WPS is also paying its ownership share of acquisition related costs.

The table below shows the allocation of the purchase price to the assets acquiredadditional capital expenditures 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. Bluewateroperating expenses. Forward Wind Energy Center is included in the non-utility energy infrastructureWisconsin segment. See Note 15, Segment Information, for more information.

(in millions)  
Current assets $2.0
Net property, plant, and equipment 217.6
Goodwill 7.3
Current liabilities (0.9)
Total purchase price $226.0


09/30/2017 Form 10-Q7WEC Energy Group, Inc.
Table of Contents

NOTE 3—DISPOSITIONSDISPOSITION


WisconsinCorporate and Other Segment

– Sale of Milwaukee CountyCertain WPS Power PlantDevelopment, LLC Solar Power Generation Facilities


In April 2016,June 2019, we sold the MCPP steam3 solar power generation and distribution assets,facilities owned by PDL for $20.0 million. These solar facilities were located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings.Massachusetts. During the second quarter of 2016,2019, we recorded a pre-taxan after-tax gain on the sale of $10.9$4.9 million ($6.5 million after tax),primarily related to the recognition of deferred investment tax credits, which waswere included in other operation and maintenanceincome tax 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 of this plantthese facilities 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.


Corporate
NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2018 Annual Report on Form 10-K.


09/30/2019 Form 10-Q10WEC Energy Group, Inc.
Table of Contents

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 revenues 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.
(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 September 30, 2019  
  
    
    
  
  
Electric $1,185.4
 $—
 $—
 $1,185.4
 $—
 $—
 $—
 $1,185.4
Natural gas 151.1
 190.0
 43.8
 384.9
 8.9
 —
 (8.4) 385.4
Total regulated revenues 1,336.5
 190.0
 43.8
 1,570.3
 8.9
 —
 (8.4) 1,570.8
Other non-utility revenues —
 —
 4.2
 4.2
 12.0
 1.3
 (0.7) 16.8
Total revenues from contracts with customers 1,336.5
 190.0
 48.0
 1,574.5
 20.9
 1.3
 (9.1) 1,587.6
Other operating revenues 2.8
 8.0
 0.9
 11.7
 98.5
 —
 (89.8) 20.4
Total operating revenues $1,339.3
 $198.0
 $48.9
 $1,586.2
 $119.4
 $1.3
 $(98.9) $1,608.0

(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 September 30, 2018  
  
    
    
  
  
Electric $1,218.3
 $—
 $—
 $1,218.3
 $—
 $—
 $—
 $1,218.3
Natural gas 167.4
 193.2
 45.9
 406.5
 10.0
 —
 (12.7) 403.8
Total regulated revenues 1,385.7
 193.2
 45.9
 1,624.8
 10.0
 —
 (12.7) 1,622.1
Other non-utility revenues —
 0.1
 4.0
 4.1
 7.9
 2.3
 (0.7) 13.6
Total revenues from contracts with customers 1,385.7
 193.3
 49.9
 1,628.9
 17.9
 2.3
 (13.4) 1,635.7
Other operating revenues 3.0
 4.6
 0.3
 7.9
 97.3
 0.1
 (97.3) 8.0
Total operating revenues $1,388.7
 $197.9
 $50.2
 $1,636.8
 $115.2
 $2.4
 $(110.7) $1,643.7


(in millions) Wisconsin Illinois Other States 
Total Utility
Operations
 Non-Utility Energy Infrastructure 
Corporate
and Other
 
Reconciling
Eliminations
 WEC Energy Group Consolidated
Nine Months Ended September 30, 2019  
  
    
    
  
  
Electric $3,269.1
 $—
 $—
 $3,269.1
 $—
 $—
 $—
 $3,269.1
Natural gas 943.3
 967.4
 293.0
 2,203.7
 35.1
 —
 (32.2) 2,206.6
Total regulated revenues 4,212.4
 967.4
 293.0
 5,472.8
 35.1
 —
 (32.2) 5,475.7
Other non-utility revenues —
 0.1
 12.5
 12.6
 40.6
 3.6
 (4.5) 52.3
Total revenues from contracts with customers 4,212.4
 967.5
 305.5
 5,485.4
 75.7
 3.6
 (36.7) 5,528.0
Other operating revenues 13.6
 9.9
 (2.6) 20.9
 294.8
 0.3
 (268.4) 47.6
Total operating revenues $4,226.0
 $977.4
 $302.9
 $5,506.3
 $370.5
 $3.9
 $(305.1) $5,575.6


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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
Nine Months Ended September 30, 2018  
  
    
    
  
  
Electric $3,370.2
 $—
 $—
 $3,370.2
 $—
 $—
 $—
 $3,370.2
Natural gas 921.8
 974.6
 287.5
 2,183.9
 34.9
 —
 (27.9) 2,190.9
Total regulated revenues 4,292.0
 974.6
 287.5
 5,554.1
 34.9
 —
 (27.9) 5,561.1
Other non-utility revenues —
 0.2
 11.8
 12.0
 24.3
 6.4
 (4.5) 38.2
Total revenues from contracts with customers 4,292.0
 974.8
 299.3
 5,566.1
 59.2
 6.4
 (32.4) 5,599.3
Other operating revenues 11.3
 (1.6) (6.8) 2.9
 291.1
 0.5
 (291.1) 3.4
Total operating revenues $4,303.3
 $973.2
 $292.5
 $5,569.0
 $350.3
 $6.9
 $(323.5) $5,602.7


Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:
  Electric Utility Operating Revenues
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Residential $454.7
 $465.3
 $1,218.1
 $1,243.3
Small commercial and industrial 385.6
 388.2
 1,050.8
 1,072.2
Large commercial and industrial 237.9
 249.7
 668.0
 695.2
Other 6.9
 7.5
 22.0
 22.4
Total retail revenues 1,085.1
 1,110.7
 2,958.9
 3,033.1
Wholesale 53.1
 62.0
 145.4
 175.3
Resale 29.5
 40.7
 119.7
 139.6
Steam 2.4
 2.7
 16.8
 16.9
Other utility revenues 15.3
 2.2
 28.3
 5.3
Total electric utility operating revenues $1,185.4
 $1,218.3
 $3,269.1
 $3,370.2


Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:
(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2019  
  
    
Residential $69.3
 $117.6
 $22.5
 $209.4
Commercial and industrial 30.0
 29.3
 11.5
 70.8
Total retail revenues 99.3
 146.9
 34.0
 280.2
Transport 14.4
 44.3
 5.6
 64.3
Other utility revenues * 37.4
 (1.2) 4.2
 40.4
Total natural gas utility operating revenues $151.1
 $190.0
 $43.8
 $384.9


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(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2018  
  
    
Residential $71.9
 $112.7
 $20.1
 $204.7
Commercial and industrial 35.0
 29.4
 12.6
 77.0
Total retail revenues 106.9
 142.1
 32.7
 281.7
Transport 13.9
 43.3
 4.9
 62.1
Other utility revenues * 46.6
 7.8
 8.3
 62.7
Total natural gas utility operating revenues $167.4
 $193.2
 $45.9
 $406.5


(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2019  
  
    
Residential $579.4
 $625.7
 $187.0
 $1,392.1
Commercial and industrial 285.5
 190.6
 104.0
 580.1
Total retail revenues 864.9
 816.3
 291.0
 1,972.2
Transport 52.5
 178.3
 23.0
 253.8
Other utility revenues * 25.9
 (27.2) (21.0) (22.3)
Total natural gas utility operating revenues $943.3
 $967.4
 $293.0
 $2,203.7

(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2018  
  
    
Residential $556.7
 $609.0
 $181.2
 $1,346.9
Commercial and industrial 286.4
 186.1
 96.0
 568.5
Total retail revenues 843.1
 795.1
 277.2
 1,915.4
Transport 51.3
 175.6
 21.6
 248.5
Other utility revenues * 27.4
 3.9
 (11.3) 20.0
Total natural gas utility operating revenues $921.8
 $974.6
 $287.5
 $2,183.9


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

Other SegmentNatural Gas Operating Revenues


SaleWe 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. All amounts associated with services from affiliates have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of Bostco Real Estate Holdingsthe following:

  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
We Power revenues (1)
 $6.4
 $6.4
 $19.1
 $19.0
Appliance service revenues 4.2
 4.0
 12.5
 11.8
Distributed renewable solar project revenues 1.3
 2.3
 3.6
 6.4
Wind generation revenues (2)
 4.9
 0.8
 17.0
 0.8
Other —
 0.1
 0.1
 0.2
Total other non-utility operating revenues $16.8
 $13.6
 $52.3
 $38.2

In March 2017, we sold
(1)
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 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 this contract liability to

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revenues over the remaining real estate holdingslife of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space.the related lease term that We Power has with WE. During the first quarter of 2017,three and nine months ended September 30, 2019, we recorded an insignificant gain on$6.4 million and $19.1 million of revenue, respectively, related to amortization of these deferred carrying costs. During the sale, which was included in other income, net on our income statements. The assets included in the sale were not materialthree and therefore, were not presented as held for sale. The resultsnine months ended September 30, 2018, we recorded $6.4 million and $19.0 million of operations associated withrevenue, respectively, related to amortization of these assets 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.deferred carrying costs.


(2)
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.

Sale of Certain Assets of WisvestOther Operating Revenues


In April 2016, as partOther operating revenues consist primarily of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which were used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $19.6 million ($11.8 million after tax), which was included in other income, net on our income statements. following:
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Alternative revenues * $1.4
 $(1.9) $(17.2) $(32.2)
Late payment charges 9.7
 9.4
 34.9
 31.9
Other 9.3
 0.5
 29.9
 3.7
Total other operating revenues $20.4
 $8.0
 $47.6
 $3.4

*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.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Sale of Integrys Transportation Fuels

Through a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was no gain or loss recorded on the sales, as ITF'sfollowing regulatory assets and liabilities were adjusted to fair value through purchase accountingreflected on our balance sheets at September 30, 2019 and presented as held for sale through the sale date. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shiftDecember 31, 2018. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our corporate strategy and did not have a major effect2018 Annual Report on our operations and financial results. The pre-tax profit or lossForm 10-K.
(in millions) September 30, 2019 December 31, 2018
Regulatory assets    
Pension and OPEB costs $1,126.5
 $1,193.5
Plant retirements * 1,032.1
 832.3
Environmental remediation costs 719.6
 687.1
Income tax related items 451.0
 369.1
SSR 320.1
 316.7
Asset retirement obligations 222.5
 185.4
Uncollectible expense 39.7
 38.7
We Power generation 29.9
 43.0
Electric transmission costs 16.6
 58.1
Energy efficiency programs 5.1
 14.0
Other, net 73.1
 117.9
Total regulatory assets $4,036.2
 $3,855.8
     
Balance sheet presentation    
Other current assets $36.3
 $50.7
Regulatory assets 3,999.9
 3,805.1
Total regulatory assets $4,036.2
 $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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(in millions) September 30, 2019 December 31, 2018
Regulatory liabilities    
Income tax related items $2,358.6
 $2,406.6
Removal costs 1,313.3
 1,329.6
Pension and OPEB benefits 227.1
 238.3
Mines deferral 132.1
 120.8
Decoupling 46.9
 30.5
Energy costs refundable through rate adjustments 45.2
 39.6
Energy efficiency programs 33.4
 31.7
Uncollectible expense 32.3
 30.5
Earnings sharing mechanisms 28.5
 30.0
Derivatives 18.6
 16.4
Other, net 12.2
 14.4
Total regulatory liabilities $4,248.2
 $4,288.4
     
Balance sheet presentation    
Other current liabilities $49.4
 $36.8
Regulatory liabilities 4,198.8
 4,251.6
Total regulatory liabilities $4,248.2
 $4,288.4


NOTE 4—6—PROPERTY, PLANT, AND EQUIPMENT


Presque Isle Power Plant


In October 2017,Pursuant to MISO's April 2018 approval of the MPSC approved UMERC’s application to construct and operate approximately 180 MWs of natural gas-fired generation in the Upper Peninsula of Michigan. Upon receiving this approval, early retirement of the PIPP, generatingthese units became probable.were retired on March 31, 2019. The new units are expected to begin commercial operation in 2019 and should allow forcarrying value of the retirement of PIPP no later than 2020. Thewas $164.6 million at September 30, 2019. This amount included the net book value of these units$176.3 million, which was $203.0classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. In addition, an $11.7 million cost of removal reserve related to the PIPP remained classified as a regulatory liability at September 30, 2017. These units are currently included in rate base,2019. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. WE continuesand UMERC continue to depreciate themamortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW. The net bookPSCW before the units were retired. Amortization is included in depreciation and amortization in the income statement. WE has FERC approval to continue to collect the carrying value of these assetsthe PIPP 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 proceedings.

Pleasant Prairie Power Plant

WE has FERC approval to continue to collect the carrying value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining carrying value. Collection of the return on and of the carrying value is no longer subject to refund as the FERC completed its prudency review and concluded that the retirement of this plant was transferred fromprudent.

2019 Rate Application

WE will address the accounting and regulatory treatment related to the retirement of the Pleasant Prairie power plant and the PIPP with the PSCW in serviceconjunction with its 2019 rate case. WPS will address the accounting and regulatory treatment related to plant to be retired.the retirement of Pulliam units 7 and 8 and the Edgewater 4 generating unit with the PSCW in conjunction with its 2019 rate case. See Note 19,23, Regulatory Environment, for more information regarding UMERC’s application.information.



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EdgewaterSeverance Liability for Plant Retirements


As a result ofWe have evaluated future plans for our older and less efficient fossil fuel generating units and have retired several plants within the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, early retirement of the Edgewater 4 generating unitWisconsin segment. A severance liability was probable at September 30, 2017. The net book value of our ownership share of this generating unit was $13.3 million at September 30, 2017. This amount was classified as plant to be retired within property, plant, and equipmentrecorded in other current liabilities on our balance sheet. This unit is currently included in rate base, and WPS continuessheets related to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 17, Commitments and Contingencies, for more information regarding the Consent Decree.these plant retirements.
(in millions)  
Severance liability at December 31, 2018 $15.7
Severance payments (7.2)
Other (3.1)
Total severance liability at September 30, 2019 $5.4


NOTE 5—7—COMMON EQUITY


Stock-Based Compensation


During the first quarter of 2017,2019, 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)
 552,215476,418

Restricted shares (2)
 82,62297,343

Performance units 237,650148,036



(1) 
Stock options awarded had a weighted-average exercise price of $58.31$68.18 and a weighted-average grant date fair value of $7.45$8.60 per option.


(2) 
Restricted shares awarded had a weighted-average grant date fair value of $58.10$68.18 per share.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the nine months ended September 30, 2017:
(in millions) Retained Earnings
Balance at December 31, 2016 $4,613.9
Net income attributed to common shareholders 771.1
Common stock dividends (492.4)
Cumulative effect of adoption of ASU 2016-09 15.7
Balance at September 30, 2017 $4,908.3

ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.


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 11,10, Common Equity, in our 20162018 Annual Report on Form 10-K for additional information on these and other restrictions.


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


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Common Stock Dividends


On October 19, 2017,17, 2019, our Board of Directors declared a quarterly cash dividend of $0.52$0.59 per share, payable on December 1, 2017,2019, to stockholdersshareholders of record on November 14, 2017.2019.


NOTE 6—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) September 30, 2019 December 31, 2018
Commercial paper    
Amount outstanding $686.4
 $1,440.1
Weighted-average interest rate on amounts outstanding 2.23% 2.92%

(in millions, except percentages) September 30, 2017 December 31, 2016
Commercial paper    
Amount outstanding $993.5
 $860.2
Weighted-average interest rate on amounts outstanding 1.38% 0.96%


Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2017,2019 was $705.0$1,190.7 million with a weighted-average interest rate during the period of 1.21%2.67%.



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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 September 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   686.4
Available capacity under existing credit facility   $2,111.1

(in millions) Maturity September 30, 2017
WEC Energy Group (1)
 December 2020 $1,050.0
WE (2)
 December 2020 500.0
WPS (3)
 December 2020 250.0
WG (2)
 December 2020 350.0
PGL (2)
 December 2020 350.0
Total short-term credit capacity   $2,500.0
Less:    
Letters of credit issued inside credit facilities   $32.9
Commercial paper outstanding   993.5
Available capacity under existing agreements   $1,473.6

(1)
In October 2017, WEC Energy Group increased its credit facility to $1,200.0 million, and extended the maturity to October 2022.

(2)
In October 2017, WE, WG, and PGL extended the maturities of their credit facilities to October 2022.

(3)
In October 2017, WPS increased its credit facility to $400.0 million. WPS intends to request approval from the PSCW to extend the maturity of its facility to October 2022.

NOTE 7—9—LONG-TERM DEBT


Effective May 2017, the $500.0WEC Energy Group, Inc.

In March 2019, we issued $350.0 million of 2007 Junior Notes bear interest at the three-month LIBOR plus 211.25 basis points, and reset quarterly.

In June 2017, MERC issued $120.0 million of senior notes. The senior notes were issued in three tranches: $40.0 million of 3.11%3.10% Senior Notes due July 15, 2027; $40.0March 8, 2022. We used the net proceeds to repay short-term debt and for working capital and other general corporate purposes.

Wisconsin Public Service Corporation

In August 2019, WPS issued $300.0 million of 3.41%3.30% Senior Notes due July 15, 2032;September 1, 2049, and $40.0used the net proceeds to repay short-term debt and for working capital and other corporate purposes.

Upper Michigan Energy Resources Corporation

In August 2019, UMERC issued $160.0 million of 4.01%3.26% Senior Notes due July 15, 2047. NetAugust 28, 2029, and used the net proceeds wereto redeem its long-term debt to WEC Energy Group and for working capital and general corporate purposes.

ATC Holding LLC

In September 2019, ATC Holding issued $235.0 million of 3.75% Senior Notes due September 16, 2029, and used the net proceeds to balance its capital structure.

The Peoples Gas Light and Coke Company

In September 2019, PGL issued $275.0 million of 2.96% Bonds, Series GGG due September 1, 2029. PGL used the net proceeds to repay MERC's $78.0PGL's $75.0 million aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were usedof 4.63% Bonds, Series UU which matured in September 2019, and for general corporate purposes, including capital expenditures and the repayment of short-term debt borrowed from Integrys.debt.

In June 2017, MGUNovember 2019, PGL issued $90.0$75.0 million of senior notes. The senior notes were issued in three tranches: $30.02.64% Bonds, Series HHH due November 1, 2024 and $50.0 million of 3.11% Senior Notes3.06% Bonds, Series III due July 15, 2027; $30.0 million of 3.41% Senior Notes due July 15, 2032; and $30.0 million of 4.01% Senior Notes due July 15, 2047. NetNovember 1, 2031. PGL used the net proceeds were used to repay MGU's $71.0 million aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including capital expenditures and the repayment of short-term debt.

Wisconsin Gas LLC

In October 2019, WG issued $150.0 million of 2.38% Debentures due November 1, 2024, and used the net proceeds to repay short-term debt borrowed from Integrys.and for working capital and other corporate purposes.




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NOTE 8—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 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 following practical expedients, which were available under ASU 2016-02, in our adoption 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 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. NaN impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842.

In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in NaN 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 power purchase agreement that meets the criteria of a finance lease, while the adoption of Topic 842 changed the classification of expense related to this lease on a prospective basis, it had 0 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.

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Obligations Under Finance Leases

Power Purchase Commitment

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 0 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. At lease inception we 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 in cost of sales on our income statements.
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 cost of sales in our income statements, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases.
In accordance with Topic 980-842, 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, as 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.

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 0 over the remaining life of the contract. The total obligation under the finance lease was $19.7 million at September 30, 2019, and will decrease to 0 over the remaining life of the contract.

Two Creeks Solar Project

Related to its investment in Two Creeks, 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 2 optional 10-year extensions. We expect the 2 optional extensions to be exercised, and, as a result, the land leases will be amortized over the 50-year extended term of the leases. The lease payments are expected to be recovered through rates.

We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Two Creeks was $7.7 million as of September 30, 2019, and will decrease to 0 over the remaining lives of the leases.

Badger Hollow Solar Farm I

Related to its investment in Badger Hollow I, WPS, along with an unaffiliated utility, entered into several land leases in Iowa County, Wisconsin that commenced in the third quarter of 2019. The leases are for a total of approximately 1,500 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases will be amortized over the extended term of the leases. The lease payments are expected to be recovered through rates.


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We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Badger Hollow I was $21.0 million as of September 30, 2019, and will decrease to 0 over the remaining lives of the leases.

Amounts Recognized in the Financial Statements

The components of lease expense and supplemental cash flow information related to our leases for the three and nine months ended September 30 are as follows:
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Finance/capital lease expense (1)
 $2.1
 $2.0
 $6.2
 $5.8
Operating lease expense (2)
 1.3
 1.4
 4.1
 4.2
Short-term lease expense (2)
 0.1
 0.1
 0.2
 0.8
Total lease expense $3.5
 $3.5
 $10.5
 $10.8
         
Other information        
         
Cash paid for amounts included in the measurement of lease liabilities:        
Operating cash flows for finance/capital leases (3)
     $2.6
 $5.8
Operating cash flows for operating leases     $4.9
 $4.9
Financing cash flows for finance leases (3)
     $3.6
 $—
         
Non-cash activities:        
Right of use assets obtained in exchange for finance lease liabilities     $28.7
  
Right of use assets obtained in exchange for operating lease liabilities     $49.0
  
         
Weighted-average remaining lease term – finance leases     31.5 years
  
Weighted-average remaining lease term – operating leases     13.0 years
  
         
Weighted average discount rate – finance leases (4)
     6.8%  
Weighted average discount rate – operating leases (4)
     4.4%  

(1)
For the three and nine months ended September 30, 2019, finance lease expense included amortization of right of use assets in the amount of $1.3 million and $3.6 million (included in depreciation and amortization expense), respectively, and interest on lease liabilities of $0.8 million and $2.6 million (included in interest expense), respectively. For each of the three and nine months ended September 30, 2018, total capital lease cost 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 nine months ended September 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 power purchase agreement that meets the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.


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The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets:
(in millions) September 30, 2019 December 31, 2018
Long-term power purchase commitment    
Under finance/capital lease $140.3
 $140.3
Accumulated amortization (125.2) (120.9)
Total long-term power purchase commitment $15.1
 $19.4
     
Two Creeks land leases    
Under finance leases $7.7
 $—
Accumulated amortization —
 —
Total Two Creeks land leases $7.7
 $—
     
Badger Hollow I land leases    
Under finance leases $21.0
 $—
Accumulated amortization —
 —
Total Badger Hollow I land leases $21.0
 $—
     
Total finance lease right of use assets/capital lease asset $43.8
 $19.4


Right of use assets related to operating leases were $43.8 million at September 30, 2019, and were included in other long-term assets on our balance sheets.

Future minimum lease payments under our operating leases and our finance leases, and the present value of our net minimum lease payments as of September 30, 2019, were as follows:
(in millions) Total Operating Leases Power Purchase Commitment Two Creeks Badger Hollow I Total Finance Leases
Three months ending December 31, 2019 $1.1
 $2.0
 $0.1
 $0.1
 $2.2
2020 6.9
 8.8
 0.2
 0.4
 9.4
2021 4.9
 9.4
 0.2
 0.7
 10.3
2022 4.9
 4.2
 0.2
 0.7
 5.1
2023 5.0
 —
 0.2
 0.7
 0.9
2024 4.8
 —
 0.2
 0.8
 1.0
Thereafter 30.5
 —
 22.8
 57.7
 80.5
Total minimum lease payments 58.1
 24.4
 23.9
 61.1
 109.4
Less: Interest (14.9) (4.7) (16.2) (40.1) (61.0)
Present value of minimum lease payments 43.2
 19.7
 7.7
 21.0
 48.4
Less: Short-term lease liabilities (4.4) (5.9) —
 —
 (5.9)
Long-term lease liabilities $38.8
 $13.8
 $7.7
 $21.0
 $42.5


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 leases 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 generating facilities. 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

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concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

As of November 7, 2019, we have not entered into any material leases that have not yet commenced.

NOTE 11—MATERIALS, SUPPLIES, AND INVENTORIES


Our inventory consisted of:
(in millions) September 30, 2019 December 31, 2018
Natural gas in storage $266.4
 $232.9
Materials and supplies 236.7
 226.6
Fossil fuel 90.2
 88.7
Total $593.3
 $548.2

(in millions) September 30, 2017 December 31, 2016
Natural gas in storage $301.5
 $223.1
Materials and supplies 225.1
 206.5
Fossil fuel 145.6
 158.0
Total $672.2
 $587.6


PGL and NSG price natural gas storage injections at the calendar year average of the costcosts of natural gas supply purchased. Withdrawals from storage are priced usingon 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 on the balance sheet as a temporary LIFO liquidation debit or credit.liquidation. At September 30, 2017,2019, all LIFO layers were replenished, and the LIFO liquidation balance was zero.0.


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


NOTE 9—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 September 30, 2019 Three Months Ended September 30, 2018
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $51.5
 21.0 % $52.6
 21.0 %
State income taxes net of federal tax benefit 20.3
 8.2 % 16.0
 6.4 %
Tax repairs (30.7) (12.5)% (35.8) (14.3)%
Federal excess deferred tax amortization (12.0) (4.9)% (3.2) (1.3)%
Wind production tax credits (6.8) (2.8)% (4.5) (1.8)%
Excess tax benefits – stock options (3.9) (1.6)% (0.9) (0.4)%
Other (7.1) (2.8)% (7.2) (2.8)%
Total income tax expense $11.3
 4.6 % $17.0
 6.8 %


  Nine Months Ended September 30, 2019 Nine Months Ended September 30, 2018
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $206.1
 21.0 % $212.3
 21.0 %
State income taxes net of federal tax benefit 66.8
 6.8 % 63.6
 6.3 %
Tax repairs (90.7) (9.2)% (83.9) (8.3)%
Federal excess deferred tax amortization (32.7) (3.3)% (17.2) (1.7)%
Wind production tax credits (26.4) (2.7)% (10.4) (1.0)%
Excess tax benefits – stock options (15.5) (1.6)% (2.9) (0.3)%
Other (16.1) (1.7)% (5.1) (0.5)%
Total income tax expense $91.5
 9.3 % $156.4
 15.5 %


The effective tax rates of 4.6% and 9.3% for the three and nine months ended September 30, 2019, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement, the impact of the Tax Legislation, and wind production tax credits generated from acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment, partially offset by state income taxes.

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The effective tax rates of 6.8% and 15.5% for the three and nine months ended September 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 2017 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 we began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 23, Regulatory Environment, for more information.

NOTE 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).


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


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


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


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


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


When possible, we base the valuations of our 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.



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The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
 September 30, 2017 September 30, 2019
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Derivative assets                
Natural gas contracts $2.8
 $3.7
 $—
 $6.5
 $5.2
 $3.7
 $—
 $8.9
Petroleum products contracts 1.0
 —
 —
 1.0
FTRs —
 —
 7.3
 7.3
 —
 —
 6.2
 6.2
Coal contracts —
 0.9
 —
 0.9
 —
 0.6
 —
 0.6
Total derivative assets $3.8
 $4.6
 $7.3
 $15.7
 $5.2
 $4.3
 $6.2
 $15.7
                
Investments held in rabbi trust $113.5
 $—
 $—
 $113.5
 $78.2
 $—
 $—
 $78.2
                
Derivative liabilities                
Natural gas contracts $1.5
 $2.5
 $—
 $4.0
 $23.4
 $1.1
 $—
 $24.5
Coal contracts —
 2.1
 —
 2.1
 —
 0.2
 —
 0.2
Interest rate swaps —
 6.9
 —
 6.9
Total derivative liabilities $1.5
 $4.6
 $—
 $6.1
 $23.4
 $8.2
 $—
 $31.6


  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

  December 31, 2016
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $10.1
 $24.2
 $—
 $34.3
Petroleum products contracts 0.2
 —
 —
 0.2
FTRs —
 —
 5.1
 5.1
Coal contracts —
 2.0
 —
 2.0
Total derivative assets $10.3
 $26.2
 $5.1
 $41.6
         
Investments held in rabbi trust $103.9
 $—
 $—
 $103.9
         
Derivative liabilities        
Natural gas contracts $0.2
 $0.2
 $—
 $0.4
Petroleum products contracts 0.1
 —
 —
 0.1
Coal contracts —
 1.9
 —
 1.9
Total derivative liabilities $0.3
 $2.1
 $—
 $2.4


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 September 30, 2019 and 2018, the net unrealized gains included in earnings related to the investments held at the end of the period were $0.7 million and $7.1 million, respectively. For the nine months ended September 30, 2019 and 2018, the net unrealized gains included in earnings related to the investments held at the end of the period were $12.1 million and $7.5 million, respectively.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Balance at the beginning of the period $10.4
 $16.7
 $7.4
 $4.4
Purchases —
 —
 12.8
 18.4
Settlements (4.2) (5.2) (14.0) (11.3)
Balance at the end of the period $6.2
 $11.5
 $6.2
 $11.5

  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Balance at the beginning of the period $11.8
 $13.4
 $5.1
 $3.6
Realized and unrealized losses —
 —
 —
 (0.2)
Purchases —
 —
 13.8
 15.2
Sales —
 —
 —
 (0.2)
Settlements (4.5) (4.2) (11.6) (9.2)
Balance at the end of the period $7.3
 $9.2
 $7.3
 $9.2


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



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Fair Value of Financial Instruments


The following table shows the financial instruments included on our balance sheets that arewere not recorded at fair value:
  September 30, 2019 December 31, 2018
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock of subsidiary $30.4
 $29.2
 $30.4
 $28.3
Long-term debt, including current portion * 11,541.5
 12,751.7
 10,335.7
 10,554.9

  September 30, 2017 December 31, 2016
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $29.6
 $30.4
 $28.8
Long-term debt, including current portion * 9,467.5
 10,135.2
 9,285.8
 9,818.2


*The carrying amount of long-term debt excludes finance and capital lease obligations of $27.6$48.4 million and $29.6$23.3 million at September 30, 20172019 and December 31, 2018, respectively.
December 31, 2016, respectively.

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.


NOTE 10—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.


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.


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:
  September 30, 2019 December 31, 2018
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
Natural gas contracts $8.9
 $22.3
 $7.7
 $5.3
FTRs 6.2
 —
 7.4
 —
Coal contracts 0.3
 0.1
 0.2
 0.1
Interest rate swaps —
 2.5
 —
 0.4
Total other current * 15.4
 24.9

15.3

5.8
         
Other long-term        
Natural gas contracts —
 2.2
 0.4
 0.2
Coal contracts 0.3
 0.1
 0.2
 —
Interest rate swaps —
 4.4
 —
 1.9
Total other long-term * 0.3
 6.7

0.6

2.1
Total $15.7
 $31.6
 $15.9
 $7.9

  September 30, 2017 December 31, 2016
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
Natural gas contracts $5.4
 $4.0
 $31.4
 $0.4
Petroleum products contracts 1.0
 —
 0.2
 0.1
FTRs 7.3
 —
 5.1
 —
Coal contracts 0.6
 1.4
 1.5
 1.4
   Total other current * $14.3
 $5.4

$38.2

$1.9
         
Other long-term        
Natural gas contracts $1.1
 $—
 $2.9
 $—
Coal contracts 0.3
 0.7
 0.5
 0.5
   Total other long-term * $1.4
 $0.7

$3.4

$0.5
Total $15.7
 $6.1
 $41.6
 $2.4


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




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Realized gains (losses) on 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 September 30, 2017
Three Months Ended September 30, 2016 Three Months Ended September 30, 2019 Three Months Ended September 30, 2018
(in millions) Volumes Gains (Losses) Volumes Gains (Losses) Volumes Gains (Losses) Volumes Gains
Natural gas contracts 24.9 Dth $(2.1) 30.5 Dth $(3.4) 37.8 Dth $(13.2) 36.7 Dth $0.4
Petroleum products contracts 4.4 gallons (0.5) 4.3 gallons (0.4) — gallons —
 1.3 gallons 0.5
FTRs 9.4 MWh 4.2
 9.9 MWh 7.1
 7.8 MWh 7.6
 7.9 MWh 7.1
Total   $1.6
   $3.3
   $(5.6)   $8.0


  Nine Months Ended September 30, 2019 Nine Months Ended September 30, 2018
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 137.7 Dth $(16.8) 124.7 Dth $(7.1)
Petroleum products contracts — gallons —
 5.1 gallons 1.3
FTRs 23.9 MWh 12.9
 22.9 MWh 14.7
Total   $(3.9)   $8.9

  Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 84.2 Dth $(1.1) 113.3 Dth $(56.9)
Petroleum products contracts 14.2 gallons (1.4) 10.9 gallons (2.5)
FTRs 28.0 MWh 9.4
 24.9 MWh 11.7
Total   $6.9
   $(47.7)


On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 20172019 and December 31, 2016,2018, we had posted cash collateral of $24.7$28.3 million and $16.4$2.7 million, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At December 31, 2016,2018, we had also received cash collateral of $4.4$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 September 30, 2019.


The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
 September 30, 2017 December 31, 2016 September 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 $15.7
 $6.1
 $41.6
 $2.4
 $15.7
 $31.6
 $15.9
 $7.9
 
Gross amount not offset on the balance sheet (3.0) (3.1)
(1) 
(4.9)
(2) 
(0.5) (5.7) (23.9)
(1) 
(4.0)
(2) 
(4.9)
(3) 
Net amount $12.7
 $3.0
 $36.7
 $1.9
 $10.0
 $7.7
 $11.9
 $3.0
 


(1)  
Includes cash collateral posted of $0.1$18.2 million.


(2) 
Includes cash collateral received of $4.4$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 September 30, 2019, we had 2 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 $2.3 millionaccumulated other comprehensive loss and $0.2 million at September 30, 2017 and December 31, 2016, respectively. At September 30, 2017 and December 31, 2016, 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 these commodity instruments. If allIntegrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the credit risk-related contingent features containedperiods in derivative instrumentswhich the interest costs are recognized in a net liability position had been triggered at September 30, 2017, we would have been required to post collateral of $0.8 million. At December 31, 2016, we would not have been required to post any collateral.earnings.




09/30/20172019 Form 10-Q1426WEC Energy Group, Inc.
Table of Contents


The table below shows the amounts related to these cash flow hedges recorded in other comprehensive loss and in earnings, along with our total interest expense on the income statements:
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Derivative (losses) gains recognized in other comprehensive loss $(0.5) $0.4
 $(5.3) $0.4
Net derivative gains reclassified from accumulated other comprehensive loss to interest expense 0.2
 0.2
 1.0
 1.3
Total interest expense line item on the income statements 125.8
 112.0
 374.3
 327.2


We estimate that during the next twelve months $0.5 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense.

NOTE 11—15—GUARANTEES


The following table shows our outstanding guarantees:
   Expiration   Expiration
(in millions) Total Amounts Committed at September 30, 2017 Less Than 1 Year 1 to 3 Years Over 3 Years Total Amounts Committed at September 30, 2019 Less Than 1 Year 1 to 3 Years Over 3 Years
Guarantees                
Guarantees supporting commodity transactions of subsidiaries (1)
 $8.1
 $8.1
 $—
 $—
 $6.7
 $6.7
 $—
 $—
Standby letters of credit (2)
 35.8
 28.7
 7.1
 —
 103.1
 1.0
 0.5
 101.6
Surety bonds (3)
 9.7
 9.7
 —
 —
 9.9
 9.9
 —
 —
Other guarantees (4)
 11.1
 0.5
 —
 10.6
 12.2
 —
 0.9
 11.3
Total guarantees $64.7
 $47.0
 $7.1
 $10.6
 $131.9
 $17.6
 $1.4
 $112.9


(1) 
Consists of $8.1Includes $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 $11.1$12.2 million related to other indemnifications, for which a liability of $10.6$11.3 million related to workers compensation coverage was recorded on our balance sheets.


NOTE 12—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 September 30 Nine Months Ended September 30 Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016 2019 2018 2019 2018
Service cost $11.1
 $10.9
 $33.2
 $32.9
 $11.6
 $11.9
 $34.7
 $35.7
Interest cost 30.3
 33.2
 91.7
 99.4
 30.3
 28.5
 91.1
 85.5
Expected return on plan assets (48.8) (49.0) (146.9) (147.0) (48.3) (49.2) (145.2) (147.6)
Loss on plan settlement 2.9
 0.7
 8.2
 14.8
 7.8
 0.4
 9.6
 1.1
Amortization of prior service cost 0.7
 0.9
 2.2
 2.6
 0.5
 0.7
 1.6
 2.0
Amortization of net actuarial loss 21.5
 20.4
 64.5
 61.1
 18.9
 23.6
 56.6
 70.6
Net periodic benefit cost $17.7
 $17.1
 $52.9
 $63.8
 $20.8
 $15.9
 $48.4
 $47.3


  OPEB Costs
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Service cost $6.0
 $6.5
 $17.9
 $19.6
Interest cost 8.4
 9.2
 25.3
 27.7
Expected return on plan assets (13.6) (13.2) (40.9) (39.6)
Amortization of prior service credit (2.8) (2.3) (8.4) (7.0)
Amortization of net actuarial loss 0.7
 2.2
 2.3
 6.4
Net periodic benefit (credit) cost $(1.3) $2.4
 $(3.8) $7.1

During the nine months ended September 30, 2017, we made payments of $109.8 million to our pension plans and $5.6 million to our OPEB plans. We expect to make payments of $3.8 million related to our pension plans and $3.9 million related to our OPEB plans during the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.



09/30/20172019 Form 10-Q1527WEC Energy Group, Inc.
Table of Contents


  OPEB Costs
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Service cost $4.1
 $5.9
 $12.3
 $17.7
Interest cost 6.5
 7.5
 19.3
 22.4
Expected return on plan assets (13.7) (14.9) (41.0) (44.6)
Amortization of prior service credit (3.9) (3.8) (11.6) (11.5)
Amortization of net actuarial (gain) loss (2.0) 0.3
 (4.7) 0.8
Net periodic benefit credit $(9.0) $(5.0) $(25.7) $(15.2)


During the nine months ended September 30, 2019, we made contributions and payments of $9.6 million related to our pension plans and $2.5 million related to our OPEB plans. We expect to make contributions and payments of $52.2 million related to our pension plans and $4.1 million related to our OPEB plans during the remainder of 2019, dependent upon various factors affecting us, including our liquidity position and the effects of the Tax Legislation.

NOTE 13—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 at September 30, 2019. We had 0 changes to the carrying amount of goodwill during the nine months ended September 30, 2017:2019.
(in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total
Goodwill balance as of January 1, 2017 $2,104.3
 $758.7
 $183.2
 $—
 $3,046.2
Acquisition of Bluewater (1)
 —
 —
 —
 7.3
 7.3
Goodwill balance as of September 30, 2017 (2)
 $2,104.3
 $758.7
 $183.2
 $7.3
 $3,053.5
(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 no0 accumulated impairment losses related to our goodwill as of September 30, 2017.2019.


In the third quarter of 2017,2019, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2017. No2019. NaN impairments resulted from these tests.


NOTE 14—18—INVESTMENT IN AMERICAN TRANSMISSION COMPANYAFFILIATES


We own approximately 60% of ATC, a for-profit, electric transmissiontransmission-only company regulated by the FERC for cost of service and certain state regulatory commissions.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 table showstables provide a reconciliation of the changes toin our investmentinvestments in ATC:ATC and ATC Holdco:
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended September 30, 2019
(in millions) 2017 2016 2017 2016 ATC ATC Holdco Total
Balance at beginning of period $1,544.0
 $1,425.0
 $1,443.9
 $1,380.9
  $1,656.6
 $39.9
 $1,696.5
Add: Earnings from equity method investment 39.2
 38.3
 122.9
 107.7
  38.3
 0.4
 38.7
Add: Capital contributions 12.8
 15.0
 63.3
 27.1
  15.1
 0.3
 15.4
Add: Acquisition of Integrys's investment in ATC —
 —
 —
 (1.0)
(1) 
Add: Adjustment to equity method goodwill —
 —
 —
 10.4
 
Less: Distributions 35.2
 25.2
 69.2
(2) 
71.9
  30.3
 —
 30.3
Less: Other —
 —
 0.1
 0.1
 
Add: Other 0.1
 —
 0.1
Balance at end of period $1,560.8
 $1,453.1
 $1,560.8
 $1,453.1
  $1,679.8
 $40.6
 $1,720.4


  Three Months Ended September 30, 2018
(in millions) ATC ATC Holdco Total
Balance at beginning of period $1,558.4
 $38.2
 $1,596.6
Add: Earnings (loss) from equity method investment 34.6
 (0.9) 33.7
Add: Capital contributions 9.1
 2.2
 11.3
Less: Distributions 27.8
 —
 27.8
Less: Other 0.1
 —
 0.1
Balance at end of period $1,574.2
 $39.5
 $1,613.7


09/30/2019 Form 10-Q28WEC Energy Group, Inc.
Table of Contents

  Nine Months Ended September 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 112.2
 (0.5) 111.7
Add: Capital contributions 36.2
 1.1
 37.3
Less: Distributions 93.9
 —
 93.9
Balance at end of period $1,679.8
 $40.6
 $1,720.4


  Nine Months Ended September 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 97.8
 (2.6) 95.2
Add: Capital contributions 39.2
 4.5
 43.7
Less: Distributions 78.5
(2) 
—
 78.5
Less: Other 0.1
 —
 0.1
Balance at end of period $1,574.2
 $39.5
 $1,613.7

(1) 
Amount reflects an adjustment to the allocation of the purchase price for Integrys made in the second quarter of 2016.

(2)
Distributions of $35.2$39.9 million, received in the first quarter of 2017,2018, were approved and recorded as a receivable from ATC in other current assets at December 2016.31, 2017.


(2)
Distributions of $27.7 million, received in the fourth quarter of 2018, were approved and recorded as a receivable from ATC in accounts receivable at September 30, 2018.

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 areis 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 September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Charges to ATC for services and construction $9.2
 $5.0
 $16.5
 $13.7
Charges from ATC for network transmission services 86.9
 84.4
 261.0
 253.5
Refund from ATC related to a FERC audit —
 —
 —
 22.0

  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Charges to ATC for services and construction $4.4
 $4.4
 $12.3
 $12.8
Charges from ATC for network transmission services 87.4
 89.3
 262.0
 271.4
Refund from ATC per FERC ROE order —
 —
 (28.3) —


Our balance sheets included the following receivables and payables for services received from or provided to ATC:

(in millions) September 30, 2019 December 31, 2018 
Accounts receivable for services provided to ATC $3.3
 $3.4
 
Accounts payable for services received from ATC 29.0
 28.2
 
Amounts due from ATC for transmission infrastructure upgrades 2.8
(1) 
29.4
(2) 


(1)
In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, WPS was required to initially fund the construction of the transmission infrastructure upgrades needed for the new generation. ATC owns these transmission assets and will reimburse WPS for these costs after the new generation has been placed in service.

(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 were needed for the new generation. In the second quarter of 2019, ATC fully reimbursed UMERC for these costs.


09/30/20172019 Form 10-Q1629WEC Energy Group, Inc.
Table of Contents

Our balance sheets included the following receivables and payables related to ATC:
(in millions) September 30, 2017 December 31, 2016
Accounts receivable    
Services provided to ATC $1.5
 $2.2
Accounts payable    
Services received from ATC 29.1
 28.7


Summarized financial data for ATC is included in the following tables:
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2019 2018 2019 2018
Income statement data        
Operating revenues $184.9
 $170.4
 $544.8
 $501.3
Operating expenses 94.7
 87.9
 278.7
 264.3
Other expense, net 28.7
 27.4
 86.1
 80.4
Net income $61.5
 $55.1
 $180.0
 $156.6

  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Income statement data        
Revenues $171.1
 $158.1
 $522.4
 $476.6
Operating expenses 85.0
 80.2
 250.1
 241.0
Other expense 27.5
 23.5
 79.6
 71.2
Net income $58.6
 $54.4
 $192.7

$164.4


(in millions) September 30, 2019 December 31, 2018
Balance sheet data    
Current assets $84.9
 $87.2
Noncurrent assets 5,178.8
 4,928.8
Total assets $5,263.7
 $5,016.0
     
Current liabilities $493.3
 $640.0
Long-term debt 2,312.6
 2,014.0
Other noncurrent liabilities 299.4
 295.3
Shareholders' equity 2,158.4
 2,066.7
Total liabilities and shareholders' equity $5,263.7
 $5,016.0

(in millions) September 30, 2017 December 31, 2016
Balance sheet data    
Current assets $89.0
 $75.8
Noncurrent assets 4,564.9
 4,312.9
Total assets $4,653.9
 $4,388.7
     
Current liabilities $772.1
 $495.1
Long-term debt 1,740.8
 1,865.3
Other noncurrent liabilities 213.8
 271.5
Shareholders' equity 1,927.2
 1,756.8
Total liabilities and shareholders' equity $4,653.9
 $4,388.7


NOTE 15—19—SEGMENT INFORMATION


We use operating income to measure segment profitability and to allocate resources to our businesses. At September 30, 2017,2019, we reported six6 segments, which are described below.


The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, WPS, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017.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 was formed to invest 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, electric transmission company regulated by the FERC and certain state regulatory commissions.

Following the acquisition of Bluewater, our We Power segment was renamed the non-utility energy infrastructure segment. This segment includes We Power, which owns and leases generating facilities to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. 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% ownership interest in Bishop Hill III, a wind generating facility located in Henry County, Illinois,
◦
Our 80% ownership interest in Coyote Ridge, a wind generating facility under construction in Brookings County, South Dakota, and
◦
Our 80% ownership interest in Upstream, a wind generating facility located in Antelope County, Nebraska.

See Note 2, Acquisitions, for more informationon the Bluewater transaction.
Bishop Hill III, Coyote Ridge, and 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, WPS Power DevelopmentWEC Business Services LLC, and ITF. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco and in the second quarter of 2016, we sold certain assets of Wisvest. The sale of ITF was completed in the first quarter of 2016. See Note 3, Dispositions, for more information on these sales.
PDL.




09/30/20172019 Form 10-Q1730WEC Energy Group, Inc.
Table of 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 nine months ended September 30, 20172019 and 2016:2018:
 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  
  
    
      
  
  
  
  
    
      
  
  
September 30, 2017                  
September 30, 2019                  
External revenues $1,401.3
 $187.2
 $49.8
 $1,638.3
 $—
 $13.6
 $5.6
 $—
 $1,657.5
 $1,339.3
 $198.0
 $48.9
 $1,586.2
 $—
 $20.5
 $1.3
 $—
 $1,608.0
Intersegment revenues —
 —
 —
 —
 —
 111.6
 —
 (111.6) —
 —
 —
 —
 —
 —
 98.9
 —
 (98.9) —
Other operation and maintenance 458.3
 100.8
 21.6
 580.7
 —
 1.5
 (1.5) (109.0) 471.7
 400.2
 101.8
 22.0
 524.0
 —
 3.9
 1.3
 —
 529.2
Depreciation and amortization 131.5
 38.9
 6.3
 176.7
 —
 18.2
 6.3
 —
 201.2
 155.6
 45.7
 6.8
 208.1
 —
 23.3
 6.0
 (3.6) 233.8
Operating income (loss) 279.7
 12.5
 (3.1) 289.1
 —
 103.4
 1.1
 —
 393.6
 290.8
 24.8
 (2.2) 313.4
 —
 90.3
 (6.0) (86.8) 310.9
Equity in earnings of transmission affiliate —
 —
 —
 —
 39.2
 —
 —
 —
 39.2
Equity in earnings of transmission affiliates —
 —
 —
 —
 38.7
 —
 —
 —
 38.7
Interest expense 48.5
 11.0
 2.3
 61.8
 —
 16.2
 25.4
 0.4
 103.8
 142.9
 14.7
 2.3
 159.9
 3.0
 15.5
 35.9
 (88.5) 125.8


  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  
  
    
      
  
  
September 30, 2018                  
External revenues $1,388.7
 $197.9
 $50.2
 $1,636.8
 $—
 $4.5
 $2.4
 $—
 $1,643.7
Intersegment revenues —
 —
 —
 —
 —
 110.7
 —
 (110.7) —
Other operation and maintenance 525.0
 104.5
 23.0
 652.5
 —
 3.0
 (4.4) (98.0) 553.1
Depreciation and amortization 137.2
 43.0
 6.4
 186.6
 —
 19.1
 7.1
 —
 212.8
Operating income (loss) 201.4
 15.5
 (5.4) 211.5
 —
 91.6
 (0.4) —
 302.7
Equity in earnings of transmission affiliates —
 —
 —
 —
 33.7
 —
 —
 —
 33.7
Interest expense 49.6
 12.8
 2.1
 64.5
 —
 15.9
 32.9
 (1.3) 112.0

  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  
  
    
      
  
  
September 30, 2016                  
External revenues $1,470.6
 $181.8
 $49.9
 $1,702.3
 $—
 $6.2
 $4.0
 $—
 $1,712.5
Intersegment revenues —
 —
 —
 —
 —
 105.0
 —
 (105.0) —
Other operation and maintenance 498.2
 105.9
 21.2
 625.3
 —
 0.4
 (3.2) (105.0) 517.5
Depreciation and amortization 124.5
 33.5
 5.2
 163.2
 —
 17.1
 11.3
 —
 191.6
Operating income (loss) 299.1
 11.7
 (1.0) 309.8
 —
 93.7
 (4.5) —
 399.0
Equity in earnings of transmission affiliate —
 —
 —
 —
 38.3
 —
 —
 —
 38.3
Interest expense 44.6
 9.3
 1.9
 55.8
 —
 15.6
 29.7
 (2.0) 99.1


  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
Nine Months Ended  
  
    
      
  
  
September 30, 2017                  
External revenues $4,316.6
 $965.7
 $273.4
 $5,555.7
 $—
 $26.1
 $11.7
 $—
 $5,593.5
Intersegment revenues —
 —
 —
 —
 —
 333.2
 —
 (333.2) —
Other operation and maintenance 1,379.9
 326.6
 73.2
 1,779.7
 —
 4.6
 (0.3) (330.6) 1,453.4
Depreciation and amortization 391.1
 112.6
 18.4
 522.1
 —
 53.1
 18.3
 —
 593.5
Operating income (loss) 835.6
 209.3
 35.0
 1,079.9
 —
 299.5
 (6.3) —
 1,373.1
Equity in earnings of transmission affiliate —
 —
 —
 —
 122.9
 —
 —
 —
 122.9
Interest expense 145.4
 33.0
 6.5
 184.9
 —
 46.7
 81.3
 (2.5) 310.4



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Table of Contents


 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
Nine Months Ended  
  
    
      
  
  
  
  
    
      
  
  
September 30, 2016                  
September 30, 2019                  
External revenues $4,354.9
 $853.1
 $262.3
 $5,470.3
 $—
 $18.7
 $20.3
 $—
 $5,509.3
 $4,226.0
 $977.4
 $302.9
 $5,506.3
 $—
 $65.4
 $3.9
 $—
 $5,575.6
Intersegment revenues 0.3
 —
 —
 0.3
 —
 317.1
 —
 (317.4) —
 —
 —
 —
 —
 —
 305.1
 —
 (305.1) —
Other operation and maintenance 1,477.3
 340.0
 80.6
 1,897.9
 —
 3.5
 (13.0) (317.4) 1,571.0
 1,156.8
 337.0
 73.0
 1,566.8
 —
 14.5
 2.1
 —
 1,583.4
Depreciation and amortization 370.1
 99.4
 15.5
 485.0
 —
 51.1
 33.4
 —
 569.5
 459.5
 135.2
 20.0
 614.7
 —
 68.8
 18.4
 (11.8) 690.1
Operating income (loss) 841.3
 171.3
 33.1
 1,045.7
 —
 281.1
 (6.4) —
 1,320.4
 922.8
 205.3
 43.9
 1,172.0
 —
 274.3
 (17.0) (261.0) 1,168.3
Equity in earnings of transmission affiliate —
 —
 —
 —
 107.7
 —
 —
 —
 107.7
Equity in earnings of transmission affiliates —
 —
 —
 —
 111.7
 —
 —
 —
 111.7
Interest expense 133.5
 28.8
 6.5
 168.8
 —
 46.8
 91.2
 (6.7) 300.1
 429.0
 43.4
 6.5
 478.9
 8.3
 46.7
 107.5
 (267.1) 374.3


  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
Nine Months Ended  
  
    
      
  
  
September 30, 2018                  
External revenues $4,303.3
 $973.2
 $292.5
 $5,569.0
 $—
 $26.8
 $6.9
 $—
 $5,602.7
Intersegment revenues —
 —
 —
 —
 —
 323.5
 —
 (323.5) —
Other operation and maintenance 1,495.9
 320.8
 74.5
 1,891.2
 —
 9.2
 (2.5) (295.2) 1,602.7
Depreciation and amortization 406.9
 125.7
 17.5
 550.1
 —
 55.7
 22.3
 —
 628.1
Operating income (loss) 670.2
 204.8
 38.9
 913.9
 —
 277.0
 (12.3) —
 1,178.6
Equity in earnings of transmission affiliates —
 —
 —
 —
 95.2
 —
 —
 —
 95.2
Interest expense 147.5
 37.4
 6.3
 191.2
 —
 48.0
 91.2
 (3.2) 327.2


NOTE 16—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.


AmericanInvestment in Transmission CompanyAffiliates


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. See Note 14, Investment in American Transmission Company, for more information.

The significant assetsAt September 30, 2019 and liabilities related to ATC recorded on our balance sheets includeDecember 31, 2018, our equity investment distributions receivable, and accounts payable. At September 30, 2017 and December 31, 2016, our equity investmentin ATC was $1,560.8$1,679.8 million and $1,443.9$1,625.3 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had a receivable

09/30/2019 Form 10-Q32WEC Energy Group, Inc.
Table of $35.2 million recorded at December 31, 2016 for distributions from ATC. Contents


We also had $29.1 million and $28.7 millionown approximately 75% of accounts payable dueATC 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 atHoldco is a variable interest entity but 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. Therefore, we account for ATC Holdco as an equity method investment. At September 30, 20172019 and December 31, 2016,2018, our equity investment in ATC Holdco was $40.6 million and $40.0 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

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


Purchased Power Purchase Agreement


We have a purchased power purchase agreement that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capitalfinance lease. The agreement includes no0 minimum energy requirements over the remaining term of approximately fivethree 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 no0 residual guarantee associated with the purchased power purchase agreement.


We have approximately $74.9$24.4 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

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the nine months ended September 30, 2017 and 2016 were $13.5 million and $40.5 million, respectively. Ourour maximum exposure to loss is limited to thethese capacity payments under the contract.payments.


NOTE 17—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 September 30, 2017,2019, including those of our subsidiaries, were $11,863.2 million.approximately $12 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 SO2, NOx,sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.


Air Quality

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing the CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015 and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and will finalize its designation by the end of 2017. We believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation.

8-Hour Ozone National Ambient Air Quality Standards

Sheboygan County and the eastern portion of Kenosha County are currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plans for both Sheboygan and Kenosha County and submitted them to the EPA for approval. The plans concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. We expect the EPA to issue a decision later in 2017.



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Air Quality

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 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS.National Ambient Air Quality Standards. The EPA is currently scheduled to finalizeissued final nonattainment area designations later in 2017. For nonattainment areas, theon 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 have to develop ais currently developing the state implementation plan to bringas required by the areas back into attainment.rule. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

Although we are still in the process of reviewing and determining potential impacts resulting from this rule, 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 0 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, the EPA issued a finalThe ACE rule regulating GHG emissions frombecame effective in September 2019. This rule provides existing coal-fired generating units referred to aswith standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, (CPP), aand (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. The WDNR is working with state utilities and has begun the process of developing the implementation plan.

In December 2018, the EPA proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standardsrevise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. The EPA announceddetermined that it has initiated this review. Asthe BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage.

In April 2019, we issued a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for theclimate report, which analyzes our GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state planswith respect to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a notice of proposed rulemakinginternational efforts to repeal the CPP. The EPA is expected subsequentlylimit future global temperature increases to issue an advanced notice of proposed rulemaking thatless than 2 degrees Celsius. We will solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunitiesupdate this analysis as climate-change policies and actions that preserverelevant technologies evolve over time with a focus on preserving fuel diversity, lowerlowering costs for our customers, and contribute towardsreducing long-term GHG reductions. emissions.

Our plan is to work with our industry partners,peers, environmental groups, public policy makers, and the State of Wisconsin,customers, with a goalgoals of reducing CO2 emissions by approximately 40% and 80% below 2005 levels by 2030. We have implemented2030 and continue to evaluate numerous options in order to meet2050, respectively. As a result of our CO2 reduction goal, such as increased usegeneration reshaping plan, we retired approximately 1,800 MW of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation orcoal generation since the beginning of 2018. This plan included the March 31, 2019 retirement of existing coal-fired units, additionthe PIPP as well as the 2018 retirements of new renewable energy resources (wind, solar),the Pleasant Prairie power plant, the Pulliam power plant, and considerationthe jointly-owned Edgewater Unit 4 generating units. See Note 6, Property, Plant, and Equipment, for more information on the retirement of supply and demand-side energy efficiency and distributed generation.the PIPP.


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Water Quality


Clean Water Act Cooling Water Intake Structure Rule


In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act 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 and Weston Unit 2, satisfy the IM BTA requirements.
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We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNRhave received BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR 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 VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 andOC 5 through OC 8, Weston Units 2, through3, and 4, and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. 

During 2017 and 2018, we will continue to complete studies and evaluate options to addresssatisfies the EM BTA requirements, at these plants. Withfinal determinations will not be made until the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towersdischarge permit is renewed for this facility. Until that meet EM BTA requirements),time, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. for this facility.

We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. We provided information to the MDEQWDNR and the EGLE (previously Michigan Department of Environmental Quality) about generating unit retirements. Based onFollowing discussions with the MDEQ, ifEGLE, in January 2019, we submitsubmitted a signed certification stating that the PIPP willwould be retired no later than the end of the next permit cycle (assumedJune 1, 2019. The PIPP was retired on March 31, 2019 and was not required to be October 1, 2022),in compliance with the EMnew BTA requirements will be waived. We expectrequirements.

As a result of past capital investments completed to submit this certification in November 2017. We expect to submit entrainment studies being conductedaddress Section 316(b) compliance at Pulliam Units 7WE and 8 to the WDNR by June 2018.

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


Steam Electric Effluent Limitation Guidelines


The EPA's final steam electric effluent limitation guidelines (ELG)2015 ELG rule took effect in January 2016. In April 2017, the EPA issued an administrative stayThis rule created new requirements for several types of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rulepower plant wastewaters. The two new requirements that affect WE and WPS relate to postpone the earliest compliance datesdischarge limits for the bottom ash transport waterBATW and wet flue gas desulfurization wastewater requirements. This rule appliesFGD wastewater. As a result of past capital investments at WE and WPS, we believe our fleet is well positioned to wastewater discharges from our power plant processes in Wisconsin and Michigan. Whilemeet the existing ELG compliance deadlines are postponed, 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, asThere will, however, need to be modifications to the BATW systems at Weston Unit 3 and OC 7 and OC 8. Also, one wastewater treatment system modification may be required for the wet FGD discharges from the 6 units that make up the OCPP and ERGS. Based on preliminary engineering, we estimate that compliance with the current rule will cost $70 million.

The ELG requirements for BATW and wet FGD systems are currently constructed,being reevaluated by the EPA. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements while it reconsiders the ELG rule. The Postponement Rule left unchanged the latest ELG rule will require additional wastewatercompliance date of December 31, 2023. On November 4, 2019, the EPA Administrator signed the proposed ELG Reconsideration Rule to revise the treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase in new or more stringenttechnology requirements related to limits of arsenic, mercury, selenium,BATW and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie

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FGD wastewaters at existing facilities. The ruleEPA 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 byproposed a provision that exempts facility owners from the new rule,BATW and modifications would be required at OC 7, OC 8, the Pleasant Prairie units, Pulliam Units 7 and 8, and Weston Unit 3.wet FGD requirements if a generating unit is retired by December 31, 2028. We are beginning preliminary engineering for compliance withexpect the rule and estimate a total cost range of $80 million to $110 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPPfinalized in late 2020. In the meantime, we are currently evaluating what impact, if we were not expecting to retireany, the plant. See the UMERC discussion in Note 19, Regulatory Environment, regarding the potential retirement of PIPP.proposed rule will have on our estimated compliance cost.


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.


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 tofor manufactured gas plant sites:
(in millions) September 30, 2019 December 31, 2018
Regulatory assets $719.6
 $687.1
Reserves for future environmental remediation 631.8
 616.4

(in millions) September 30, 2017 December 31, 2016
Regulatory assets $683.3
 $702.7
Reserves for future remediation 617.5
 633.4

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.


Consent Decrees


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


In November 2009, the EPA issued aan 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.

Also, WPS retired Pulliam Units 7 and 8 in May 2010,October 2018. WPS also completed the mitigation projects required and received a completeness letter from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by2018. We have started the Sierra Club as of September 30, 2017. It is unknown whetherprocess to terminate the Sierra Club will take further action in the future.WPS Consent Decree.


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Joint Ownership Power Plants Consent Decree – Columbia and Edgewater


In December 2009, the EPA issued aan NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and 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.

The As a result of the continued implementation of the Consent Decree containsrelated to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018.

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 requirement to, among other things, refuel, repower,material effect on our financial condition or retire Edgewater Unit 4,results of which WPS is a joint owner, by no later than December 31, 2018. Management of the joint owners has recommended that Edgewater Unit 4 be retired by December 2018. See Note 4, Property, Plant, and Equipment, for more information about the retirement.operations.


NOTE 18—22—SUPPLEMENTAL CASH FLOW INFORMATION
  Nine Months Ended September 30
(in millions) 2017 2016
Cash (paid) for interest, net of amount capitalized $(258.2) $(260.7)
Cash received for income taxes, net 7.3
 11.7
Significant non-cash transactions    
Accounts payable related to construction costs 172.7
 113.1
Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust

 4.6
 (4.5)
Portion of Bostco real estate holdings sale financed with note receivable * 7.0
 —
Amortization of deferred revenue 18.7
 18.5
  Nine Months Ended September 30
(in millions) 2019 2018
Cash (paid) for interest, net of amount capitalized $(317.9) $(278.1)
Cash (paid) for income taxes, net (15.4) (55.9)
Significant non-cash investing and financing transactions:    
Accounts payable related to construction costs 162.7
 71.9
Non-cash capital contributions from noncontrolling interest 14.6
 —

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


At September 30, 2017,The statements of cash flows include our activity related to cash, cash equivalents, and December 31, 2016,restricted cash. Our restricted cash primarily consists of $20.4 million and $33.6 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount wasthe cash held in the Integrys rabbi trust, and represents a portion of the required funding that was triggered by the announcement ofwhich is used to fund participants' benefits under the Integrys acquisition. Withdrawals of restricted cash fromdeferred 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. Our restricted cash also includes the restricted cash we received when we acquired ownership interests in Bishop Hill III and Upstream during August 2018 and January 2019, respectively. This cash is restricted as it can only be used to pay for qualifying payments areany remaining costs associated with the construction of these wind generation facilities. See Note 2, Acquisitions, for more information on the acquisitions of Bishop Hill III and Upstream.


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The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at September 30 to the total of these amounts shown as an investing activity on the statements of cash flows. Changes in restricted cash due to the sale or purchase of investments held in the rabbi trust are non-cash transactions and are included in the table above.flows:

(in millions) 2019 2018
Cash and cash equivalents $20.0
 $14.5
Restricted cash included in other long term assets 46.6
 25.7
Cash, cash equivalents, and restricted cash $66.6
 $40.2


NOTE 19—23—REGULATORY ENVIRONMENT


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


2020 and 2021 Rates

March 2019 Rate Application

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 applications reflected the following proposals:
  WE WG WPS
2020 Effective rate increase            
Electric (1) (2)
 $83 million/2.9% N/A $49 million/4.9%
Gas (3)
 $15 million/3.9% $11 million/1.8% $7 million/2.4%
Steam $1 million/4.5% N/A N/A
             
2021 Effective rate increase            
Electric (1)
 $83 million/2.9% N/A $49 million/4.9%
Gas N/A N/A $7 million/2.4%
             
ROE 10.35% 10.30% 10.35%
             
Common equity component average on a financial basis 52.0% 52.0% 52.0%

(1)
WE and WPS amounts are net of approximately $94 million and $16 million, respectively, of previously deferred unprotected tax benefits from the Tax Legislation in 2020, and $17 million and $24 million, respectively, in 2021.

(2)
WPS amount is net of approximately $21 million that would be refunded to customers related to its 2018 earnings sharing mechanism.

(3)
WPS amount is net of approximately $7 million of previously deferred unprotected tax benefits from the Tax Legislation.

All 3 Wisconsin utilities also proposed to continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism proposed was modified from its current structure to one that is consistent with other Wisconsin investor-owned utilities. Under the proposed earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers.

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 also requested 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 2 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 also requested 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.

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The proposed increases at our Wisconsin natural gas utilities were driven by continued investment in our natural gas distribution systems.

August 2019 Settlement Agreements

On August 30, 2019, WE, WG, and WPS filed an application with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case. The settlement agreements reflect the following:
  WE WG WPS
2020 Effective rate increase (decrease)            
Electric (1) (2)
 $37 million/1.3% N/A $35 million/3.5%
Gas (3)
 $10 million/2.8% $(1) million/(0.2)% $4 million/1.4%
Steam $2 million/10.0% N/A N/A
             
ROE 10.0% 10.2% 10.0%
             
Common equity component average on a financial basis 52.5% 52.5% 52.5%

(1)
These amounts are net of previously deferred unprotected tax benefits from the Tax Legislation. The WE and WPS settlement agreements reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over 2 years. For WE, approximately $65 million of tax benefits would be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits would be amortized in 2020 and $39 million would be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of the recently retired plants and the SSR regulatory asset would be used to reduce the related regulatory asset. The initial applications filed in March 2019 proposed that these tax benefits be refunded to customers over a period of 40 years with a significant portion being refunded in the first 2 years.

(2)
The WPS settlement agreement is net of $21 million of refunds related to its 2018 earnings sharing mechanism. WPS's settlement agreement reflects these refunds being returned to customers evenly over 2 years, with half being returned in 2020 and the remainder in 2021.

(3)
The WE amount includes previously deferred unprotected tax expense from the Tax Legislation, and the WPS and WG amounts are net of previously deferred unprotected tax benefits from the Tax Legislation. The settlement agreements for all 3 gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over 4 years. For WE, approximately $5 million of previously deferred tax expense would be amortized each year. For WG and WPS, approximately $3 million and $5 million, respectively, of previously deferred tax benefits would be amortized each year. The initial applications filed in March 2019 proposed that these tax impacts be refunded to or collected from customers over a period of 40 years, with a significant portion of the WPS benefit being refunded in the first 2 years.

The change in the rate increases between the initial applications filed in March 2019 and the settlement agreements was driven by various adjustments, including:

decreasing each utility’s proposed ROE (see table above);
increasing the common equity component in each utility’s capital structure (see table above);
extending amortizations as recommended in the PSCW Staff’s audit;
extending the period of recovery for the SSR escrow balance beyond what the PSCW Staff’s audit recommended; and
•
securitizing $100 million of Pleasant Prairie power plant’s book value.

Under the terms of the settlement agreement, WE would seek a financing order from the PSCW to securitize $100 million of Pleasant Prairie power plant's book value as of January 1, 2020, plus the carrying costs accrued on the $100 million during the securitization process and related fees. The securitization would reduce the carrying costs for the $100 million, benefiting customers.

The settlement agreements include the same earnings sharing mechanism for each utility that was proposed in the initial application filed in March 2019. The settlement agreements also require WE, WG, and WPS to maintain residential and small commercial electric and natural gas customer fixed charges at currently authorized rates through 2021 and to support maintaining WE's and WPS's electric market-based rates for large industrial customers in their current form.

At its meeting on October 31, 2019, the PSCW approved the settlement agreements without any known material modifications. The terms of these approvals are subject to our receipt and review of final written orders from the PSCW, which we expect to receive by

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the end of 2019. The PSCW is scheduled to address outstanding issues from the initial applications that were not included in the settlement agreements in a subsequent meeting. We expect the new rates to be 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 have filed requests for rehearing.


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. In addition, WE WG,is flowing through the tax benefit of its repair-related deferred tax liabilities in 2018 and WPS will defer2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While WE would typically follow the revenue requirement impactsnormalization accounting method and utilize the tax benefits of anythe deferred tax liabilities in rate-making as an offset to rate base, benefiting customers over time, the federal corporate tax reform enactedcode 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 2017 or during the base rate freeze period. Additionally, the0 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 currentlythat had been in place for WE and WG since January 2016, and all three3 utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing

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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 withrefunded to customers. All utility earnings above the first 50 basis points must also be shared withrefunded to customers.


Liquefied Natural Gas Storage Facilities in Michigan


In January 2017, we signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide approximately one-third of the current storage needs for the natural gas distribution service customers ofOn November 1, 2019, WE WG, and WPS. As a result of this agreement, WE, WG and WPS filed a requestjoint application with the PSCW in February 2017requesting approval for a declaratory ruling on various items associated with the storage facilities. In the filing, WE, WG, and WPS requested that the PSCW review and confirm the reasonableness and prudencyeach company to construct its own LNG facility. If approved, each facility would provide 1.0 billion cubic feet of their potential long-term storage service agreements and interstate natural gas transportation contracts relatedsupply to meet peak demand without requiring the storage facilities. WE, WG,construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WPS also requested approvalWG's natural gas system during the highest demand days of winter. The total cost of both projects is estimated to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and we acquired Bluewater on June 30, 2017. In September 2017, WE, WG, and WPS finalized the long-term service agreementsbe approximately $370 million, with approximately half being invested by each utility. Commercial operation for the natural gas storage andLNG facilities is targeted for the end of 2023.

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 a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Subject to PSCW 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.

In May 2018, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in 2 solar projects in Wisconsin. Badger Hollow I will be located in Iowa County, Wisconsin, and Two Creeks 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 agreements. We expect to receive approval2 projects in April 2019. Commercial operation for both projects is targeted for the end of the service agreements in the fourth quarter2020.


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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 commenced in January 2016 and 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. In March 2017, the ICCprogram, and issued an order directing that additional hearings be held before the ALJ on certain issues to further develop the evidentiary record in the case. This proceeding is expected to result in 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 ICCIllinois AG in 2017. We are currently unable to determine what, if any, long-term impact there will be onApril 2018. On June 28, 2019, the SMP.Illinois Appellate Court issued its ruling affirming the ICC’s final order. The appeal period has since expired for this ruling.


Qualifying Infrastructure Plant Rider


In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. The ActThis 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 2017,2019, PGL filed its 20162018 reconciliation with the ICC, which, along with the 2017 and 2016 reconciliations, are still pending. In July 2019, the ICC approved a settlement of the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ICC staffwhich includes a rate base reduction of $7.0 million and the Illinois Attorney General's office held an evidentiary hearing in September 2017, and we expecta $7.3 million refund to receive an order related to the 2014 reconciliation in 2017.ratepayers. As of September 30, 2017,2019, $7.1 million had been refunded to ratepayers.

As of September 30, 2019, there can be no0 assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.


Minnesota Energy Resources Corporation


2018 Minnesota Rate Case


In October 2017, MERC initiated a rate proceeding with the MPUC. In December 2018, the MPUC to increaseissued a final written order for MERC. The order authorized a retail natural gas rates $12.6rate increase of $3.1 million (5.05%(1.26%). MERC's request reflectsThe rates reflect a 10.3%9.7% ROE and a common equity component average of 50.9%. The proposed retail natural gas rate increase is primarily driven by increased capital investments as well as general inflation. MERC is also requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism.


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2016 Minnesota Rate Order

In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, effective Marchrates were implemented on July 1, 2017. The order authorized a retail natural gas rate increase of $6.8 million (3.0%). The rates reflect a 9.11% ROE and a common equity component average of 50.32%. The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another three years.2019. The final approved rate increase was lower than the interim rates collected from customers during 2016.2018 and through June 30, 2019. Therefore, weMERC refunded $4.1$8.0 million to MERC'sits customers during the secondthird quarter of 2017.2019.


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

In August 2016, we entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years. The agreement also calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in 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 construction of the proposed generation. The estimated cost of this project is $265.7 million ($277 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain a customer of WE until this new generation begins commercial operation.

2015 Michigan Rate Order

Prior to the formation of UMERC, in October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015,February 2018, the MPSC issued a final writtenan order for WPS, effective April 24, 2015, approving a settlement agreement. As a resultrequiring Michigan utilities to make 3 filings related to the Tax Legislation. The first of those filings, which was filed in March 2018, prospectively addressed the formation of UMERC, the terms and conditions of this WPS rate order now apply to UMERC, including the deferrals described below. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costsimpact on base rates for the 2013 acquisition ofchange in tax expense resulting from the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farmfederal tax rate reduction from 35% to 21%. UMERC and environmental upgrades at generation plants. The rates reflectedMGU proposed providing a 10.2% ROEvolumetric bill credit, subject to reconciliation and a common equity component average of 50.48%. The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, the Fox Energy Center costs deferral was discontinued and amortization of this deferral began, along with the amortization of the deferral associated with the termination of the Fox Energy Center tolling agreement.true up. In the order,May 2018, the MPSC also approvedissued 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 deferral and amortization of the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. UMERC will not seek an increase to retail electricimpact on base rates that would become effective priorfor the change in tax expense resulting from the federal tax rate reduction from 35% to January 1, 2018.

NOTE 20—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue21% from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

We intend to adopt this standard for interim and annual periods beginning January 1, 2018 as required,until July 1, 2018. UMERC and planMGU proposed to usereturn the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include atax


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reconciliation of results under the new revenue recognition guidance compared with what would have been reportedsavings from these months to customers via volumetric bill credits over multiple months. The MPSC issued orders approving settlements in 2018 under the old revenue recognition guidance in order to help facilitate comparabilitySeptember 2018. In accordance with the prior periods.settlement orders, the savings were returned to UMERC's and MGU's customers via volumetric bill credits that were in effect from October 1, 2018 through December 31, 2018.


We are finalizing our review of our contracts with customersThe third filing was filed in October 2018 and addressed the related financial disclosures to evaluate the impactremaining impacts of the amended guidanceTax Legislation on our existing revenue recognition policiesbase rates – most notably the re-measurement of deferred tax balances. UMERC and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component relatedMGU proposed providing a volumetric bill credit, subject to alternative revenue programs,reconciliation and true up, to be in the scopereturn these remaining impacts of the new standard. We have evaluated the nature of our operating revenuesTax Legislation to customers. The MPSC issued orders approving settlements in May 2019. The settlement orders provide for volumetric bill credits to UMERC’s and do not expect that thereMGU’s customers effective June 1, 2019. The bill credits will be a significant shiftremain in the timing or pattern of revenue recognition. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition.effect until each company's next rate proceeding.


Recognition and Measurement of Financial Instruments

NOTE 24—NEW ACCOUNTING PRONOUNCEMENTS
In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded, if applicable, with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Leases

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


Financial Instruments Credit Losses


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


Classification of Certain Cash Receipts and Cash PaymentsCloud Computing


In August 2016,2018, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts2018-15, 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 Cash Payments. Thiswhich costs to expense. The guidance isspecifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for fiscal years, andannual reporting periods, including interim periodsreporting within those fiscal years,periods, beginning after December 15, 2017,2019. Early adoption is permitted and willcan be applied using a retrospectiveeither retrospectively or prospectively. We are currently evaluating the transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believemethods and the impact the adoption of this guidance willstandard may have a significant impact on our financial statements.


Restricted CashDisclosure Requirements for Defined Benefit Plans


In November 2016,August 2018, the FASB issued ASU 2016-18, Restricted Cash. This2018-14, 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 isremoves 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 fiscal years, and interimannual reporting periods within those fiscal years, beginningending after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included2020, with cash and cash equivalents when reconcilingearly adoption permitted. We are currently evaluating the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. We do not believe the adoptioneffects of this guidance will have a significant impactpronouncement on our financial statements.Notes to Consolidated Financial Statements.


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

In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after


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December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. While we have not fully determined the impacts of the adoption of this standard, we expect that as a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components), will be recognized in our financial statements consistent with the current ratemaking treatment. As a result, we believe the impacts of adoption will be limited to changes in classification of non-service costs in the income statements.


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


CORPORATE DEVELOPMENTS


The following discussion should be read in conjunction with the accompanying financial statements and related notes and our 2018 Annual Report on Form 10-K for the year ended December 31, 2016.10-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 ATCAmerican 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 our We Power business and our recently acquired(which owns generation assets in Wisconsin), Bluewater (which owns underground natural gas storage facilities in Michigan. For more information onMichigan), a 90% ownership interest in Bishop Hill III (a wind generating facility in Illinois), an 80% ownership interest in Upstream (a wind generating facility in Nebraska), and an 80% ownership interest in Coyote Ridge (a wind generating facility under construction in South Dakota). Coyote Ridge is expected to be in service by the natural gas storage facilities, seeend of 2019.

In August 2019, WEC Energy Group signed an agreement to acquire an 80% ownership interest in Thunderhead Wind Energy LLC, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska. This wind generating facility is expected to be in service by the end of 2020, and will be included in the non-utility energy infrastructure segment. See Note 2, Acquisitions.Acquisitions, for more information.


Corporate Strategy


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


ReliabilityReshaping Our Generation Fleet


We have made significant reliability-related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliabilityThe planned reshaping of our generation fleet will balance reliability and distribution networks. Below arecustomer cost with environmental stewardship. Taken as a few examples of reliability projects that are currently underway.

UMERC, our Michigan electric and natural gas utility, is moving forward with its long-term generation solution for electric reliability in the Upper Peninsula of Michigan. Thewhole, this plan calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in the Upper Peninsula of Michigan. The new generation is expected to achieve commercial operation in 2019 and provide the region with affordable, reliable electricity that generates less emissions than PIPP. This should allow for the retirement of PIPP no later than 2020. For more information, see Note 19, Regulatory Environment.

PGL continues to work on its SMP, which primarily involves replacing old cast and ductile iron gas pipes and facilities in the city of Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.

WPS continues work on its SMRP, which involves 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. WE, WPS, and WG 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 received approval from the PSCW to make changes at ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.

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


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Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, attractive dividends, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment 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 a portion of a wind energy generation facility in Wisconsin.

See Note 3, Dispositions, for information on the sale of ITF, the MCPP, certain assets of Wisvest, and Bostco's real estate holdings.

Our primary investment opportunities are in our regulated utility business and our investment in ATC. From 2017 to 2021, we expect capital contributions to ATC and ATC Holdco, LLC to be approximately $350 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 $1.4 billion inside the traditional ATC footprint and $300 million outside of the traditional ATC footprint.

Excluding ATC, we expect total capital expenditures for our regulated utility business to be approximately $12 billion from 2017 to 2021. Ongoing projects are discussed in more detail within Liquidity and Capital Resources.

We have developed and are executing a strategy to reshape our generation portfolio in order to reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. Subject to final review, we plan on retiring2030 and by approximately 80% below 2005 levels by 2050. We have already retired more than 1,800 MWsMW of coal generation by 2020.since 2017, 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 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 4,6, Property, Plant, and Equipment, for information related to the planned retirementPIPP retirement.

As part of our PIPP and jointly-owned Edgewater 4commitment to invest in zero-carbon generation, units. In addition, we plan to retireinvest in up to 350 MW of utility scale solar within our Pulliam power plantWisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to acquire ownership interests in Green Bay, WI, subjecttwo 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. Construction began at the Two Creeks Solar Project and the Badger Hollow Solar Farm I in August 2019 and October 2019, respectively. 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 a proposed solar project, Badger Hollow Solar Farm II, that will be located in Iowa County, Wisconsin. Subject to PSCW approval, WE will own 100 MW of the completionoutput 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.

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

We also have a methane reduction goal of 30% by the year 2030 from a 2011 baseline. This goal represents a decrease in the rate of methane emissions from our natural gas distribution lines.

Reliability

We have made significant transmissionreliability-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 Midwest for the eighth year in a row. We Energies is the trade name under which WE and WG operate.

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, has completed its long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan called for UMERC to construct and operate approximately 180 MW of natural gas-fueled generation located in the Upper Peninsula. The new generation achieved commercial operation on March 31, 2019, and is providing the region with affordable, reliable electricity that generates less emissions than the PIPP.

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.

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 facilities to improve the reliability of electric service WPS provides to its customers. WPS, WE, 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 area.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 portions of wind energy generation facilities in Wisconsin, Illinois, Nebraska, and South Dakota.


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•
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 $13.7 billion from 2020 to 2024. Specific projects are also reviewing retirementsdiscussed in more detail below under Liquidity and Capital Resources.

From 2020 to 2024, we expect capital contributions to ATC to be approximately $150 million. Capital investments at ATC will be funded utilizing these capital contributions, in addition to cash generated from operations and debt. We currently forecast that our share of additional coal-fueled generation units.ATC's projected capital expenditures over the next five years will be $1.3 billion.


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, wherethrough 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 in order to improve customer satisfaction.


Safety


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




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RESULTS OF OPERATIONS


THREE MONTHS ENDED SEPTEMBER 30, 20172019


Consolidated Earnings


The following table compares our consolidated results for the third quarter of 20172019 with the third quarter of 2016,2018, including favorable or better, "B", and unfavorable or worse, "W", variances:
 Three Months Ended September 30 Three Months Ended September 30
(in millions, except per share data) 2017 2016 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 $279.7
 $299.1
 $(19.4) $290.8
 $201.4
 $89.4
 $7.4
 $87.6
 $(5.6)
Illinois 12.5
 11.7
 0.8
 24.8
 15.5
 9.3
 —
 —
 9.3
Other states (3.1) (1.0) (2.1) (2.2) (5.4) 3.2
 —
 —
 3.2
Non-utility energy infrastructure 103.4
 93.7
 9.7
 90.3
 91.6
 (1.3) —
 —
 (1.3)
Corporate and other 1.1
 (4.5) 5.6
 (6.0) (0.4) (5.6) —
 —
 (5.6)
Reconciling eliminations * (86.8) —
 (86.8) —
 (86.8) —
Total operating income 393.6
 399.0
 (5.4) 310.9
 302.7
 8.2
 7.4
 0.8
 —
Equity in earnings of transmission affiliate 39.2
 38.3
 0.9
Equity in earnings of transmission affiliates 38.7
 33.7
 5.0
 —
 —
 5.0
Other income, net 16.4
 7.5
 8.9
 21.8
 26.1
 (4.3) —
 —
 (4.3)
Interest expense 103.8
 99.1
 (4.7) 125.8
 112.0
 (13.8) —
 (0.8) (13.0)
Income before income taxes 345.4
 345.7
 (0.3) 245.6
 250.5
 (4.9) 7.4
 —
 (12.3)
Income tax expense 129.7
 128.4
 (1.3) 11.3
 17.0
 5.7
 (7.4) —
 13.1
Preferred stock dividends of subsidiary 0.3
 0.3
 —
 0.3
 0.3
 —
 —
 —
 —
Net loss attributed to noncontrolling interests 0.3
 —
 0.3
 —
 —
 0.3
Net income attributed to common shareholders $215.4
 $217.0
 $(1.6) $234.3
 $233.2
 $1.1
 $—
 $—
 $1.1
                  
Diluted earnings per share $0.68
 $0.68
 $—
 $0.74
 $0.74
 $—
      


*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 September 30, 2019, $86.8 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 leases do not impact our financial statements as all amounts associated with the leases are eliminated at the consolidated level.

Earnings decreased $1.6increased $1.1 million during the third quarter of 2017,2019, compared with the same quarter in 2016.2018. The mosttable above shows the income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the adoption of Topic 842, effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholders. See Note 23, Regulatory Environment, for more information on the flow through of tax repairs and Note 10, Leases, for more information on the adoption of Topic 842.

The significant factorfactors impacting the decrease$1.1 million increase in earnings was a $19.4 million pre-tax ($11.6 million after tax)were:

•
A $13.1 million remaining decrease in income tax expense, primarily driven by the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation, lower income before income taxes, and an increase in wind production tax credits related to acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment. The impact on our income tax expense from the 2018 PSCW order related to the Tax Legislation was offset in operating income at the Wisconsin segment. See Note 2, Acquisitions, for more information on the acquisitions in our non-utility energy infrastructure segment.


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•
A $9.3 million 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.

•
A $5.0 million increase in earnings from our ownership interests in transmission affiliates, primarily due to continued capital investment by ATC.

These increases in operating income at the Wisconsin segment. The decrease was primarily due to lower electric margins, driven by a decrease in sales volumes. Lower operating expenses partially offset the decrease in electric margins.

The decrease in operating income at the Wisconsin segment wasearnings were partially offset by:


•
A $13.0 million remaining increase in interest expense, driven by higher long-term debt balances, primarily used to fund capital investments.

•
A $5.6 million remaining decrease in operating income at the Wisconsin segment, driven by a decrease in electric margins related to lower retail sales volumes, due in part to unfavorable weather during the third quarter of 2019, compared with the same quarter in 2018. Also contributing to the decrease was the impact from the PSCW's 2018 order addressing the Tax Legislation, which was offset in income tax expense. These decreases in operating income were partially offset by lower operating expenses during the third quarter of 2019. The decrease in operating expenses was primarily driven by an accrual recorded in the third quarter of 2018 related to the earnings sharing mechanisms in place at our Wisconsin utilities. Lower maintenance and labor costs driven by the retirements of Pulliam Units 7 and 8 in October 2018 and the PIPP in March 2019 also contributed to the decrease in operating expenses.
A $9.7 million pre-tax ($5.8 million after tax) 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 $5.6 million increase in operating loss at the corporate and other segment, primarily driven by a gain recorded in the third quarter of 2018 that related to a business that was previously sold.

An $8.9 million pre-tax ($5.3 million after tax) increase in other income, net, due in part to an increase in gains on investments held in the rabbi trust and the quarter-over-quarter impact of expenses incurred in the third quarter of 2016 related to the disposition of certain non-utility real estate assets.


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.


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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 third quarter of 20172019 and 20162018 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
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Electric revenues $1,242.7
 $1,320.4
 $(77.7) $1,187.2
 $1,220.5
 $(33.3)
Fuel and purchased power 419.9
 442.5
 22.6
 385.9
 400.8
 14.9
Total electric margins 822.8
 877.9
 (55.1) 801.3
 819.7
 (18.4)
            
Natural gas revenues 158.6
 150.2
 8.4
 152.1
 168.2
 (16.1)
Cost of natural gas sold 71.4
 65.5
 (5.9) 67.5
 83.5
 16.0
Total natural gas margins 87.2
 84.7
 2.5
 84.6
 84.7
 (0.1)
            
Total electric and natural gas margins 910.0
 962.6
 (52.6) 885.9
 904.4
 (18.5)
            
Other operation and maintenance 458.3
 498.2
 39.9
 400.2
 525.0
 124.8
Depreciation and amortization 131.5
 124.5
 (7.0) 155.6
 137.2
 (18.4)
Property and revenue taxes 40.5
 40.8
 0.3
 39.3
 40.8
 1.5
Operating income $279.7
 $299.1
 $(19.4) $290.8
 $201.4
 $89.4


The following table shows a breakdown of other operation and maintenance:
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operation and maintenance not included in line items below $184.0
 $204.8
 $20.8
 $187.8
 $195.5
 $7.7
We Power (1)
 129.6
 129.6
 —
 36.9
 127.8
 90.9
Transmission (2)
 108.8
 107.0
 (1.8) 105.1
 106.5
 1.4
Regulatory amortizations and other pass through expenses (3)
 35.9
 38.2
 2.3
Earnings sharing mechanisms —
 18.6
 18.6
Transmission expense related to the flow through of tax repairs (3)
 16.5
 27.4
 10.9
Transmission expense related to Tax Legislation (4)
 17.5
 16.9
 (0.6)
Regulatory amortizations and other pass through expenses (5)
 36.4
 35.9
 (0.5)
Earnings sharing mechanisms (6)
 —
 15.0
 15.0
Total other operation and maintenance $458.3
 $498.2
 $39.9
 $400.2
 $525.0
 $124.8


(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 September 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 September 30, 2019, the $90.4 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 $86.8 million of depreciation and amortization and interest expense, respectively, in accordance with Topic 842. The We Power leases do not impact our financial statements as all amounts associated with the leases are eliminated at the consolidated level.

During the three months ended September 30, 20172019, $26.6 million of operating and 2016, $129.0maintenance 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 September 30, 2018, $124.8 million and $120.0 million, respectively, 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 differencesdifference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended September 30, 20172019 and 2016,2018, $128.9 million and $127.7$124.7 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 23, Regulatory Environment, for more information. The decrease in transmission expense associated with the flow through of tax benefits is offset in income taxes.

(4)
Represents 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.


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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.



09/30/2017 Form 10-Q
(6)
32WEC Energy Group, Inc.See Note 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 September 30 Three Months Ended September 30
 
MWh (in thousands)
 
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class        
Residential 2,960.4
 3,291.0
 (330.6) 3,140.1
 3,262.5
 (122.4)
Small commercial and industrial * 3,440.6
 3,604.8
 (164.2) 3,495.5
 3,617.5
 (122.0)
Large commercial and industrial * 3,364.6
 3,491.8
 (127.2) 3,312.4
 3,461.5
 (149.1)
Other 39.8
 36.4
 3.4
 36.0
 39.9
 (3.9)
Total retail * 9,805.4
 10,424.0
 (618.6) 9,984.0
 10,381.4
 (397.4)
Wholesale 977.8
 1,006.9
 (29.1) 872.2
 959.9
 (87.7)
Resale 2,484.8
 2,544.4
 (59.6) 1,107.5
 1,313.7
 (206.2)
Total sales in MWh * 13,268.0
 13,975.3
 (707.3) 11,963.7
 12,655.0
 (691.3)


*Includes distribution sales for customers who purchased power from an alternative electric supplier in Michigan.
 Three Months Ended September 30 Three Months Ended September 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class            
Residential 59.0
 54.3
 4.7
 57.7
 59.5
 (1.8)
Commercial and industrial 55.6
 54.6
 1.0
 54.6
 58.9
 (4.3)
Total retail 114.6
 108.9
 5.7
 112.3
 118.4
 (6.1)
Transport 275.7
 260.3
 15.4
 285.7
 291.6
 (5.9)
Total sales in therms 390.3
 369.2
 21.1
 398.0
 410.0
 (12.0)


  Three Months Ended September 30
  Degree Days
Weather 2017 2016 B(W)
WE and WG (1)
      
Heating (118 normal) 72
 27
 45
Cooling (543 normal) 542
 781
 (239)
       
WPS (2)
      
Heating (200 normal) 178
 79
 99
Cooling (363 normal) 315
 426
 (111)
       
UMERC (3)
      
Heating (328 normal) 306
 N/A
 N/A
Cooling (243 normal) 186
 N/A
 N/A
  Three Months Ended September 30
  Degree Days
Weather 2019 2018 B (W)
WE and WG (1)
      
Heating (114 Normal) 24
 75
 (68.0)%
Cooling (562 Normal) 649
 686
 (5.4)%
       
WPS (2)
      
Heating (197 Normal) 98
 147
 (33.3)%
Cooling (373 Normal) 424
 459
 (7.6)%
       
UMERC (3)
      
Heating (321 Normal) 261
 267
 (2.2)%
Cooling (252 Normal) 235
 340
 (30.9)%


(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 $55.1 million during the third quarter of 2017, compared with the same quarter in 2016. The significant factors impacting the lower electric utility margins were:

A $46.5 million decrease related to lower sales volumes during the third quarter of 2017, primarily driven by cooler summer weather. As measured by cooling degree days, the quarter ended September 30, 2017, was 30.6% and 26.1% cooler than the same quarter in 2016 in the Milwaukee and Green Bay areas, respectively.


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Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $18.4 million during the third quarter of 2019, compared with the same quarter in 2018. The significant factors impacting the lower electric utility margins were:

•
A $22.3 million decrease related to lower sales volumes, due in part to unfavorable weather during the third quarter of 2019, compared with the same quarter in 2018. As measured by cooling degree days, the third quarter of 2019 was 5.4% and 7.6% cooler than the same quarter in 2018 in the Milwaukee area and Green Bay area, respectively. As measured by heating degree days, the third quarter of 2019 was 68.0% and 33.3% warmer than the same quarter in 2018 in the Milwaukee area and Green Bay area, respectively.

A $20.2$1.7 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approveddecrease 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 variancerelated to savings from the costs includedTax Legislation that we are required to return to customers through bill credits or reductions in rates,other regulatory assets. This decrease in margins did not impact net income as it was offset by the net impact of a $5.5 million decrease in income taxes and a $3.8 million increase in depreciation and amortization expense. We received the remaining variance that exceeds the 2% variance is deferred.PSCW order in May 2018, which required WPS to use 40% of its 2018 and 2019 tax benefits to reduce certain regulatory assets.


These decreases in margins were partially offset by $9.2a $4.9 million increase related to the iron ore mines located in the Upper Peninsula of lower capacity paymentsMichigan. Prior to the transfer of the mines as a counterparty duringfull requirements customer of WE to UMERC as of April 1, 2019, the third quartermargin from the mines was being deferred for the benefit of 2017.Wisconsin retail electric customers, as ordered by the PSCW. On March 31, 2019, when the new generation solution in the Upper Peninsula began commercial operation, a new 20 year agreement with Tilden became effective under which Tilden began purchasing electric power from UMERC. Half of the cost of the generation solution is being recovered from Tilden under this new agreement.


Natural Gas Utility Margins


Natural gas utility margins at the Wisconsin segment increased $2.5decreased $0.1 million during the third quarter of 2017,2019, compared with the same quarter in 2016.2018. The most significant factor impacting the higherdecrease in natural gas utility margins was an increase inlower sales volumes, primarily driven by higher residential use per customer.a decrease in heating degree days during the third quarter of 2019, compared with the same quarter in 2018.


Operating Income


Operating income at the Wisconsin segment decreased $19.4increased $89.4 million during the third quarter of 2017,2019, compared with the same quarter in 2016.2018. This decreaseincrease was driven by the $52.6 million net decrease in margins discussed above, partially offset by $33.2$107.9 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenuesrevenue taxes)., partially offset by the $18.5 million decrease in margins discussed above.


The Wisconsin segment experienced lower overall operating expenses related to synergy savings resulting from the Integrys acquisition. The significant factors impacting the decrease in operating expenses which were due in part to synergy savings, were:

An $18.9 million decrease in operation and maintenance expenses at our plants, primarily related to lower costs at the PIPP and the timing of planned outages and maintenance.

An $18.6 million expense recorded induring the third quarter of 20162019, compared with the same quarter in 2018, were:

A $90.4 million decrease in other operation and maintenance expense 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 earnings sharing mechanismsWe Power leases. For the third 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 place at WE and WG. See Note 19, Regulatory Environment, for more information.
accordance with Topic 842.

A $5.8 million decrease in electric and natural gas distribution expenses.

These decreases in operating expenses were partially offset by:

A $7.3 million increase in benefit costs, primarily driven by higher stock-based compensation expense.


•
A $7.0$15.0 million increase expense recorded in depreciation and amortization, driven by the completion of the ReACTTM multi-pollutant control system at Weston Unit 3 during the fourththird quarter of 2016 and an overall increase2018 related to the earnings sharing mechanisms in utility plantplace at our Wisconsin utilities, with no corresponding expense in service.2019. See Note 23, Regulatory Environment, for more information.


A $10.9 million decrease in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes.
Illinois Segment Contribution to Operating Income

  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Natural gas revenues $187.2
 $181.8
 $5.4
Cost of natural gas sold 31.1
 25.3
 (5.8)
Total natural gas margins 156.1
 156.5
 (0.4)
       
Other operation and maintenance 100.8
 105.9
 5.1
Depreciation and amortization 38.9
 33.5
 (5.4)
Property and revenue taxes 3.9
 5.4
 1.5
Operating income $12.5
 $11.7
 $0.8
A $9.2 million decrease in other operation and maintenance expense, driven by the retirements of Pulliam Units 7 and 8 in October 2018 and the PIPP in March 2019. This resulted in lower maintenance and labor costs during the third quarter of 2019.




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A $6.3 million net decrease in benefit costs, which included $7.9 million of expense recorded in 2018 related to staff reductions.

These decreases in operating expenses were partially offset by:

•
An $18.4 million increase in depreciation and amortization, driven by capital expenditures related to assets that were placed into service 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 offset in electric margins above, and additional expense recognized related to the adoption of Topic 842, as discussed in the other operation and maintenance table above.

A $10.8 million increase in storm restoration expense during the third quarter of 2019.

Illinois Segment Contribution to Operating Income

Since the majority of PGL and NSG customers use natural gas for heating, operating income at the Illinois segment is sensitive to weather and is generally higher during the winter months.
  Three Months Ended September 30
(in millions) 2019 2018 B (W)
Natural gas revenues $198.0
 $197.9
 $0.1
Cost of natural gas sold 20.3
 29.8
 9.5
Total natural gas margins 177.7
 168.1
 9.6
       
Other operation and maintenance 101.8
 104.5
 2.7
Depreciation and amortization 45.7
 43.0
 (2.7)
Property and revenue taxes 5.4
 5.1
 (0.3)
Operating income $24.8
 $15.5
 $9.3

The following table shows a breakdown of other operation and maintenance:
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operation and maintenance not included in the line items below $88.9
 $90.7
 $1.8
 $89.9
 $93.7
 $3.8
Riders * 11.5
 14.5
 3.0
 12.3
 10.6
 (1.7)
Regulatory amortizations * —
 0.7
 0.7
 (0.4) (0.4) —
Other 0.4
 —
 (0.4) —
 0.6
 0.6
Total other operation and maintenance $100.8
 $105.9
 $5.1
 $101.8
 $104.5
 $2.7


*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 salesdelivered volumes by customer class and weather statistics:
 Three Months Ended September 30 Three Months Ended September 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class          
Residential 55.9
 52.9
 3.0
 42.4
 43.2
 (0.8)
Commercial and industrial 14.0
 15.1
 (1.1) 23.8
 22.9
 0.9
Total retail 69.9
 68.0
 1.9
 66.2
 66.1
 0.1
Transport 98.4
 104.0
 (5.6) 98.0
 103.0
 (5.0)
Total sales in therms 168.3
 172.0
 (3.7) 164.2
 169.1
 (4.9)



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 Three Months Ended September 30 Three Months Ended September 30
 Degree Days Degree Days
Weather * 2017 2016 B (W) 2019 2018 B (W)
Heating (81 Normal) 43
 23
 20
Heating (76 Normal) 13
 54
 (75.9)%


*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 $3.0$1.7 million impact of the riders referenced in the table above, increased $2.6$7.9 million during the third quarter of 2017,2019, compared with the same quarter in 2016. The increase was2018, primarily driven 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 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 increased $0.8$9.3 million during the third quarter of 2017,2019, compared with the same quarter in 2016.2018. This increase was due toprimarily driven by the $2.6$7.9 million net increase in margins discussed above, partially offset by a $1.8as well as $1.4 million increase inof lower 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.

The increasesignificant factor impacting the decrease in operating expenses during the third quarter of 2019, compared with the same quarter in 2018 was a $9.5 million decrease in natural gas maintenance costs.

This decrease in operating expenses was partially offset by:

A $6.1 million increase in benefit costs, primarily related to higher pension expense and deferred compensation.

A $2.7 million increase in depreciation expense, primarily driven by higher depreciation expense at PGL due toPGL's continued capital investment in the SMP project.



Other States Segment Contribution to Operating Income

Since the majority of MGU and MERC customers use natural gas for heating, operating income at the Other States segment is sensitive to weather and is generally higher during the winter months.
  Three Months Ended September 30
(in millions) 2019
2018 B (W)
Natural gas revenues $48.9
 $50.2
 $(1.3)
Cost of natural gas sold 18.0
 21.7
 3.7
Total natural gas margins 30.9
 28.5
 2.4
      

Other operation and maintenance 22.0
 23.0
 1.0
Depreciation and amortization 6.8
 6.4
 (0.4)
Property and revenue taxes 4.3
 4.5
 0.2
Operating loss $(2.2) $(5.4) $3.2


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Other States Segment Contribution to Operating Income
  Three Months Ended September 30
(in millions) 2017
2016 B (W)
Natural gas revenues $49.8
 $49.9
 $(0.1)
Cost of natural gas sold 21.3
 21.1
 (0.2)
Total natural gas margins 28.5
 28.8
 (0.3)
      

Other operation and maintenance 21.6
 21.2
 (0.4)
Depreciation and amortization 6.3
 5.2
 (1.1)
Property and revenue taxes 3.7
 3.4
 (0.3)
Operating loss $(3.1) $(1.0) $(2.1)

The following table shows a breakdown of other operation and maintenance:
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operation and maintenance not included in line item below $18.5
 $18.6
 $0.1
Operation and maintenance not included in line items below $18.4
 $19.6
 $1.2
Regulatory amortizations and other pass through expenses * 3.1
 2.6
 (0.5) 3.3
 3.4
 0.1
Other 0.3
 —
 (0.3)
Total other operation and maintenance $21.6
 $21.2
 $(0.4) $22.0
 $23.0
 $1.0


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


The following tables provide information on sales volumes by customer class and weather statistics:
 Three Months Ended September 30 Three Months Ended September 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class            
Residential 18.1
 14.7
 3.4
 15.7
 16.7
 (1.0)
Commercial and industrial 18.5
 10.1
 8.4
 13.1
 16.9
 (3.8)
Total retail 36.6
 24.8
 11.8
 28.8
 33.6
 (4.8)
Transport 147.6
 146.0
 1.6
 172.7
 159.6
 13.1
Total sales in therms 184.2
 170.8
 13.4
 201.5
 193.2
 8.3


 Three Months Ended September 30 Three Months Ended September 30
 Degree Days Degree Days
Weather * 2017 2016 B (W) 2019 2018 B (W)
Heating (173 Normal) 154
 83
 71
MERC      
Heating (220 Normal) 159
 207
 (23.2)%
      
MGU   

  
Heating (119 Normal) 26
 86
 (69.8)%


*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.


Operating LossNatural Gas Utility Margins


The operating loss at the other states segmentNatural gas utility margins increased $2.1$2.4 million during the third quarter of 2017,2019, compared to the same quarter last year. The increase was primarily driven by higher sales volumes resulting from customer growth and capital investment in natural gas utility infrastructure. MERC began recognizing revenue under its new GUIC rider in the second quarter of 2019. The GUIC rider allows MERC to recover previously approved GUIC that are incurred to replace or modify natural gas facilities to the extent the work is required by state, federal, or other government agencies and exceeds the costs included in base rates.

Operating Loss

The operating loss at the other states segment decreased $3.2 million during the third quarter of 2019, compared to the same quarter last year. This decrease was driven by the $2.4 million increase in margins discussed above, as well as a $0.8 million decrease in operating expenses (which include other operation and maintenance, depreciation and amortization, due to an increase in capital investment. See Note 19, Regulatory Environment, for more information regarding MERC’s pending rate case.and property and revenue taxes).


Non-Utility Energy Infrastructure Segment Contribution to Operating Income
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Operating income $103.4
 $93.7
 $9.7



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Non-Utility Energy Infrastructure Segment Contribution to Operating income at the non-utility energy infrastructure segment increased $9.7 million, or 10.4%, when compared to the third quarter of 2016. Bluewater, which was acquired on June 30, 2017, contributed $5.9 million to third quarter 2017 operating income. The remaining increase of $3.8 million was driven by higher revenues in connection with capital additions to the plants We Power owns and leases to WE. See Note 2, Acquisitions, for more informationon the acquisition of Bluewater and Note 15, Segment Information, for information on the change in segment name.Income

  Three Months Ended September 30
(in millions) 2019 2018 B (W)
Operating income $90.3
 $91.6
 $(1.3)

Corporate and Other Segment Contribution to Operating Income
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operating income (loss) $1.1
 $(4.5) $5.6
Operating loss $(6.0) $(0.4) $(5.6)


Operating incomeThe operating loss at the corporate and other segment increased $5.6 million when compared toduring the third quarter of 2016,2019, compared with the same quarter in 2018, primarily driven by costsa gain recorded in the third quarter of 2018 that related to the acquisition of Integrys incurred in 2016 and lower general corporate expenses in 2017.a business that was previously sold.


Electric Transmission Segment Operations
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Equity in earnings of transmission affiliate $39.2
 $38.3
 $0.9
Equity in earnings of transmission affiliates $38.7
 $33.7
 $5.0


Earnings from our ownership interests in transmission affiliates increased $5.0 million during the third quarter of 2019, compared with the same quarter in 2018, primarily due to continued capital investment by ATC.

Consolidated Other Income, Net
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
AFUDC – Equity $3.0
 $6.7
 $(3.7) $3.3
 $3.7
 $(0.4)
Non-service components of net periodic benefit costs 9.6
 7.3
 2.3
Other, net 13.4
 0.8
 12.6
 8.9
 15.1
 (6.2)
Other income, net $16.4
 $7.5
 $8.9
 $21.8
 $26.1
 $(4.3)


Other Income,income, net increased by $8.9decreased $4.3 million when compared to the third quarter of 2016. The increase was due in part to a $3.0 million increase in gains on investments held in our rabbi trust during the third quarter of 2017,2019, compared with the same periodquarter in 2016,2018, driven by a $6.4 million decrease in addition to expenses we incurredgains on the investments held in the third quarter of 2016Integrys rabbi trust. These investment gains partially offset benefits costs related to the disposition of certain non-utility real estate assets. These increases were partially offset by lower AFUDC largely due to the ReACTTM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016.deferred compensation, which are included in operating income. See Note 3, Dispositions,13, Fair Value Measurements, for more information on our asset sales.investments held in the Integrys rabbi trust. This decrease in other income, net was partially offset by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 16, Employee Benefits, for more information on our pension and OPEB costs.


Consolidated Interest Expense
 Three Months Ended September 30 Three Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Interest expense $103.8
 $99.1
 $(4.7) $125.8
 $112.0
 $(13.8)


Interest expense increased by $4.7$13.8 million as compared withduring the third quarter of 2016. The increase was2019, compared with the same quarter in 2018, primarily due to higher long-term debt levelsbalances. The increase in 2017debt balances is primarily related to fund continued capital investments and lower capitalized interest in 2017, primarily as a result of the completion of the ReACTTM emission control project in the fourth quarter of 2016.investments.


Consolidated Income Tax Expense
  Three Months Ended September 30
  2017 2016 B (W)
Effective tax rate 37.6% 37.1% (0.5)%
  Three Months Ended September 30
  2019 2018 B (W)
Effective tax rate 4.6% 6.8% 2.2%
 
Our effective tax rate increased by 0.5% when compared with the third quarter of 2016, primarily due to an increase in state income tax rates.



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Our effective tax rate decreased by 2.2% during the third quarter of 2019, compared with the same quarter in 2018. The decrease was primarily due to the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation and an increase in wind production tax credits related to acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment. The decreases in our effective tax rate were partially offset by decreased quarter-over-quarter benefits from the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement. The impacts from the 2018 PSCW order related to the Tax Legislation and the flow through of tax repairs were offset in operating income at the Wisconsin segment. See Note 2, Acquisitions, Note 12, Income Taxes, and Note 23, Regulatory Environment, for more information.

NINE MONTHS ENDED SEPTEMBER 30, 20172019


Consolidated Earnings


The following table compares our consolidated results for the nine months ended September 30, 20172019 with the nine months ended September 30, 2016,2018, including favorable or better, "B", and unfavorable or worse, "W", variances:
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions, except per share data) 2017 2016 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 $835.6
 $841.3
 $(5.7) $922.8
 $670.2
 $252.6
 $(9.3) $263.6
 $(1.7)
Illinois 209.3
 171.3
 38.0
 205.3
 204.8
 0.5
 —
 —
 0.5
Other states 35.0
 33.1
 1.9
 43.9
 38.9
 5.0
 —
 —
 5.0
Non-utility energy infrastructure 299.5
 281.1
 18.4
 274.3
 277.0
 (2.7) —
 —
 (2.7)
Corporate and other (6.3) (6.4) 0.1
 (17.0) (12.3) (4.7) —
 —
 (4.7)
Reconciling eliminations * (261.0) —
 (261.0) —
 (261.0) —
Total operating income 1,373.1
 1,320.4
 52.7
 1,168.3
 1,178.6
 (10.3) (9.3) 2.6
 (3.6)
Equity in earnings of transmission affiliate 122.9
 107.7
 15.2
Equity in earnings of transmission affiliates 111.7
 95.2
 16.5
 —
 —
 16.5
Other income, net 45.2
 72.6
 (27.4) 76.3
 65.0
 11.3
 —
 —
 11.3
Interest expense 310.4
 300.1
 (10.3) 374.3
 327.2
 (47.1) —
 (2.6) (44.5)
Income before income taxes 1,230.8
 1,200.6
 30.2
 982.0
 1,011.6
 (29.6) (9.3) —
 (20.3)
Income tax expense 458.8
 455.1
 (3.7) 91.5
 156.4
 64.9
 9.3
 —
 55.6
Preferred stock dividends of subsidiary 0.9
 0.9
 —
 0.9
 0.9
 —
 —
 —
 —
Net loss attributed to noncontrolling interests 0.5
 —
 0.5
 —
 —
 0.5
Net income attributed to common shareholders $771.1
 $744.6
 $26.5
 $890.1
 $854.3
 $35.8
 $—
 $—
 $35.8
     

     

      
Diluted Earnings Per Share
 $2.43
 $2.35
 $0.08
 $2.81
 $2.70
 $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 nine months ended September 30, 2019, $261.0 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 leases do not impact our financial statements as all amounts associated with the leases are eliminated at the consolidated level.

Earnings increased $26.5$35.8 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016. 2018. The table above shows the income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the adoption of Topic 842, effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholders.

The significant factors impacting the $35.8 million increase in earnings were:


•
A $55.6 million remaining decrease in income tax expense, primarily due to an increase in wind production tax credits related to acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment, the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation, and lower income before income taxes. The impact
A $38.0 million pre-tax ($22.8 million after tax) increase in operating income at the Illinois segment. The increase was driven by lower operating expenses and higher natural gas margins at PGL due to continued capital investment in the SMP project under its QIP rider.

An $18.4 million pre-tax ($11.0 million after tax) increase in operating income at the non-utility energy infrastructure segment. The increase was driven by higher revenues in connection with capital additions to the plants We Power owns and leases to WE and the inclusion of the operations of Bluewater following its acquisition on June 30, 2017.

A $15.2 million pre-tax ($9.1 million after tax) increase in earnings from our ownership interest in ATC. In 2016, ATC recognized lower earnings as a result of an ALJ recommendation related to the FERC ROE reviews. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.

A 0.6% decrease in our effective tax rate also favorably impacted earnings. The decrease in our effective tax rate was in part due to the recognition of excess tax benefits related to share-based payments and favorable compensation expense during the nine months ended September 30, 2017.

These increases in earnings were partially offset by:

A $27.4 million pre-tax ($16.4 million after tax) decrease in other income, net. The decrease was primarily driven by the period-over-period impact of the gains recognized in 2016 related to the repurchase of a portion of Integrys's 2006 Junior Notes and the sale of certain assets of Wisvest. See Note 3, Dispositions, for more information on the Wisvest sale.

A $10.3 million pre-tax ($6.2 million after tax) increase in interest expense, driven by higher long-term debt levels and lower capitalized interest during 2017.

A $5.7 million pre-tax ($3.4 million after tax) decrease in operating income at the Wisconsin segment. The decrease was primarily due to lower electric and natural gas margins, driven by a decrease in sales volumes. Lower operating expenses partially offset the decrease in margins.



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on our income tax expense from the 2018 PSCW order related to the Tax Legislation was offset in operating income at the Wisconsin segment. See Note 2, Acquisitions, for more information on the acquisitions in our non-utility energy infrastructure segment.

•
A $16.5 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.

•
An $11.3 million increase in other income, net, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 16, Employee Benefits, for more information on our pension and OPEB costs. Also contributing to the increase were higher earnings from our equity method investments and higher 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, which are included in operating income. See Note 13, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

These increases in earnings were partially offset by:

•
A $44.5 million remaining increase in interest expense. The increase in interest expense was driven by higher long-term debt balances, primarily used to fund capital investments

•
A $1.7 million remaining decrease in operating income at the Wisconsin segment, driven by a decrease in electric margins related to lower retail sales volumes, which were primarily a result of cooler summer weather during 2019 compared with 2018. Also contributing to the decrease was the impact from the PSCW's 2018 order addressing the Tax Legislation, which was offset in income tax expense. These decreases in operating income were partially offset by lower operating expenses during 2019. The decrease in operating expenses was primarily driven by 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, which resulted in lower maintenance and labor costs. An accrual recorded in the third quarter of 2018 related to the earnings sharing mechanisms in place at our Wisconsin utilities also contributed to the decrease in operating expenses.

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 nine months ended September 30, 20172019 and 20162018 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
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Electric revenues $3,448.7
 $3,534.8
 $(86.1) $3,278.2
 $3,377.1
 $(98.9)
Fuel and purchased power 1,115.4
 1,121.9
 6.5
 1,035.4
 1,081.3
 45.9
Total electric margins 2,333.3
 2,412.9
 (79.6) 2,242.8
 2,295.8
 (53.0)
 

 

 

 

 

 

Natural gas revenues 867.9
 820.4
 47.5
 947.8
 926.2
 21.6
Cost of natural gas sold 473.1
 422.4
 (50.7) 536.5
 528.1
 (8.4)
Total natural gas margins 394.8
 398.0
 (3.2) 411.3
 398.1
 13.2
     

     

Total electric and natural gas margins 2,728.1
 2,810.9
 (82.8) 2,654.1
 2,693.9
 (39.8)
            
Other operation and maintenance 1,379.9
 1,477.3
 97.4
 1,156.8
 1,495.9
 339.1
Depreciation and amortization 391.1
 370.1
 (21.0) 459.5
 406.9
 (52.6)
Property and revenue taxes 121.5
 122.2
 0.7
 115.0
 120.9
 5.9
Operating income $835.6
 $841.3
 $(5.7) $922.8
 $670.2
 $252.6


The following table shows a breakdown of other operation and maintenance:
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operation and maintenance not included in line items below $559.8
 $637.6
 $77.8
 $518.8
 $560.9
 $42.1
We Power (1)
 384.3
 385.5
 1.2
 107.0
 380.9
 273.9
Transmission (2)
 318.8
 318.6
 (0.2) 314.5
 315.7
 1.2
Regulatory amortizations and other pass through expenses (3)
 117.0
 117.0
 —
Earnings sharing mechanisms —
 18.6
 18.6
Transmission expense related to the flow through of tax repairs (3)
 48.3
 52.1
 3.8
Transmission expense related to Tax Legislation (4)
 50.2
 50.7
 0.5
Regulatory amortizations and other pass through expenses (5)
 118.0
 116.9
 (1.1)
Earnings sharing mechanism (6)
 —
 18.7
 18.7
Total other operation and maintenance $1,379.9
 $1,477.3
 $97.4
 $1,156.8
 $1,495.9
 $339.1


(1) 
Represents costs associated with the We Power generation units, including operating and maintenance costs incurredrecognized by WE, as well asWE. For the nine months ended September 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 nine months ended September 30, 20172019, $272.8 million of lease expense related to the We Power leases with WE was no longer classified within other operation and 2016, $394.0maintenance, but was instead recorded as $11.8 million and $383.5$261.0 million of depreciation and amortization and interest expense, respectively, of both lease and operating and maintenance costs were billed to or incurred by WE,in accordance with Topic 842. The We Power leases do not impact our financial statements as all amounts associated with the difference in costs billed or incurred and expenses recognized, either deferred or deducted fromleases are eliminated at the regulatory asset.consolidated level.

During the nine months ended September 30, 2019, $103.0 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 nine months ended September 30, 2018, $361.5 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.
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(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 differencesdifference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the nine months ended September 30, 20172019 and 2016, $330.42018, $367.0 million and $371.6$316.3 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 23, Regulatory Environment, for more information. The decrease in transmission expense associated with the flow through of tax benefits is offset in income taxes.

(4)
Represents 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.


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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 23, Regulatory Environment, for more information about our earnings sharing mechanisms.

The following tables provide information on sales volumes by customer class and weather statistics:
 Nine Months Ended September 30 Nine Months Ended September 30
 
MWh (in thousands)
 
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class            
Residential 8,013.9
 8,401.6
 (387.7) 8,287.6
 8,545.0
 (257.4)
Small commercial and industrial * 9,746.8
 9,974.0
 (227.2) 9,731.4
 10,032.8
 (301.4)
Large commercial and industrial * 9,669.4
 10,323.1
 (653.7) 9,554.3
 9,838.2
 (283.9)
Other 126.9
 124.0
 2.9
 120.2
 124.2
 (4.0)
Total retail * 27,557.0
 28,822.7
 (1,265.7) 27,693.5
 28,540.2
 (846.7)
Wholesale 2,854.4
 2,760.3
 94.1
 2,536.7
 2,692.7
 (156.0)
Resale 6,002.5
 6,638.9
 (636.4) 4,252.2
 4,550.4
 (298.2)
Total sales in MWh * 36,413.9
 38,221.9
 (1,808.0) 34,482.4
 35,783.3
 (1,300.9)


*Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
 Nine Months Ended September 30 Nine Months Ended September 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class            
Residential 668.5
 692.5
 (24.0) 804.9
 753.3
 51.6
Commercial and industrial 421.6
 426.3
 (4.7) 500.8
 497.6
 3.2
Total retail 1,090.1
 1,118.8
 (28.7) 1,305.7
 1,250.9
 54.8
Transport 952.0
 931.8
 20.2
 1,037.8
 1,026.8
 11.0
Total sales in therms 2,042.1
 2,050.6
 (8.5) 2,343.5
 2,277.7
 65.8


  Nine Months Ended September 30
  Degree Days
Weather 2017 2016 B(W)
WE and WG (1)
      
Heating (4,333 normal) 3,669
 4,058
 (389)
Cooling (704 normal) 745
 977
 (232)
       
WPS (2)
      
Heating (4,809 normal) 4,285
 4,481
 (196)
Cooling (494 normal) 440
 568
 (128)
       
UMERC (3)
      
Heating (5,465 normal) 5,109
 N/A
 N/A
Cooling (322 normal) 233
 N/A
 N/A
  Nine Months Ended September 30
  Degree Days
Weather 2019 2018 B (W)
WE and WG (1)
      
Heating (4,306 Normal) 4,480
 4,323
 3.6 %
Cooling (728 Normal) 725
 903
 (19.7)%
       
WPS (2)
      
Heating (4,794 Normal) 4,979
 4,864
 2.4 %
Cooling (509 Normal) 502
 674
 (25.5)%
       
UMERC (3)
      
Heating (5,452 Normal) 5,898
 5,509
 7.1 %
Cooling (331 Normal) 284
 478
 (40.6)%


(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 decreased $79.6$53.0 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016.2018. The significant factors impacting the lower electric utility margins were:


•
A $50.0 million decrease related to lower sales volumes, primarily driven by cooler summer weather during 2019 compared with 2018. As measured by cooling degree days, the nine months endedSeptember 30, 2019, were 19.7% and 25.5% cooler than the same period in 2018 in the Milwaukee area and Green Bay area, respectively.

•
A $13.1 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. This decrease in margins was offset in income taxes. See Note 23, Regulatory Environment, for more information.
A $71.2 million decrease related to lower sales volumes during the nine months ended September 30, 2017, primarily driven by unfavorable weather and lower overall retail use per customer. Cooler summer weather, warmer winter weather, and an additional day of sales during the same period in 2016 due to leap year contributed to the decrease. As measured by cooling degree days, the nine months ended September 30, 2017, were 23.7% and 22.5% cooler than the same period in 2016 in the Milwaukee and Green Bay areas, respectively. As measured by heating degree days, the nine months ended September 30, 2017, were 9.6% and 4.4% warmer than the same period in 2016 in the Milwaukee and Green Bay areas, respectively.


A $31.0 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, 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 $4.5$5.1 million decrease in steam margins drivenrelated to savings from the Tax Legislation that we are required to return to customers through bill credits or reductions in other regulatory assets. This decrease in margins did not impact net income as it was offset by the salenet impact of a $16.5 million decrease in income taxes and an $11.4 million increase in depreciation and amortization expense. We received the MCPPPSCW order in April 2016. See Note 3, Dispositions, for more information.
May 2018, which required WPS to use 40% of its 2018 and 2019 tax benefits to reduce certain regulatory assets.


These decreases in margins were partially offset by $27.2a $10.9 million increase related to the iron ore mines located in the Upper Peninsula of lower capacity paymentsMichigan. Prior to the transfer of the mines as a counterparty duringfull requirements customer of WE to UMERC as of April 1, 2019, the nine months ended September 30, 2017.margin from the mines was being deferred for the benefit of Wisconsin retail electric customers, as ordered by the PSCW. On March 31, 2019 when the new generation solution in the Upper Peninsula began commercial operation, a new 20 year agreement with Tilden became effective under which Tilden began purchasing electric power from UMERC. Half of the cost of the generation solution is being recovered from Tilden under this new agreement.


Natural Gas Utility Margins


Natural gas utility margins at the Wisconsin segment decreased $3.2increased $13.2 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016.2018. The most significant factor impacting the lowerhigher natural gas utility margins were lower retailwas higher sales volumes, primarily driven by warmerdue in part to colder winter weather. An additional day of sales during 2016 due to leap year also contributed to the decrease. The lower margins were partially offset byweather, customer growth, and higher overall retail use per customer.residential customer during the nine months ended September 30, 2019, compared with the same period in 2018.


Operating Income


Operating income at the Wisconsin segment decreased $5.7increased $252.6 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016.2018. This decreaseincrease was driven by $292.4 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $82.8$39.8 million net decrease in margins discussed above, partially offset by $77.1 million of lower operating expenses.above.


The Wisconsin segment experienced lower overall operating expenses related to synergy savings resulting from the Integrys acquisition. The significant factors impacting the decrease in operating expenses which were dueduring the nine months ended September 30, 2019, compared with the same period in part to synergy savings,2018, were:


•
A $272.8 million decrease in other operation and maintenance expense 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 nine months ended September 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 $51.9 million decrease in other operation and maintenance expense, driven by 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 nine months ended September 30, 2019.

A $39.9 million decrease in operation and maintenance expenses at our plants, primarily related to the seasonal operation of the Pleasant Prairie Power Plant, lower costs at the PIPP, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information on the sale of the MCPP.

A $20.9 million decrease in electric and natural gas distribution expenses.

An $18.6 million expense recorded in the third quarter of 2016 related to the earnings sharing mechanisms in place at WE and WG. See Note 19, Regulatory Environment, for more information.

A $10.1 million decrease in expenses related to an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this project from WBS to WPS during 2017. The portion of these lower expenses related to the transfer are offset through higher depreciation and amortization, discussed below.

A $6.5 million decrease in benefit costs.



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•
An $18.7 million expense recorded during the nine months ended September 30, 2018, related to the earnings sharing mechanisms in place at our Wisconsin utilities, with no corresponding expense in 2019. See Note 23, Regulatory Environment, for more information.

A $5.0 million decrease in other operation and maintenance expense primarily related to gains recorded on a land sale in 2019.

A $3.8 million decrease in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes.

These decreases in operating expenses were partially offset by:


•
A $21.052.6 million increase in depreciation and amortization, driven by capital expenditures related to assets that were placed into service as we continue to execute on our capital plan, an increase related to the completionreduction of certain regulatory assets as a result of the ReACTTM multi-pollutant control system at Weston Unit 3 duringPSCW's May 2018 order addressing the fourth quarterTax legislation and offset in electric margins above, and additional expense recognized related to the adoption of 2016,Topic 842, as discussed in the transfer of the information technology project to WPS during 2017,other operation and an overall increase in utility plant in service.maintenance table above.


A $10.9$16.3 million gain on the sale of the MCPP,net increase in benefit costs, primarily related to higher deferred compensation costs in 2019, which was soldwere partially offset by expenses recorded in April 2016. See Note 3, Dispositions, for more information on the sale of the MCPP.
2018 related to staff reductions.


A $13.3 million increase in storm restoration expense in 2019.

Illinois Segment Contribution to Operating Income

Since the majority of PGL and NSG customers use natural gas for heating, operating income at the Illinois segment is sensitive to weather and is generally higher during the winter months.
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Natural gas revenues $965.7
 $853.1
 $112.6
 $977.4
 $973.2
 $4.2
Cost of natural gas sold 302.9
 228.8
 (74.1) 282.9
 306.8
 23.9
Total natural gas margins 662.8
 624.3
 38.5
 694.5
 666.4
 28.1
            
Other operation and maintenance 326.6
 340.0
 13.4
 337.0
 320.8
 (16.2)
Depreciation and amortization 112.6
 99.4
 (13.2) 135.2
 125.7
 (9.5)
Property and revenue taxes 14.3
 13.6
 (0.7) 17.0
 15.1
 (1.9)
Operating income $209.3
 $171.3
 $38.0
 $205.3
 $204.8
 $0.5


The following table shows a breakdown of other operation and maintenance:
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operation and maintenance not included in the line items below $251.3
 $284.7
 $33.4
 $269.4
 $253.1
 $(16.3)
Riders * 73.2
 50.3
 (22.9) 68.4
 67.2
 (1.2)
Regulatory amortizations * 1.2
 2.0
 0.8
 (1.1) (1.1) —
Other 0.9
 3.0
 2.1
 0.3
 1.6
 1.3
Total other operation and maintenance $326.6
 $340.0
 $13.4
 $337.0
 $320.8
 $(16.2)


*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 delivered sales volumes by customer class and weather statistics:
 Nine Months Ended September 30 Nine Months Ended September 30
 Therms (in millions) Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class            
Residential 595.7
 623.1
 (27.4) 618.1
 610.2
 7.9
Commercial and industrial 127.2
 130.7
 (3.5) 256.1
 250.8
 5.3
Total retail 722.9
 753.8
 (30.9) 874.2
 861.0
 13.2
Transport 571.2
 606.6
 (35.4) 626.9
 628.7
 (1.8)
Total sales in therms 1,294.1
 1,360.4
 (66.3) 1,501.1
 1,489.7
 11.4


 Nine Months Ended September 30 Nine Months Ended September 30
 Degree Days Degree Days
Weather * 2017 2016 B (W) 2019 2018 B (W)
Heating (3,947 Normal) 3,306
 3,687
 (381)
Heating (3,954 Normal) 4,171
 4,003
 4.2%


*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 $22.9$1.2 million impact of the riders referenced in the table above, increased $15.6$26.9 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016. The increase was2018, primarily driven 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 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 increased $38.0$0.5 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016.2018. This increase was due todriven by the $15.6$26.9 million net increase in margins discussed above, andpartially offset by a $22.4$26.4 million decreaseincrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), net of the impact of the riders referenced in the table above.

The significant factors impacting the decreaseincrease in operating expenses during the nine months ended September 30, 2019, compared with the same period in 2018 were:


A $14.1$16.7 million decreaseincrease in benefit costs, primarily related to higher pension expense and deferred compensation.

A $9.5 million increase in depreciation expense, primarily driven by lower pension costs.

A $7.9 million decrease driven by the residual impact of the warmer weather this past winter leading to reduced need for repair and maintenance activity.

These decreases were partially offset by higher depreciation expense at PGL due toPGL's continued capital investment in the SMP project.


Other States Segment Contribution to Operating Income
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Natural gas revenues $273.4
 $262.3
 $11.1
 $302.9
 $292.5
 $10.4
Cost of natural gas sold 135.1
 123.1
 (12.0) 153.4
 149.1
 (4.3)
Total natural gas margins 138.3
 139.2
 (0.9) 149.5
 143.4
 6.1
     

     

Other operation and maintenance 73.2
 80.6
 7.4
 73.0
 74.5
 1.5
Depreciation and amortization 18.4
 15.5
 (2.9) 20.0
 17.5
 (2.5)
Property and revenue taxes 11.7
 10.0
 (1.7) 12.6
 12.5
 (0.1)
Operating income $35.0
 $33.1
 $1.9
 $43.9
 $38.9
 $5.0



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The following table shows a breakdown of other operation and maintenance:
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operation and maintenance not included in line item below $56.3
 $63.6
 $7.3
Operation and maintenance not included in line items below $56.1
 $55.9
 $(0.2)
Regulatory amortizations and other pass through expenses * 16.9
 17.0
 0.1
 16.6
 18.6
 2.0
Other 0.3
 —
 (0.3)
Total other operation and maintenance $73.2
 $80.6
 $7.4
 $73.0
 $74.5
 $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:
 Nine Months Ended September 30 Nine Months Ended September 30
 
Therms (in millions)
 
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W) 2019 2018 B (W)
Customer Class            
Residential 191.5
 198.4
 (6.9) 235.5
 234.1
 1.4
Commercial and industrial 130.1
 125.5
 4.6
 157.2
 152.0
 5.2
Total retail 321.6
 323.9
 (2.3) 392.7
 386.1
 6.6
Transport 506.6
 530.2
 (23.6) 576.2
 551.9
 24.3
Total sales in therms 828.2
 854.1
 (25.9) 968.9
 938.0
 30.9

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 Nine Months Ended September 30 Nine Months Ended September 30
 Degree Days Degree Days
Weather * 2017 2016 B (W) 2019 2018 B (W)
Heating (4,589 Normal) 4,064
 4,162
 (98)
MERC     

Heating (5,063 Normal) 5,615
 5,356
 4.8%
      
MGU      
Heating (4,093 Normal) 4,129
 4,079
 1.2%


*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 $6.1 million during the nine months ended September 30, 2019, compared with the same period in 2018. The increase was primarily driven by higher sales volumes as a result of colder weather and customer growth, as well as capital investment in natural gas utility infrastructure. MERC began recognizing revenue under its new GUIC rider in the second quarter of 2019.

Operating Income


Operating income at the other states segment increased $1.9$5.0 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016.2018. The increase was primarily driven by lowerthe $6.1 million increase in margins discussed above, partially offset by a $1.1 million increase in operating expenses (which include other operation and maintenance, expense due to effective cost control measures, partially offset by higher depreciation and amortization, and property and revenue taxes). The increase in operating expenses is primarily due to an increasethe positive impact on 2018 depreciation and amortization expense of a depreciation study approved by the MPUC in capital investment.the second quarter of 2018. These rates were effective retroactive to January 2017.



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Non-Utility Energy Infrastructure Segment Contribution to Operating Income
�� Nine Months Ended September 30
 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operating income $299.5
 $281.1
 $18.4
 $274.3
 $277.0
 $(2.7)


Operating income at the non-utility energy infrastructure segment increased $18.4decreased $2.7 million or 6.5%, when compared withduring the nine months ended September 30, 2016. Higher revenues2019, compared with the same period in connection with capital additions2018. This decrease was driven by operating losses at the Upstream and Bishop Hill III wind generation facilities. The majority of earnings from our ownership interests in wind generation facilities come in the form of wind production tax credits, and are recognized as an offset to the plants We Power owns and leases to WE drove $12.5 million of the increase. In addition, Bluewater, which was acquired on June 30, 2017, contributed $5.9 million to 2017 operating income. See Note 2, Acquisitions, forincome tax expense. For more information on the acquisition of BluewaterUpstream and Bishop Hill III, see Note 15, Segment Information, for information on the change in segment name.2, Acquisitions.


Corporate and Other Segment Contribution to Operating Income
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Operating loss $(6.3) $(6.4) $0.1
 $(17.0) $(12.3) $(4.7)


The operating loss at the corporate and other segment increased $4.7 million during the nine months ended September 30, 2019, compared with the same period in 2018, primarily driven by a gain recorded in the third quarter of 2018 that related to a business that was previously sold.

Electric Transmission Segment Operations
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
Equity in earnings of transmission affiliate $122.9
 $107.7
 $15.2
Equity in earnings of transmission affiliates $111.7
 $95.2
 $16.5


EquityEarnings from our ownership interests in earnings of transmission affiliateaffiliates increased $15.2$16.5 million or 14.1%, when compared with the nine months ended September 30, 2016. Lower earnings during the nine months ended September 30, 2016, were2019, compared with the same period in 2018, primarily due to continued capital investment by ATC. Also contributing to the increase 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 an ALJ recommendation related to the FERC ROE reviews. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.financial audit completed in February 2018.


Consolidated Other Income, Net
 Nine Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 B (W) 2019 2018 B (W)
AFUDC – Equity $8.3
 $20.7
 $(12.4) $10.6
 $10.7
 $(0.1)
Gain on repurchase of notes —
 23.6
 (23.6)
Gain on sale of certain assets of Wisvest —
 19.6
 (19.6)
Non-service components of net periodic benefit costs 27.5
 19.8
 7.7
Other, net 36.9
 8.7
 28.2
 38.2
 34.5
 3.7
Other income, net $45.2
 $72.6
 $(27.4) $76.3
 $65.0
 $11.3


Other income, net decreased by $27.4increased $11.3 million when compared withduring the nine months ended September 30, 2016.2019, compared with the same period in 2018. The decreaseincrease was primarily driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 16, Employee Benefits, for more information on our pension and OPEB costs. Also contributing to the increase were $3.0 million of higher earnings from our equity method investments and an increase of $2.7 million from higher gains on the investments held in the Integrys rabbi trust.

Consolidated Interest Expense
  Nine Months Ended September 30
(in millions) 2019 2018 B (W)
Interest expense $374.3
 $327.2
 $(47.1)

Interest expense increased $47.1 million during the nine months ended September 30, 2019, compared with the same period in 2018, primarily due to the $23.6 million gain on the repurchase of a portion of Integrys's 2006 Junior Notes at a discounthigher long-term debt balances. This increase in February 2016,debt balances is primarily related to continued capital investments.


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a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, and lower AFUDC largely due to the ReACTTM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016. Partially offsetting these decreases were higher gains on investments held in our rabbi trust during the nine months ended September 30, 2017, compared with the same period in 2016. See Note 3, Dispositions, for more information on our asset sales.

Consolidated Interest Expense
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Interest expense $310.4
 $300.1
 $(10.3)

Interest expense increased by $10.3 million, as compared with the nine months ended September 30, 2016. The increase was primarily due to higher debt levels in 2017 to fund continued capital investments and lower capitalized interest in the nine months ended September 30, 2017, primarily as a result of the completion of the ReACTTM emission control project in the fourth quarter of 2016.


Consolidated Income Tax Expense
  Nine Months Ended September 30
  2017 2016 B (W)
Effective tax rate 37.3% 37.9% 0.6%
  Nine Months Ended September 30
  2019 2018 B (W)
Effective tax rate 9.3% 15.5% 6.2%


Our effective tax rate decreased by 0.6% when compared with the nine months ended September 30, 2016, in part due to the recognition of excess tax benefits related to share-based payments and favorable compensation expense6.2% during the nine months ended September 30, 2017.2019, compared with the same period in 2018. The decrease was primarily due to an increase in wind production tax credits related to acquisitions of ownership interests in wind generation facilities in our non-utility energy infrastructure segment, the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation, and the increased benefit from the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement. The impacts from the 2018 PSCW order related to the Tax Legislation and the flow through of tax repairs were offset in operating income at the Wisconsin segment. See Note 5, Common Equity,2, Acquisitions, Note 12, Income Taxes, and Note 23, Regulatory Environment, for more information on the excess tax benefits related to share-based payments. information.

We expect our 20172019 annual effective tax rate to be between 37.0%10.5% and 38.0%11.5%, which includes an estimated 9.5% effective tax rate benefit due to the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement. Excluding the impact of the tax repairs, the expected 2019 effective tax rate would be between 20% and 21%.


LIQUIDITY AND CAPITAL RESOURCES


Cash Flows


The following table summarizes our cash flows during the nine months ended September 30:
(in millions) 2017 2016 Change in 2017 Over 2016 2019 2018 Change in 2019 Over 2018
Cash provided by (used in):            
Operating activities $1,746.7
 $1,721.9
 $24.8
 $1,840.7
 $2,008.2
 $(167.5)
Investing activities (1,552.0) (841.6) (710.4) (1,734.5) (1,720.0) (14.5)
Financing activities (214.1) (905.1) 691.0
 (185.7) (306.6) 120.9


Operating Activities


Net cash provided by operating activities increased $24.8decreased $167.5 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016,2018, driven by:


•
A $179.7 million decrease in cash from higher payments for other operation and maintenance expenses. During the nine months ended September 30, 2019, our payments were higher for accounts payable, transmission, benefits, and storm restoration, compared with the same period in 2018.
A $139.9 million increase in cash related to higher overall collections from customers, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 20.5% during the nine months ended September 30, 2017, compared with the same period in 2016.
•
A $56.2 million decrease in cash due to higher collateral requirements, driven by an increase in the fair value of our natural gas derivative liabilities during the nine months ended September 30, 2019, compared with the same period in 2018.


•
A $39.8 million decrease in cash due to an increase in payments for interest related to higher long-term debt balances during the nine months ended September 30, 2019, compared with the same period in 2018.
A $134.0 million increase in cash from lower payments for operating and maintenance costs. During the nine months ended September 30, 2017, our payments related to transmission, electric generation, electric and natural gas distribution, and employee benefits decreased.
•
A $25.1 million decrease in cash related to higher payments for environmental remediation from work completed on former manufactured gas plant sites during the nine months ended September 30, 2019, compared with the same period in 2018.


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


•
A $74.9 million increase in cash primarily related to lower payments for natural gas and for fuel and purchased power. Lower payments for natural gas were due to a 7.3% decrease in the average per-unit cost of natural gas sold during the nine months ended September 30, 2019, compared with the same period in 2018. Lower payments for fuel and purchased power were 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 $140.4 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, primarily due to higher commodity prices during the nine months ended September 30, 2017, compared with the same period in 2016.


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•
A $40.5 million net increase in cash related to a decrease in cash paid for income taxes during the nine months ended September 30, 2019, compared with the same period in 2018. This increase in cash was primarily due to the uncertainty around the ability to use tax attributes to offset the 2017 federal extension payment as a result of the Tax Legislation, which increased our 2017 extension payment made in 2018.
A $91.9 millionincrease in contributions and payments to our pension and OPEB plans during the nine months ended September 30, 2017, compared with the same period in 2016.


Investing Activities


Net cash used in investing activities increased $710.4$14.5 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016,2018, driven by:


•
The acquisition of an 80% ownership interest in Upstream in January 2019 for $268.2 million, which is net of cash and restricted cash acquired of $9.2 million. See Note 2, Acquisitions, for more information.

•
A $21.0 million increase in cash paid for capital expenditures during the nine months ended September 30, 2019, compared with the same period in 2018, which is discussed in more detail below.

A $309.1 millionThis increase in net cash paid for capital expenditures during the nine months ended September 30, 2017, compared with the same periodused in 2016, which is discussed in more detail below.
investing activities was partially offset by:


•
The acquisition of Bishop Hill III during August 2018 for $143.5 million, which is net of restricted cash acquired of $4.5 million. See Note 2, Acquisitions, for more information.

•
The acquisition of Forward Wind Energy Center in April 2018 for $77.1 million. See Note 2, Acquisitions, for more information.
The acquisition of Bluewater during June 2017 for $226.0 million. See Note 2, Acquisitions, for more information.
•
A $32.4 million increase in cash related to a reimbursement received from ATC for construction costs during the nine months ended September 30, 2019. See Note 18, Investment in Transmission Affiliates, for more information.

•
A $21.3 million increase in proceeds received from the sale of assets and businesses during the nine months ended September 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.

A $138.5 million decrease in the proceeds received from the sale of assets and businesses during the nine months ended September 30, 2017, compared with the same period in 2016. See Note 3, Dispositions, for more information.

A $36.2 million increase in our capital contributions to ATC during the nine months ended September 30, 2017, compared with the same period in 2016, due to the continued investment in equipment and facilities by ATC to improve reliability. The refunds and reserves resulting from the ATC ROE complaints filed with the FERC also contributed to the increase in our capital contributions. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information on these ATC ROE complaints.


Capital Expenditures


Capital expenditures by segment for the nine months ended September 30 were as follows:
Reportable Segment
(in millions)
 2017 2016 Change in 2017 Over 2016 2019 2018 Change in 2019 Over 2018
Wisconsin $764.0
 $644.5
 $119.5
 $968.2
 $983.4
 $(15.2)
Illinois 356.8
 204.3
 152.5
 423.6
 376.6
 47.0
Other states 52.9
 42.7
 10.2
 79.0
 75.3
 3.7
Non-utility energy infrastructure 19.1
 39.5
 (20.4) 30.2
 24.6
 5.6
Corporate and other 116.4
 69.1
 47.3
 10.5
 30.6
 (20.1)
Total capital expenditures $1,309.2
 $1,000.1
 $309.1
 $1,511.5
 $1,490.5
 $21.0


The increasedecrease in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2017,2019, compared with the same period in 2016,2018, was primarily driven by upgradesa project to construct a new natural gas-fired generation facility in the Upper Peninsula of Michigan, the implementation of an enterprise resource planning system, our electric and natural gas distribution systems, including meter and main replacement projects, WPS's SMRP,AMI program and various other software projects, projects at the OCPP.OCPP, and upgrades to WE's electric distribution system during the nine months ended September 30, 2018. These increasesdecreases in cash paid for capital expenditures were partially offset by reduced construction activity at WPS since the ReACTTM emission controlincreased capital expenditures related to WPS's acquisition of Two Creeks, upgrades to WPS's natural gas distribution system, and an information technology project at Weston Unit 3 was completed in 2016. In addition, WPS had lower expenditures forcreated to improve WE's and WG's billing, call center, and credit collection functions during the upgrades to the combustion turbine units at the Fox Energy Center, which were completed in June 2017.nine months ended September 30, 2019.


The increase in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2017,2019, compared with the same period in 2016,2018, was driven by increased construction activity related to PGL's SMP andan increase in facilities projects at PGL, partially offset by a project to relocate one of PGL's service facilities.

The decrease in cash paid for capitalAMI expenditures at the non-utility energy infrastructure segmentNSG during the nine months ended September 30, 2017, compared with the same period in 2016, was driven by reduced construction activity during 2017 for We Power's fuel flexibility project at the Oak Creek Expansion units.2019.



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The increasedecrease in cash paid for capital expenditures at the corporate and other segment during the nine months ended September 30, 2017,2019, compared with the same period in 2016,2018, was primarily driven by a project to implement a newthe implementation of an enterprise resource planning system.system during the nine months ended September 30, 2018.


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


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Financing Activities


Net cash used in financing activities decreased $691.0$120.9 million during the nine months ended September 30, 2017,2019, compared with the same period in 2016,2018, driven by:


•
A $720.0 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2019, compared with the same period in 2018.

•
A $588.4 million increase in cash related to lower long-term debt repayments during the nine months ended September 30, 2019, compared with the same period in 2018.

•
A $52.2 million increase in cash from stock options exercised during the nine months ended September 30, 2019, compared with the same period in 2018.

A $438.9 million net increaseThese increases in cash due to $133.3 million of net borrowings of commercial paper during the nine months ended September 30, 2017, compared with $305.6 million of net repayments of commercial paper during the same period in 2016.

A $226.6 million decrease in cash used for the repayment of long-term debt during the nine months ended September 30, 2017, compared with the same period in 2016. In February 2016, we repurchased a portion of Integrys's 2006 Junior Notes at a discount.

A $45.0 milliondecrease in cash used to purchase shares of our common stock during the nine months ended September 30, 2017, compared with the same period in 2016, to satisfy requirements of our stock-based compensation plans.

These decreases in net cash used in financing activities were partially offset by a $23.8 million increase in dividends paid on common stock during the nine months ended September 30, 2017, compared with the same period in 2016. In January 2017, our Board of Directors increased our quarterly dividend by $0.025 per share effective with the first quarter of 2017 dividend payment.by:


•
A $1,097.4 million net decrease in cash which resulted from $753.7 million of net repayments of commercial paper during the nine months ended September 30, 2019, compared with $343.7 million of net borrowings during the same period in 2018.

•
A $96.2 million decrease in cash due to an increase in the number and cost of shares of our common stock purchased during the nine months ended September 30, 2019, compared with the same period in 2018, to satisfy requirements of our stock-based compensation plans.

•
A $35.4 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 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 (6.8%) effective with the first quarter of 2019 dividend payment.

Significant Financing Activities


For more information on our financing activities, see Note 6,8, Short-Term Debt and Lines of Credit, and Note 7,9, Long-Term Debt.


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 facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 6,8, Short-Term Debt and Lines of Credit, for more information about these credit facilities.


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The following table shows our capitalization structure as of September 30, 2017,2019, 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 equity $9,195.3
 $9,445.3
Common shareholders' equity $10,051.0
 $10,301.0
Preferred stock of subsidiary 30.4
 30.4
 30.4
 30.4
Long-term debt (including current portion) 9,495.1
 9,245.1
 11,589.9
 11,339.9
Short-term debt 993.5
 993.5
 686.4
 686.4
Total capitalization $19,714.3
 $19,714.3
 $22,357.7
 $22,357.7
        
Total debt $10,488.6
 $10,238.6
 $12,276.3
 $12,026.3
        
Ratio of debt to total capitalization 53.2% 51.9% 54.9% 53.8%

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Included in long-term debt on our balance sheet as of September 30, 2017,2019, 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.

As of September 30, 2017, WE was the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, WE terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of September 30, 2017, the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by WE. Depending on market conditions and other factors, WE may change the method used to determine the interest rate on this bond series and have it remarketed to third parties.


Working Capital


As of September 30, 2017,2019, our current liabilities exceeded our current assets by $1,202.8$1,045.4 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, if necessary.


Credit Rating Risk


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


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

In July 2017, Moody's downgraded the ratings of WE (senior unsecured), WPS (senior unsecured), WG (senior unsecured), and Elm Road Generating Station Supercritical, LLC (senior secured) to A2 from A1. Moody's affirmed the commercial paper ratings of WE (P-1), WPS (P-1), and WG (P-1). Moody's also affirmed the ratings of WEC Energy Group (senior unsecured, A3), Wisconsin Energy Capital Corporation (senior unsecured, A3), and Integrys (senior unsecured, A3), but changed the rating outlook for these companies from stable to negative. We do not believe the change in ratings and rating outlook will have a material impact on our ability to access capital markets.


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


If we are unable to successfully take actions to manage any 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) 2017 2018 2019 2019 2020 2021
Wisconsin $1,111.2
 $1,392.8
 $1,126.3
 $1,418.0
 $1,482.0
 $1,881.1
Illinois 570.6
 619.7
 620.2
 710.6
 779.0
 619.4
Other states 88.3
 97.2
 114.2
 138.6
 117.4
 111.6
Non-utility energy infrastructure 279.3
 283.1
 60.8
 396.5
 390.5
 434.7
Corporate and other 157.7
 72.4
 49.6
 27.3
 24.6
 22.7
Total $2,207.1
 $2,465.2
 $1,971.1
 $2,691.0
 $2,793.5
 $3,069.5


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 $300$185 million between 20172019 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.


In connectionAs 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 solar projects in Wisconsin. Badger Hollow I will be located in Iowa County, Wisconsin, and Two Creeks will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the formationoutput of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $260 million. Construction began at Two Creeks and Badger Hollow I in August 2019 and October 2019, respectively. 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 a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Subject to PSCW approval, 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.

UMERC we entered intoconstructed approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. This new generation began commercial operation on March 31, 2019. The cost of this project is approximately $242 million ($255 million including AFUDC), 50% of which is expected to be recovered from Tilden pursuant to an agreement with Tilden Mining Company under which it will purchase electric power from UMERC for 20 years. The agreement calls for UMERCyears, with the remaining 50% expected to be recovered from UMERC's other utility customers.

WE and WG plan to each construct and operate approximately 180 MWtheir own LNG facility. Subject to PSCW approval, each facility will provide 1.0 billion cubic feet of natural gas-fired generation located ingas supply to meet peak demand without requiring the Upper Peninsulaconstruction of Michigan.additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas system during the highest demand days of winter. The estimatedtotal cost of this projectboth projects is $265estimated to be approximately $370 million, ($275 million including AFUDC).See Note 19, Regulatory Environment,with approximately half being invested by each utility. Commercial operation for more information about UMERC and this new generation.the LNG facilities is targeted for the end of 2023.


On June 30, 2017, we completed the acquisition of Bluewater for $226 million. Bluewater owns natural gas storage facilities in Michigan that will provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we incurred approximately $5 million of acquisition related costs. See Note 2, Acquisitions, for more information on this transaction.

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 20192021 is between $280 million and $300 million. See Note 19,23, Regulatory Environment, for more informationon the SMP.


The non-utility energy infrastructure line item in the table above includes our investments in Coyote Ridge and Upstream and our planned investment in Thunderhead. See Note 2, Acquisitions, for more information on these wind projects.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $226$90 million from 20172019 through 2019.2021. We do not expect to make any contributions to ATC Holdco during that period.


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Common Stock Dividends


Our current quarterly dividend rate is $0.52$0.59 per share, which equates to an annual dividend of $2.08$2.36 per share. For information related to our most recent common stock dividend declared, see Note 5,7, Common Equity.


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 6,8, Short-Term Debt and Lines of Credit, Note 11,15, Guarantees, and Note 16,20, Variable Interest Entities.



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Contractual Obligations


We and our subsidiaries issued additional long-term debt primarily in the third quarter 2019 which resulted in an increase in our contractual obligations. See Note 9, Long-Term Debt, for more information.

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 20162018 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the nine months ended September 30, 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 20162018 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 20162018 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.


Regulatory Recovery


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


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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, is currently estimated to bewas $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 19, Regulatory Environment, for more information. WPS will be required to obtain a separatecannot collect these deferred costs without prior approval from the PSCW. WPS has requested approval for collection of these deferred costs in a futurethe rate case.

Prior to its acquisition, Integrys initiated an information technology projectproposal it filed 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, call center, and credit collection functions. As of September 30, 2017, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.
PSCW in March 2019.


•
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, call center, and credit collection functions. As of September 30, 2019, 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. WPS has requested recovery of these costs in the rate proposal it filed with the 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 July 2019, the ICC approved a settlement of the 2015 reconciliation, which includes a rate base reduction of $7.0 million and a $7.3 million refund to ratepayers. As of September 30, 2019, $7.1 million had been refunded to ratepayers. As of September 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.
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 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ICC staff and the Illinois Attorney General's office held an evidentiary hearing in September 2017, and we expect to receive an order related to the 2014 reconciliation in 2017. As of September 30, 2017, 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 19,23, Regulatory Environment, for more information regarding recent andour pending rate proceedings, previously issued rate orders, and investigations involving our utilities.



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Environmental Matters


See Note 17,21, 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. During 2018 and 2019, the PSCW and the MPSC issued written orders regarding how to refund certain tax savings from the Tax Legislation to our ratepayers in Wisconsin and Michigan, respectively. We expect that the various remaining impacts of the Tax Legislation on 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, the MPUC included the various impacts of the Tax Legislation in MERC's final 2018 rate order.

In July 2019, the FERC approved WPS's revised formula rate tariff, which incorporated the impacts of the Tax Legislation. As a result of the FERC's approval, WPS's formula rate customers will receive a monthly bill credit through the end of 2019, which includes the tax savings from the Tax Legislation as well as interest. We are also working with the FERC to modify WE's formula rate tariff for the impacts of the Tax Legislation, and we expect to receive FERC approval for WE's modified tariff in 2020. See Note 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 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 ROEs ROE

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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 13,12, 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.


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.

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.


The decrease in ATC'sIn 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 resultinginquiries to solicit comments from all potential stakeholders, including those outside of MISO. If the FERC's final order issuedproposed 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 20162016. 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 continue to have a negative impact on our equity earnings and distributions from ATC.be issued.


Critical Accounting Policies and Estimates


We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require additional disclosures. We have found that the disclosures made in our 20162018 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:


Goodwill Impairment


We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2017.2019. No impairments were recorded as a result of these tests. For our Bluewater

Our reporting unit, we assumed fair value equaled carrying value since Bluewater was acquired on June 30, 2017. units had the following goodwill balances at July 1, 2019:
(in millions, except percentages) Goodwill Percentage of Total Goodwill
Wisconsin $2,104.3
 68.9%
Illinois 758.7
 24.9%
Other states 183.2
 6.0%
Bluewater 6.6
 0.2%
Total goodwill $3,052.8
 100.0%

For all of our other reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for thesethe reporting units were calculated using a combination of the income approach and the market approach.


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


Key assumptions used in the income approach include ROEs, the long-term growth rates used to determine terminal values at the end of the discrete forecast period, and the discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the

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after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The

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terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.


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


The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.


For all of our reporting units, other than Bluewater,the fair value exceeded its carrying value by over 50%. For Bluewater, we assumed fair value equaled carrying value since we acquired Bluewater on June 30, 2017. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

Our reporting units had the following goodwill balances at July 1, 2017:
(in millions, except percentages) Goodwill Percentage of Total Goodwill
Wisconsin $2,104.3
 68.9%
Illinois 758.7
 24.9%
Other states 183.2
 6.0%
Bluewater 7.3
 0.2%
Total goodwill $3,053.5
 100.0%


See Note 13,17, Goodwill, for more information.




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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


There have been no material changes related to market risk from the disclosures presented in our 2018 Annual Report on Form 10-K for the year ended December 31, 2016.10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 9,13, Fair Value Measurements, Note 10,14, Derivative Instruments, and Note 11,15, Guarantees, in this report for information concerning our market risk exposures.


ITEM 4. CONTROLS AND PROCEDURES


Disclosure Controls and Procedures


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


Changes in Internal Control Over Financial Reporting


There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the third quarter of 20172019 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 20162018 Annual Report on Form 10-K. See Note 17,21, Commitments and Contingencies, and Note 19,23, 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 referenced abovediscussed in Note 21, Commitments and discussedContingencies, Note 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 RiverManlove Field Matter


We were contactedIn September 2017, the Illinois Department of Natural Resources, Office of Oil and Gas Resource Management, issued a VN to PGL related to a leak of natural gas from a well located at the PGL Manlove Gas Storage Field in December 2016. PGL quickly shut down and permanently plugged the well to contain the leak after it was discovered. The leak resulted in the migration of natural gas from the well to the Mahomet Aquifer located in central Illinois and impacted residential freshwater wells. PGL has been working with residents potentially impacted by the United States Department of Justice in March 2016 to commence discussions between WPSnatural gas leak, and the federalIllinois state agencies to investigate and remediate the impacts of the natural resource trustees to resolve WPS's alleged liability for natural resources damages (NRD) in the Sheboygan River relatedgas leak to the former Camp Marina manufactured gas plant site. WPS was originally notified about this claimMahomet Aquifer. In October 2017, the Illinois 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 Agreed Interim Order with the State of Illinois in October 2017 and a First Amended Agreed Interim Order in September 2012, but2019 whereby PGL agreed, among other things, to continue actions it was already undertaking proactively, including the WDNR chose not to besubmittal of a partyGroundwater Management Zone application, which PGL submitted to the NRD claim negotiationIEPA in February 2014. However,August 2019.

In addition, in December 2017, the National OceanicIEPA issued a VN to PGL alleging the same violations as the AG. Lastly, in January 2018, the IEPA issued a VN alleging certain violations of Illinois air emission rules arising from the construction and Atmospheric Administration has co-equal trusteeshipoperation 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 WDNR over thepotentially impacted Sheboygan River natural resources and is now pursuing the NRD claim. Substantial remediation of the uplands at the legacy Sheboygan Camp Marina manufactured gas plant site has already occurred. We agreed to settlehomeowners would be taken into account. At this matter, subject to the approval of the United States District Court for the Eastern District of Wisconsin. The terms of the settlement,time, we believe that civil penalties, if approved,any, will not have a material impact on our financial statements.


ITEM 1A. RISK FACTORS


There were no material changes from the risk factors presented in our 2018 Annual Report on Form 10-K for the year ended December 31, 2016.10-K. See Item 1A. Risk Factors in Part I of our 2016 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.


ITEM 5. OTHER INFORMATION

On October 12, 2017, we reported that Allen L. Leverett, Chief Executive Officer of WEC Energy Group, had been hospitalized and was receiving medical treatment for a stroke. Mr. Leverett has since been released from the hospital and is making progress in his recovery and rehabilitation work. Gale E. Klappa continues to serve as Chairman of the Board and Interim Chief Executive Officer of the Company, and has executed the certifications attached as exhibits to this Form 10-Q in such capacity.



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ITEM 6. EXHIBITS
Number Exhibit
104 Material Contracts
Instruments defining the rights of security holders, including indentures
  
10.14.1
Letter Agreement by and between WEC Energy Group, Inc. and Margaret C. Kelsey,
Thirteenth Supplemental Indenture, dated as of July 19, 2017.August 14, 2019, between WPS and U.S. Bank National Association (Exhibit 4.1 to WPS's Form 8-K filed August 14, 2019).
   
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:November 3, 20177, 2019William J. Guc
  Vice President and Controller
   
  (Duly Authorized Officer and Chief Accounting Officer)




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