wec-20200930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2020


☐			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.

001-09057

WEC ENERGY GROUP, INC.

39-1391525

(A Wisconsin Corporation)

231 West Michigan Street

P.O. Box 1331

Milwaukee, WI 53201

(414) 221-2345

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

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

Common Stock, $.01 Par Value

WEC

New 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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

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 ☒

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (September 30, 2020):

Common Stock, $.01 Par Value, 315,434,531 shares outstanding

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2020

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Income Statements

Condensed Consolidated Statements of Comprehensive Income

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Equity

Notes to Condensed Consolidated Financial Statements

Page

Regulatory Assets and Liabilities

Note 7

Property, Plant, and Equipment

Note 8

Common Equity

Note 9

Short-Term Debt and Lines of Credit

Materials, Supplies, and Inventories

Note 13

Income Taxes

Note 14

Fair Value Measurements

Note 15

Derivative Instruments

Investment in Transmission Affiliates

Note 20

Segment Information

Note 21

Variable Interest Entities

Note 22

Commitments and Contingencies

Note 23

Supplemental Cash Flow Information

Note 24

Regulatory Environment

Note 25

New Accounting Pronouncements

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.

CONTROLS AND PROCEDURES


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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:


Subsidiaries and Affiliates
ATC						American Transmission Company LLC
ATC Holdco						ATC Holdco LLC

Bishop Hill III						Bishop Hill Energy III LLC
Bluewater						Bluewater Natural Gas Holding, LLC
Coyote Ridge						Coyote Ridge Wind, LLC
Integrys						Integrys Holding, Inc.
MERC						Minnesota Energy Resources Corporation
MGU						Michigan Gas Utilities Corporation
NSG						North Shore Gas Company
PDL						WPS Power Development, LLC
PGL						The Peoples Gas Light and Coke Company
UMERC						Upper Michigan Energy Resources Corporation

Upstream						Upstream Wind Energy LLC
WE						Wisconsin Electric Power Company
We Power						W.E. Power, LLC
WEC Energy Group						WEC Energy Group, Inc.
WECI						WEC Infrastructure LLC
WG						Wisconsin Gas LLC
WPS						Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
EPA						United States Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
ICC						Illinois Commerce Commission
IEPA						Illinois Environmental Protection Agency

MPSC						Michigan Public Service Commission
MPUC						Minnesota Public Utilities Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission


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
ACE						Affordable Clean Energy
BATW						Bottom Ash Transport Water
BSER						Best System of Emission Reduction
BTA						Best Technology Available
CAA						Clean Air Act
CO2						Carbon Dioxide
ELG						Steam Electric Effluent Limitation Guidelines
FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
GMZ						Groundwater Management Zone


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MATS						Mercury and Air Toxics Standards

NOV						Notice of Violation

RTR						Risk and Technology Review
The Combustion Turbine Rule						National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines
VN						Violation Notice




Measurements
Dth						Dekatherm
MW						Megawatt
MWh						Megawatt-hour

Other Terms and Abbreviations
2007 Junior Notes						WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067
AG						Attorney General
AMI						Advanced Metering Infrastructure
Badger Hollow I						Badger Hollow Solar Park I
Badger Hollow II						Badger Hollow Solar Park II
Blooming Grove						Blooming Grove Wind Energy Center LLC
CDC						Centers for Disease Control and Prevention
COVID-19						Coronavirus Disease – 2019
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
ERGS						Elm Road Generating Station
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
GUIC						Gas Utility Infrastructure Cost
LIBOR						London Interbank Offered Rate
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.

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

SPC						COVID-19 Special Purpose Charge
SSR						System Support Resource

Tatanka Ridge						Tatanka Ridge Wind LLC
Tax Legislation						Tax Cuts and Jobs Act of 2017
Thunderhead						Thunderhead Wind Energy LLC
Tilden						Tilden Mining Company
Two Creeks						Two Creeks Solar Park


WHO						World Health Organization


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, dividend payout ratios, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our 2019 Annual Report on Form 10-K, 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 impact of the COVID-19 pandemic on our business functions, financial condition, liquidity, and results of operations;

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

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

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

•The timely completion of capital projects within budgets and the ability to recover the related costs through rates;

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

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

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


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

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

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

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

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

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

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

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

•The financial performance of ATC and its corresponding contribution to our earnings;

•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 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 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.


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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended				Nine Months Ended
	September 30				September 30
(in millions, except per share amounts)	2020		2019		2020		2019
Operating revenues	$	1,651.0	$	1,608.0	$	5,308.3	$	5,575.6

Operating expenses
Cost of sales	482.8		484.3		1,662.0		1,985.8
Other operation and maintenance	498.7		529.2		1,427.5		1,583.4
Depreciation and amortization	245.0		233.8		726.6		690.1
Property and revenue taxes	54.3		49.8		156.6		148.0
Total operating expenses	1,280.8		1,297.1		3,972.7		4,407.3

Operating income	370.2		310.9		1,335.6		1,168.3

Equity in earnings of transmission affiliates	40.1		38.7		132.8		111.7
Other income, net	25.7		21.8		59.9		76.3
Interest expense	122.0		125.8		375.8		374.3
Other expense	(56.2)		(65.3)		(183.1)		(186.3)

Income before income taxes	314.0		245.6		1,152.5		982.0
Income tax expense	46.9		11.3		190.7		91.5
Net income	267.1		234.3		961.8		890.5

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Net loss attributed to noncontrolling interests	—		0.3		—		0.5
Net income attributed to common shareholders	$	266.8	$	234.3	$	960.9	$	890.1

Earnings per share
Basic	$	0.85	$	0.74	$	3.05	$	2.82
Diluted	$	0.84	$	0.74	$	3.04	$	2.81

Weighted average common shares outstanding
Basic	315.4		315.4		315.4		315.4
Diluted	316.5		316.8		316.6		316.7

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	Three Months Ended				Nine Months Ended
	September 30				September 30
(in millions)	2020		2019		2020		2019
Net income	$	267.1	$	234.3	$	961.8	$	890.5

Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Net derivative losses, net of tax benefits of $0.0, $(0.2), $(1.6), and $(1.5), respectively	—		(0.3)		(4.2)		(3.8)
Reclassification of net loss (gains) to net income, net of tax	0.9		(0.2)		1.4		(0.8)
Cash flow hedges, net	0.9		(0.5)		(2.8)		(4.6)

Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	—		—		0.5		0.1

Other comprehensive income (loss), net of tax	0.9		(0.5)		(2.3)		(4.5)

Comprehensive income	268.0		233.8		959.5		886.0

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Comprehensive loss attributed to noncontrolling interests	—		0.3		—		0.5
Comprehensive income attributed to common shareholders	$	267.7	$	233.8	$	958.6	$	885.6

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	September 30, 2020		December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	13.1	$	37.5
Accounts receivable and unbilled revenues, net of reserves of $173.3 and $140.0, respectively	911.8		1,176.5
Materials, supplies, and inventories	573.4		549.8

Prepayments	169.5		261.8
Other	59.4		68.0
Current assets	1,727.2		2,093.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $9,308.6 and $8,878.7, respectively	24,551.7		23,620.1
Regulatory assets	3,462.2		3,506.7
Equity investment in transmission affiliates	1,750.4		1,720.8
Goodwill	3,052.8		3,052.8
Other	877.7		957.8
Long-term assets	33,694.8		32,858.2
Total assets	$	35,422.0	$	34,951.8

Liabilities and Equity
Current liabilities
Short-term debt	$	771.0	$	830.8
Current portion of long-term debt	596.2		693.2
Accounts payable	751.3		908.1
Accrued payroll and benefits	173.9		199.8

Other	547.6		550.8
Current liabilities	2,840.0		3,182.7

Long-term liabilities
Long-term debt	11,652.5		11,211.0
Deferred income taxes	3,974.7		3,769.3
Deferred revenue, net	417.8		497.1
Regulatory liabilities	3,939.3		3,992.8
Environmental remediation liabilities	589.4		589.2
Pension and OPEB obligations	320.6		326.2
Other	1,128.6		1,128.9
Long-term liabilities	22,022.9		21,514.5

Commitments and contingencies (Note 22)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding	3.2		3.2
Additional paid in capital	4,163.8		4,186.6
Retained earnings	6,290.1		5,927.7
Accumulated other comprehensive loss	(6.4)		(4.1)
Common shareholders' equity	10,450.7		10,113.4

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	78.0		110.8
Total liabilities and equity	$	35,422.0	$	34,951.8

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(in millions)	2020		2019
Operating activities
Net income	$	961.8	$	890.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	726.6		690.1
Deferred income taxes and investment tax credits, net	152.5		58.8
Contributions and payments related to pension and OPEB plans	(10.1)		(12.1)
Equity income in transmission affiliates, net of distributions	(20.3)		(17.8)
Change in –
Accounts receivable and unbilled revenues, net	262.3		360.2
Materials, supplies, and inventories	(23.6)		(44.9)
Prepayments	92.3		90.7
Other current assets	37.2		19.7
Accounts payable	(178.9)		(192.3)
Other current liabilities	(23.3)		(1.8)
Other, net	(26.8)		(0.4)
Net cash provided by operating activities	1,949.7		1,840.7

Investing activities
Capital expenditures	(1,618.7)		(1,511.5)
Acquisition of Upstream, net of cash and restricted cash acquired of $9.2	—		(268.2)
Capital contributions to transmission affiliates	(15.2)		(37.3)
Proceeds from the sale of assets and businesses	9.8		32.2
Proceeds from the sale of investments held in rabbi trust	17.1		0.2
Reimbursement for ATC's construction costs	—		32.4
Insurance proceeds received for property damage	22.2		—
Proceeds from cash surrender value of life insurance	8.3		9.2
Other, net	13.4		8.5
Net cash used in investing activities	(1,563.1)		(1,734.5)

Financing activities
Exercise of stock options	23.3		66.1
Purchase of common stock	(56.7)		(138.2)
Dividends paid on common stock	(598.5)		(558.4)
Issuance of long-term debt	810.0		1,320.0
Retirement of long-term debt	(482.6)		(106.0)
Issuance of short-term loan	340.0		—
Change in other short-term debt	(399.8)		(753.7)
Purchase of additional ownership interest in Upstream from noncontrolling interest	(31.0)		—
Other, net	(12.4)		(15.5)
Net cash used in financing activities	(407.7)		(185.7)

Net change in cash, cash equivalents, and restricted cash	(21.1)		(79.5)
Cash, cash equivalents, and restricted cash at beginning of period	82.3		146.1
Cash, cash equivalents, and restricted cash at end of period	$	61.2	$	66.6

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

	WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)	Common Stock		Additional Paid In Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Shareholders' Equity		Preferred Stock of Subsidiary		Non-controlling Interests		Total Equity
Balance at December 31, 2019	$	3.2	$	4,186.6	$	5,927.7	$	(4.1)	$	10,113.4	$	30.4	$	110.8	$	10,254.6
Net income attributed to common shareholders	—		—		452.5		—		452.5		—		—		452.5
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.2)		(0.2)
Other comprehensive loss	—		—		—		(3.0)		(3.0)		—		—		(3.0)
Common stock dividends of $0.6325 per share	—		—		(199.5)		—		(199.5)		—		—		(199.5)
Exercise of stock options	—		16.0		—		—		16.0		—		—		16.0
Purchase of common stock	—		(40.4)		—		—		(40.4)		—		—		(40.4)
Distributions to noncontrolling interests	—		—		—		—		—		—		(0.5)		(0.5)
Stock-based compensation and other	—		5.1		—		—		5.1		—		—		5.1
Balance at March 31, 2020	$	3.2	$	4,167.3	$	6,180.7	$	(7.1)	$	10,344.1	$	30.4	$	110.1	$	10,484.6
Net income attributed to common shareholders	—		—		241.6		—		241.6		—		—		241.6
Net income attributed to noncontrolling interests	—		—		—		—		—		—		0.2		0.2
Other comprehensive loss	—		—		—		(0.2)		(0.2)		—		—		(0.2)
Common stock dividends of $0.6325 per share	—		—		(199.5)		—		(199.5)		—		—		(199.5)
Exercise of stock options	—		4.3		—		—		4.3		—		—		4.3
Purchase of common stock	—		(9.9)		—		—		(9.9)		—		—		(9.9)
Purchase of additional ownership interest in Upstream from noncontrolling interest	—		—		—		—		—		—		(31.0)		(31.0)
Distributions to noncontrolling interests	—		—		—		—		—		—		(0.7)		(0.7)
Stock-based compensation and other	—		3.3		—		—		3.3		—		—		3.3
Balance at June 30, 2020	$	3.2	$	4,165.0	$	6,222.8	$	(7.3)	$	10,383.7	$	30.4	$	78.6	$	10,492.7
Net income attributed to common shareholders	—		—		266.8		—		266.8		—		—		266.8

Other comprehensive income	—		—		—		0.9		0.9		—		—		0.9
Common stock dividends of $0.6325 per share	—		—		(199.5)		—		(199.5)		—		—		(199.5)
Exercise of stock options	—		3.0		—		—		3.0		—		—		3.0
Purchase of common stock	—		(6.4)		—		—		(6.4)		—		—		(6.4)
Distributions to noncontrolling interests	—		—		—		—		—		—		(0.6)		(0.6)
Stock-based compensation and other	—		2.2		—		—		2.2		—		—		2.2
Balance at September 30, 2020	$	3.2	$	4,163.8	$	6,290.1	$	(6.4)	$	10,450.7	$	30.4	$	78.0	$	10,559.1


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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) (continued)

	WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)	Common Stock		Additional Paid In Capital		Retained Earnings		Accumulated Other Comprehensive 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

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


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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2020

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 2.9 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple wind generating facilities as part of its non-utility energy infrastructure business.

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, 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 sheets related to the minority interests at Bishop Hill III, Coyote Ridge, and Upstream held by third parties. See Note 2, Acquisitions, for more information on Upstream.

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 19, 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, 2019. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2020, are not necessarily indicative of expected results for 2020 due to seasonal variations and other factors, including any continuing financial impacts from the COVID-19 pandemic.

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

NOTE 2—ACQUISITIONS

On January 1, 2018, we adopted ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update clarify the definition of a business and provide guidance on evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 also clarifies that transaction costs are capitalized in an asset acquisition but expensed in a business combination.

Acquisition of a Wind Energy Generation Facility in South Dakota

In July 2020, WECI signed an agreement to acquire an 85% ownership interest in Tatanka Ridge, a 155 MW wind generating facility under construction in Deuel County, South Dakota. We expect WECI's total investment to be approximately $235 million. Tatanka Ridge has long-term offtake agreements for all the energy produced with an affiliate of an investment grade multinational company and a well-established electric cooperative that serves utilities in multiple states. Under the Tax Legislation, WECI's investment in Tatanka Ridge is expected to qualify for production tax credits. The transaction was approved by FERC in October 2020 and is expected to close during the fourth quarter of 2020, with commercial operation expected to begin by early 2021. WECI will provide guarantees for certain construction obligations during the period between closing and commercial operation. Tatanka Ridge will be included in the non-utility energy infrastructure segment.


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Acquisition of Wind Generation Facilities in Nebraska

In August 2019, WECI 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. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for 12 years. Under the Tax Legislation, WECI's investment in Thunderhead is expected to qualify for production tax credits . The transaction was approved by FERC in April 2020, and commercial operation was initially expected to begin by the end of 2020. However, due to a court ruling suspending a key permit and the subsequent decision by the local utility to suspend construction of the required substation, the commercial operation of Thunderhead could be delayed until as late as the summer of 2021. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment.

In January 2019, WECI 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. In April 2020, WECI completed the acquisition of an additional 10% ownership interest in Upstream for approximately $31.0 million. Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over 10 years through an agreement with an unaffiliated third party. Under the Tax Legislation, WECI's investment in Upstream qualifies for production tax credits. Upstream is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition of the initial 80% ownership interest in Upstream.


(in millions)
Current assets	$	0.4
Net property, plant, and equipment	341.6
Other long-term assets	14.8
Current liabilities	(4.6)
Long-term liabilities	(15.0)
Noncontrolling interest	(69.0)
Total purchase price	$	268.2

Acquisition of a Wind Energy Generation Facility in Illinois

In January 2020, WECI signed an agreement to acquire an 80% ownership interest in Blooming Grove, a 250 MW wind generating facility under construction in McLean County, Illinois, for a total investment of approximately $345 million. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Blooming Grove for $44 million. Blooming Grove has long-term offtake agreements for all the energy produced with affiliates of two investment grade multinational companies. Under the Tax Legislation, WECI's investment in Blooming Grove is expected to qualify for production tax credits. The transaction was approved by FERC in October 2020 and commercial operation is expected to begin by the end of 2020, at which time the transaction is expected to close. Blooming Grove will be included in the non-utility energy infrastructure segment.

NOTE 3—DISPOSITION

Corporate and Other Segment – Sale of Certain WPS Power Development, LLC Solar Power Generation Facilities

In June 2019, we sold three solar power generation facilities owned by PDL for $20.0 million. These solar facilities were located in Massachusetts. During the second quarter of 2019, we recorded an after-tax gain on the sale of $4.9 million primarily related to the recognition of deferred investment tax credits, which were included as a reduction of income 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 these 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.


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NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. 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 can be impacted differently 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, 2020
Electric	$	1,212.9	$	—	$	—	$	1,212.9	$	—	$	—	$	—	$	1,212.9
Natural gas	150.5		213.4		43.1		407.0		9.1		—		(8.3)		407.8
Total regulated revenues	1,363.4		213.4		43.1		1,619.9		9.1		—		(8.3)		1,620.7
Other non-utility revenues	—		0.1		4.2		4.3		14.7		0.5		(1.6)		17.9
Total revenues from contracts with customers	1,363.4		213.5		47.3		1,624.2		23.8		0.5		(9.9)		1,638.6
Other operating revenues	2.9		8.4		1.0		12.3		99.7		0.1		(99.7)		12.4
Total operating revenues	$	1,366.3	$	221.9	$	48.3	$	1,636.5	$	123.5	$	0.6	$	(109.6)	$	1,651.0


(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, 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
Nine Months Ended September 30, 2020
Electric	$	3,247.1	$	—	$	—	$	3,247.1	$	—	$	—	$	—	$	3,247.1
Natural gas	817.2		901.5		245.3		1,964.0		32.3		—		(30.6)		1,965.7
Total regulated revenues	4,064.3		901.5		245.3		5,211.1		32.3		—		(30.6)		5,212.8
Other non-utility revenues	—		0.1		12.8		12.9		48.2		1.7		(7.1)		55.7
Total revenues from contracts with customers	4,064.3		901.6		258.1		5,224.0		80.5		1.7		(37.7)		5,268.5
Other operating revenues	7.1		29.1		3.3		39.5		297.9		0.3		(297.9)		39.8
Total operating revenues	$	4,071.4	$	930.7	$	261.4	$	5,263.5	$	378.4	$	2.0	$	(335.6)	$	5,308.3


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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, 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

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)	2020		2019		2020		2019
Residential	$	500.8	$	454.7	$	1,324.4	$	1,218.1
Small commercial and industrial	373.6		385.6		1,004.3		1,050.8
Large commercial and industrial	244.0		237.9		626.4		668.0
Other	6.9		6.9		21.1		22.0
Total retail revenues	1,125.3		1,085.1		2,976.2		2,958.9
Wholesale	46.5		53.1		129.9		145.4
Resale	33.7		29.5		107.3		119.7
Steam	2.5		2.4		15.0		16.8
Other utility revenues	4.9		15.3		18.7		28.3
Total electric utility operating revenues	$	1,212.9	$	1,185.4	$	3,247.1	$	3,269.1

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, 2020
Residential	$	74.6	$	128.6	$	18.8	$	222.0
Commercial and industrial	28.3		28.6		10.2		67.1
Total retail revenues	102.9		157.2		29.0		289.1
Transport	15.7		40.0		5.3		61.0
Other utility revenues (1)	31.9		16.2		8.8		56.9
Total natural gas utility operating revenues	$	150.5	$	213.4	$	43.1	$	407.0


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(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 (1)	37.4		(1.2)		4.2		40.4
Total natural gas utility operating revenues	$	151.1	$	190.0	$	43.8	$	384.9


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2020
Residential	$	513.5	$	568.9	$	154.1	$	1,236.5
Commercial and industrial	226.6		156.5		78.5		461.6
Total retail revenues	740.1		725.4		232.6		1,698.1
Transport	56.8		159.0		22.8		238.6
Other utility revenues (1)	20.3		17.1		(10.1)		27.3
Total natural gas utility operating revenues	$	817.2	$	901.5	$	245.3	$	1,964.0


(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 (1)	25.9		(27.2)		(21.0)		(22.3)
Total natural gas utility operating revenues	$	943.3	$	967.4	$	293.0	$	2,203.7

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

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to 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 the following:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2020		2019		2020		2019
Wind generation revenues	$	7.4	$	4.9	$	24.0	$	17.0
We Power revenues (1)	5.8		6.4		17.1		19.1
Appliance service revenues	4.2		4.2		12.8		12.5
Distributed renewable solar project revenues	0.3		1.3		1.4		3.6
Other	0.2		—		0.4		0.1
Total other non-utility operating revenues	$	17.9	$	16.8	$	55.7	$	52.3


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(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 these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, and we continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During the three and nine months ended September 30, 2020, we recorded $5.8 million and $17.1 million, respectively, of revenues related to these deferred carrying costs. During the three and nine months ended September 30, 2019, we recorded $6.4 million and $19.1 million, respectively, of revenues related to these deferred carrying costs. These contract liabilities are presented as deferred revenue, net on our balance sheets.

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2020		2019		2020		2019
Late payment charges (1)	$	6.0	$	9.7	$	18.1	$	34.9
Alternative revenues (2)	5.4		1.4		18.2		(17.2)
Other	1.0		9.3		3.5		29.9
Total other operating revenues	$	12.4	$	20.4	$	39.8	$	47.6

(1)The reduction in late payment charges is a result of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which include the suspension of late payment charges during a designated time period. The amount of late payment charges recorded as alternative revenues during the three and nine months ended September 30, 2020 were $1.7 million and $8.5 million, respectively. See Note 24, Regulatory Environment, for more information.

(2)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, wholesale true-ups, and conservation improvement rider true-ups, as discussed in Note 1(d), Operating Revenues, in our 2019 Annual Report on Form 10-K.

NOTE 5—CREDIT LOSSES

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

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties. At the corporate and other segment, the accounts receivable and unbilled revenue balance is related to the remaining PDL residential solar business.

We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required. At September 30, 2020, we had an incremental reserve of $2.9 million included within our allowance for credit losses specific to the economic risks associated with the


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COVID-19 pandemic, which continues to evolve. We will continue to monitor the economic impacts of COVID-19 and the resulting effect that these impacts may have on the ability of our customers to pay their energy bills.

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 24, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic.

We have included a table below that shows our gross third-party receivable balances and the related allowance for credit losses at September 30, 2020, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
Accounts receivable and unbilled revenues	$	766.8		$	272.8		$	34.8		$	1,074.4		$	6.5		$	4.2		$	1,085.1
Allowance for credit losses	88.5			80.2			4.4			173.1			—			0.2			173.3
Accounts receivable and unbilled revenues, net (1)	$	678.3		$	192.6		$	30.4		$	901.3		$	6.5		$	4.0		$	911.8

Total accounts receivable, net – past due greater than 90 days (1)	$	71.5		$	53.6		$	7.1		$	132.2		$	—		$	—		$	132.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.0		%	100.0		%	—		%	93.0		%	—		%	—		%	93.0		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at September 30, 2020, $498.3 million, or 54.7%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our September 30, 2020 accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentages in the above table or this note. See Note 24, Regulatory Environment, for more information on these orders.

A rollforward of the allowance for credit losses by reportable segment for the three and nine months ended September 30, 2020, is included below:


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Corporate and Other		WEC Energy Group Consolidated
Balance at June 30, 2020	$	77.9	$	82.7	$	4.0	$	164.6	$	0.1	$	164.7
Provision for credit losses	14.8		6.3		1.0		22.1		0.1		22.2
Provision for credit losses deferred for future recovery or refund	2.5		(3.2)		—		(0.7)		—		(0.7)
Write-offs charged against the allowance	(14.5)		(10.0)		(0.9)		(25.4)		—		(25.4)
Recoveries of amounts previously written off	7.8		4.4		0.3		12.5		—		12.5
Balance at September 30, 2020	$	88.5	$	80.2	$	4.4	$	173.1	$	0.2	$	173.3


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(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Corporate and Other		WEC Energy Group Consolidated
Balance at December 31, 2019	$	59.9	$	75.9	$	4.1	$	139.9	$	0.1	$	140.0
Provision for credit losses	40.8		28.3		2.1		71.2		0.1		71.3
Provision for credit losses deferred for future recovery or refund	11.6		22.4		—		34.0		—		34.0
Write-offs charged against the allowance	(52.2)		(59.5)		(2.9)		(114.6)		—		(114.6)
Recoveries of amounts previously written off	28.4		13.1		1.1		42.6		—		42.6
Balance at September 30, 2020	$	88.5	$	80.2	$	4.4	$	173.1	$	0.2	$	173.3

The increase in the allowance for credit losses at our Wisconsin and Illinois reportable segments in 2020, was driven by an increase in past due accounts receivable balances from December 31, 2019 to September 30, 2020. This is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31. However, as a result of the COVID-19 pandemic and related regulatory orders we have received, we were also unable to disconnect any of our Wisconsin and Illinois customers during the second and third quarters of 2020. See Note 24, Regulatory Environment, for more information.

NOTE 6—REGULATORY ASSETS AND LIABILITIES

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


(in millions)	September 30, 2020		December 31, 2019
Regulatory assets
Pension and OPEB costs	$	986.0	$	1,066.6
Plant retirements	841.7		856.4
Environmental remediation costs	696.6		685.5
Income tax related items	456.0		457.8
Asset retirement obligations	201.2		137.5
SSR	137.4		151.5
Uncollectible expense	66.3		52.2
COVID-19 (1)	23.3		—
Derivatives	11.6		33.8
We Power generation	7.1		25.8
Other, net	57.2		60.5
Total regulatory assets	$	3,484.4	$	3,527.6

Balance sheet presentation
Other current assets	$	22.2	$	20.9
Regulatory assets	3,462.2		3,506.7
Total regulatory assets	$	3,484.4	$	3,527.6

(1)See Note 24, Regulatory Environment, for more information.


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(in millions)	September 30, 2020		December 31, 2019
Regulatory liabilities
Income tax related items	$	2,163.8	$	2,248.8
Removal costs	1,213.3		1,181.5
Pension and OPEB benefits	337.8		354.9
Energy costs refundable through rate adjustments	76.8		89.8
Electric transmission costs	70.8		42.2
Derivatives	35.5		6.7
Uncollectible expense	34.1		39.1
Earnings sharing mechanisms	33.6		43.5
Decoupling	25.6		36.8
Energy efficiency programs	13.3		30.7
Other, net	7.8		6.4
Total regulatory liabilities	$	4,012.4	$	4,080.4

Balance sheet presentation
Other current liabilities	$	73.1	$	87.6
Regulatory liabilities	3,939.3		3,992.8
Total regulatory liabilities	$	4,012.4	$	4,080.4

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s Public Service Building. The damage to the building from the flooding and steam was extensive and will require significant repairs and restorations. As of September 30, 2020, WE had incurred $16.8 million of costs related to these repairs and restorations, and we have received insurance proceeds sufficient to cover these costs. We are working closely with our insurance carriers, and we anticipate that any current and future expenditures required to restore the Public Service Building will largely be covered by insurance. As such, we do not currently expect a significant impact to our results of operations, and although we may experience differences between periods in the timing of cash flows, we also do not currently expect a significant impact to our long-term cash flows from this event.

NOTE 8—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2020, 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)						554,594
Restricted shares (2)						91,873
Performance units						153,465

(1)Stock options awarded had a weighted-average exercise price of $91.51 and a weighted-average grant date fair value of $10.94 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $91.54 per share.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, ATC Holding LLC, which holds our ownership interest in ATC, and WECI. 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 10, Common Equity, in our 2019 Annual Report on Form 10-K for additional information on these and other restrictions.


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

Common Stock Dividends

On October 15, 2020, our Board of Directors declared a quarterly cash dividend of $0.6325 per share, payable on December 1, 2020, to shareholders of record on November 13, 2020.

NOTE 9—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, 2020			December 31, 2019
Commercial paper
Amount outstanding	$	431.0		$	830.8
Weighted-average interest rate on amounts outstanding	0.15		%	2.00		%
Term loan
Amount outstanding	$	340.0		$	—
Weighted-average interest rate on amounts outstanding	0.97		%	N/A

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2020 was $772.7 million with a weighted-average interest rate during the period of 1.08%.

In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $340.0 million 364-day term loan that will mature on March 29, 2021. The proceeds from this term loan were used to pay down commercial paper. The weighted-average interest rate on the term loan during the nine months ended September 30, 2020 was 1.59%.

The information in the table below relates to our term loan agreement and our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these credit agreements:


(in millions)	Maturity	September 30, 2020
Term loan agreement (WEC Energy Group)	March 2021	$	340.0
Revolving credit facility (WEC Energy Group)	October 2022	1,200.0
Revolving credit facility (WE)	October 2022	500.0
Revolving credit facility (WPS)	October 2022	400.0
Revolving credit facility (WG)	October 2022	350.0
Revolving credit facility (PGL)	October 2022	350.0
Total short-term credit capacity		$	3,140.0
Less:
Letters of credit issued inside credit facilities		$	2.3
Term loan outstanding		340.0
Commercial paper outstanding		431.0
Available capacity under existing credit agreements		$	2,366.7

NOTE 10—LONG-TERM DEBT

WEC Energy Group, Inc.

In May 2020, we redeemed at par all $400.0 million outstanding of our 2.45% Senior Notes due June 15, 2020.

In September 2020, we issued $700.0 million of 0.55% Senior Notes due September 15, 2023, and used the net proceeds to repay commercial paper and for working capital and other general corporate purposes.


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In October 2020, we issued $500.0 million of 1.375% Senior Notes due October 15, 2027, and $450.0 million of 1.800% Senior Notes due October 15, 2030. We used the net proceeds to redeem our $600.0 million of 3.375% Senior Notes due June 15, 2021 and our $350.0 million of 3.10% Senior Notes due March 8, 2022, and for other general corporate purposes. As a result of redeeming our 3.375% Senior Notes and our 3.10% Senior Notes prior to their maturity dates, we recognized a $27.9 million loss on early extinguishment of debt in October 2020. The loss is comprised of the make-whole premium associated with the early redemptions and the write-off of unamortized debt discounts and debt issuance costs as of the redemption date.

The Peoples Gas Light and Coke Company

In August 2020, PGL redeemed at par all $50.0 million outstanding of its 1.875% Series WW Bonds due February 1, 2033.

Minnesota Energy Resources Corporation

In April 2020, MERC issued $50.0 million of 2.69% Senior Notes due May 1, 2025, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys, and for general corporate purposes, including capital expenditures.

Michigan Gas Utilities Corporation

In April 2020, MGU issued $60.0 million of 2.69% Senior Notes due May 1, 2025, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys, and for general corporate purposes, including capital expenditures.

NOTE 11—LEASES

WE has partnered with an unaffiliated utility to construct Badger Hollow II in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. The PSCW approved the acquisition of Badger Hollow II in March 2020 and commercial operation is targeted for December 2022.

Related to its investment in Badger Hollow II, WE, along with its unaffiliated utility partner, entered into several land leases in Iowa County, Wisconsin that commenced in the second quarter of 2020. 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 are being amortized over the extended term of the leases. The lease payments will be recovered through rates.

Our total obligation under the land related finance leases for Badger Hollow II was $22.9 million at September 30, 2020, and will decrease to zero over the remaining lives of the leases. Long-term lease liabilities related to our finance leases for Badger Hollow II were included in long-term debt on the balance sheets. Our finance lease right of use asset related to Badger Hollow II was $22.7 million as of September 30, 2020, and was included in property, plant, and equipment on our balance sheets.

In accordance with Accounting Standard Codification Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the expense recognition pattern associated with the Badger Hollow II leases resembles that of an operating lease, as amortization of the right of use assets has been modified from what would typically be recorded for a finance lease under Topic 842. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset in accordance with Subtopic 980-842 on our balance sheet.

At September 30, 2020, our weighted-average discount rate for the Badger Hollow II finance leases was 3.44%. 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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Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for Badger Hollow II as of September 30, 2020, were as follows:


(in millions)
2021	$	0.3
2022	0.3
2023	0.7
2024	0.7
2025	0.7
Thereafter	55.0
Total minimum lease payments	57.7
Less: Interest	(34.8)
Present value of minimum lease payments	22.9
Less: Short-term lease liabilities	—
Long-term lease liabilities	$	22.9

NOTE 12—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:


(in millions)	September 30, 2020		December 31, 2019
Natural gas in storage	$	251.9	$	227.7
Materials and supplies	247.3		234.2
Fossil fuel	74.2		87.9
Total	$	573.4	$	549.8

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2020, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

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 13—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, 2020				Three Months Ended September 30, 2019
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	65.9	21.0	%	$	51.5	21.0	%
State income taxes net of federal tax benefit	19.7		6.3	%	20.3		8.2	%
Federal excess deferred tax amortization – Wisconsin unprotected	(12.5)		(4.0)	%	—		—	%
Wind production tax credits	(11.2)		(3.6)	%	(6.8)		(2.8)	%
Federal excess deferred tax amortization	(8.3)		(2.6)	%	(12.0)		(4.9)	%
Uncertain tax positions	(5.1)		(1.6)	%	0.3		0.1	%
Excess tax benefits – stock options	(0.6)		(0.2)	%	(3.9)		(1.6)	%
Tax repairs	0.9		0.3	%	(30.7)		(12.5)	%
Other	(1.9)		(0.7)	%	(7.4)		(2.9)	%
Total income tax expense	$	46.9	14.9	%	$	11.3	4.6	%


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	Nine Months Ended September 30, 2020				Nine Months Ended September 30, 2019
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	242.0	21.0	%	$	206.1	21.0	%
State income taxes net of federal tax benefit	72.1		6.3	%	66.8		6.8	%
Federal excess deferred tax amortization – Wisconsin unprotected	(45.7)		(4.0)	%	—		—	%
Wind production tax credits	(39.0)		(3.4)	%	(26.4)		(2.7)	%
Federal excess deferred tax amortization	(30.2)		(2.6)	%	(32.7)		(3.3)	%
Excess tax benefits – stock options	(6.9)		(0.6)	%	(15.5)		(1.6)	%
Uncertain tax positions	(5.8)		(0.5)	%	(2.6)		(0.3)	%
Tax repairs	2.4		0.2	%	(90.7)		(9.2)	%
Other	1.8		0.1	%	(13.5)		(1.4)	%
Total income tax expense	$	190.7	16.5	%	$	91.5	9.3	%

The effective tax rates of 14.9% and 16.5% for the three and nine months ended September 30, 2020, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. In addition, wind production tax credits generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate, which was partially offset by state income taxes.

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 protected benefits associated with the Tax Legislation, as discussed in more detail below, and wind production tax credits generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment, partially offset by state income taxes.

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

See Note 24, Regulatory Environment, for more information.

NOTE 14—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.


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

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

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:


	September 30, 2020
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	32.4	$	3.2	$	—	$	35.6
FTRs	—		—		4.0		4.0
Coal contracts	—		0.5		—		0.5
Total derivative assets	$	32.4	$	3.7	$	4.0	$	40.1

Investments held in rabbi trust	$	72.6	$	—	$	—	$	72.6

Derivative liabilities
Natural gas contracts	$	0.9	$	3.9	$	—	$	4.8
Coal contracts	—		2.4		—		2.4
Interest rate swaps	—		8.3		—		8.3
Total derivative liabilities	$	0.9	$	14.6	$	—	$	15.5


	December 31, 2019
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.4	$	2.0	$	—	$	3.4
FTRs	—		—		3.1		3.1
Coal contracts	—		0.4		—		0.4
Total derivative assets	$	1.4	$	2.4	$	3.1	$	6.9

Investments held in rabbi trust	$	85.3	$	—	$	—	$	85.3

Derivative liabilities
Natural gas contracts	$	21.4	$	1.3	$	—	$	22.7
Coal contracts	—		0.2		—		0.2
Interest rate swaps	—		6.0		—		6.0
Total derivative liabilities	$	21.4	$	7.5	$	—	$	28.9

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 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, 2020 and 2019, the net unrealized gains included in earnings related to the investments held at the end of the period were $5.7 million and


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$0.7 million, respectively. For the nine months ended September 30, 2020 and 2019, the net unrealized gains included in earnings related to the investments held at the end of the period were $2.9 million and $12.1 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)	2020		2019		2020		2019
Balance at the beginning of the period	$	6.5	$	10.4	$	3.1	$	7.4
Purchases	—		—		7.5		12.8
Settlements	(2.5)		(4.2)		(6.6)		(14.0)
Balance at the end of the period	$	4.0	$	6.2	$	4.0	$	6.2

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that were not recorded at fair value:


	September 30, 2020				December 31, 2019
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	29.9	$	30.4	$	29.5
Long-term debt, including current portion (1)	12,184.1		14,007.9		11,858.3		13,035.9

(1)The carrying amount of long-term debt excludes finance lease obligations of $64.6 million and $45.9 million at September 30, 2020 and December 31, 2019, respectively.

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

NOTE 15—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.


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None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges. The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets.


	September 30, 2020				December 31, 2019
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	31.1	$	4.7	$	3.4	$	21.8
FTRs	4.0		—		3.1		—
Coal contracts	0.2		1.3		0.2		0.2
Interest rate swaps	—		6.6		—		2.8
Total other current (1)	35.3		12.6		6.7		24.8

Other long-term
Natural gas contracts	4.5		0.1		—		0.9
Coal contracts	0.3		1.1		0.2		—
Interest rate swaps	—		1.7		—		3.2
Total other long-term (1)	4.8		2.9		0.2		4.1
Total	$	40.1	$	15.5	$	6.9	$	28.9

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

Realized gains (losses) on derivatives 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, 2020			Three Months Ended September 30, 2019
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	36.2 Dth	$	(12.0)	37.8 Dth	$	(13.2)
FTRs	8.3 MWh	1.1		7.8 MWh	7.6
Total		$	(10.9)		$	(5.6)


	Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	139.3 Dth	$	(53.9)	137.7 Dth	$	(16.8)
FTRs	22.7 MWh	3.1		23.9 MWh	12.9
Total		$	(50.8)		$	(3.9)

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, 2020, we had received cash collateral of $14.6 million in our margin accounts. This amount was recorded on our balance sheet in other current liabilities. At December 31, 2019, we had posted cash collateral of $34.4 million in our margin accounts. This amount was recorded on our balance sheet in other current assets.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:


	September 30, 2020					December 31, 2019
(in millions)	Derivative Assets			Derivative Liabilities		Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	40.1		$	15.5	$	6.9	$	28.9
Gross amount not offset on the balance sheet	(15.6)		(1)	(1.0)		(1.4)		(21.4)		(2)
Net amount	$	24.5		$	14.5	$	5.5	$	7.5

(1)Includes cash collateral received of $14.6 million.


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(2)Includes cash collateral posted of $20.0 million.

Cash Flow Hedges

As of September 30, 2020, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps 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 qualify for cash flow hedge accounting treatment, the related gains and losses are being deferred in accumulated other comprehensive loss and are 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 acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The table below shows the amounts related to these 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)	2020		2019		2020		2019
Derivative losses recognized in other comprehensive loss	$	—	$	(0.5)	$	(5.8)	$	(5.3)
Net derivative gains (losses) reclassified from accumulated other comprehensive loss to interest expense	(1.3)		0.2		(2.0)		1.0
Total interest expense line item on the income statements	122.0		125.8		375.8		374.3

We estimate that during the next twelve months $5.1 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense.

NOTE 16—GUARANTEES

The following table shows our outstanding guarantees:


			Expiration
(in millions)	Total Amounts Committed at September 30, 2020		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees
Guarantees supporting transactions of subsidiaries (1)	$	28.1	$	5.9	$	1.2	$	21.0
Standby letters of credit (2)	69.5		0.4		0.2		68.9
Surety bonds (3)	9.8		9.7		0.1		—
Other guarantees (4)	11.0		0.9		—		10.1
Total guarantees	$	118.4	$	16.9	$	1.5	$	100.0

(1)Consists of $2.7 million, $4.2 million, and $21.2 million to support the business operations of Bluewater, UMERC, and WECI, 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 $11.0 million related to other indemnifications, for which a liability of $10.1 million related to workers compensation coverage was recorded on our balance sheets.


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NOTE 17—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) for our benefit plans.


	Pension Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2020		2019		2020		2019
Service cost	$	12.5	$	11.6	$	37.3	$	34.7
Interest cost	25.6		30.3		77.8		91.1
Expected return on plan assets	(47.4)		(48.3)		(143.0)		(145.2)
Loss on plan settlement	5.2		7.8		15.5		9.6
Amortization of prior service cost	0.4		0.5		1.2		1.6
Amortization of net actuarial loss	26.1		18.9		75.8		56.6
Net periodic benefit cost	$	22.4	$	20.8	$	64.6	$	48.4


	OPEB Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2020		2019		2020		2019
Service cost	$	3.8	$	4.1	$	11.4	$	12.3
Interest cost	4.7		6.5		14.0		19.3
Expected return on plan assets	(15.0)		(13.7)		(45.2)		(41.0)

Amortization of prior service credit	(3.8)		(3.9)		(11.3)		(11.6)
Amortization of net actuarial gain	(5.6)		(2.0)		(16.8)		(4.7)
Net periodic benefit credit	$	(15.9)	$	(9.0)	$	(47.9)	$	(25.7)

During the nine months ended September 30, 2020, we made contributions and payments of $9.0 million related to our pension plans and $1.1 million related to our OPEB plans. We expect to make contributions and payments of $2.5 million related to our pension plans during the remainder of 2020, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to make any contributions and payments related to our OPEB plans during the remainder of 2020.

NOTE 18—GOODWILL

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at September 30, 2020. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2020.


(in millions)	Wisconsin		Illinois		Other States		Non-Utility Energy Infrastructure		Total
Goodwill balance (1)	$	2,104.3	$	758.7	$	183.2	$	6.6	$	3,052.8

(1)We had no accumulated impairment losses related to our goodwill as of September 30, 2020.

In the third quarter of 2020, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2020. No impairments resulted from these tests.


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NOTE 19—INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:


	Three Months Ended September 30, 2020
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,713.3	$	31.4	$	1,744.7
Add: Earnings from equity method investment	39.6		0.5		40.1
Add: Capital contributions	6.2		—		6.2
Less: Distributions	39.9		—		39.9
Less: Return of capital	—		0.6		0.6
Less: Other	0.1		—		0.1
Balance at end of period	$	1,719.1	$	31.3	$	1,750.4


	Three Months Ended September 30, 2019
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,656.6	$	39.9	$	1,696.5
Add: Earnings from equity method investment	38.3		0.4		38.7
Add: Capital contributions	15.1		0.3		15.4
Less: Distributions	30.3		—		30.3
Add: Other	0.1		—		0.1
Balance at end of period	$	1,679.8	$	40.6	$	1,720.4


	Nine Months Ended September 30, 2020
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,684.7	$	36.1	$	1,720.8
Add: Earnings from equity method investment	131.7		1.1		132.8
Add: Capital contributions	15.2		—		15.2
Less: Distributions	112.5		—		112.5
Less: Return of capital	—		5.9		5.9

Balance at end of period	$	1,719.1	$	31.3	$	1,750.4


	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

We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.


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The following table summarizes our significant related party transactions with ATC:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2020		2019		2020		2019
Charges to ATC for services and construction	$	5.7	$	9.2	$	18.7	$	16.5
Charges from ATC for network transmission services	85.5		86.9		252.0		261.0

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


(in millions)	September 30, 2020		December 31, 2019
Accounts receivable for services provided to ATC	$	2.1	$	3.5

Accounts payable for services received from ATC	30.0		29.0
Amounts due from ATC for transmission infrastructure upgrades (1)	5.1		2.8

(1)In connection with WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks, and WE's construction of its new solar project, Badger Hollow II, WPS and WE are 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 and WE for these costs after the new generation has been placed in service.

Summarized financial data for ATC is included in the tables below:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2020		2019		2020		2019
Income statement data
Operating revenues	$	187.8	$	184.9	$	577.7	$	544.8
Operating expenses	93.0		94.7		285.7		278.7
Other expense, net	28.1		28.7		82.0		86.1
Net income	$	66.7	$	61.5	$	210.0	$	180.0


(in millions)	September 30, 2020		December 31, 2019
Balance sheet data
Current assets	$	92.5	$	84.7
Noncurrent assets	5,375.2		5,244.2
Total assets	$	5,467.7	$	5,328.9

Current liabilities	$	349.9	$	502.6
Long-term debt	2,512.1		2,312.8
Other noncurrent liabilities	335.0		298.9
Members' equity	2,270.7		2,214.6
Total liabilities and members' equity	$	5,467.7	$	5,328.9

NOTE 20—SEGMENT INFORMATION

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

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

•The Illinois segment includes the natural gas 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


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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 non-utility energy infrastructure segment 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, and

◦WECI, which holds our ownership interests in the following wind generating facilities:

▪90% ownership interest in Bishop Hill III, located in Henry County, Illinois,

▪80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota, and

▪90% ownership interest in Upstream, located in Antelope County, Nebraska.

See Note 2, Acquisitions, for more information on 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, Wisvest LLC, Wisconsin Energy Capital Corporation, WEC Business Services LLC, and PDL. In 2019, we sold certain PDL solar power generating facilities. See Note 3, Disposition, for more information on these sales.

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, 2020 and 2019:


	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, 2020
External revenues	$	1,366.3	$	221.9	$	48.3	$	1,636.5	$	—	$	13.9	$	0.6	$	—	$	1,651.0
Intersegment revenues	—		—		—		—		—		109.6		—		(109.6)		—
Other operation and maintenance	363.8		109.2		20.4		493.4		—		5.9		1.0		(1.6)		498.7
Depreciation and amortization	169.7		49.9		8.5		228.1		—		24.5		6.5		(14.1)		245.0
Operating income (loss)	349.0		24.5		(2.0)		371.5		—		91.3		(6.9)		(85.7)		370.2
Equity in earnings of transmission affiliates	—		—		—		—		40.1		—		—		—		40.1
Interest expense	139.1		15.6		2.7		157.4		4.9		15.0		30.4		(85.7)		122.0


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	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
Three Months Ended
September 30, 2019
External revenues	$	1,339.3	$	198.0	$	48.9	$	1,586.2	$	—	$	20.5	$	1.3	$	—	$	1,608.0
Intersegment revenues	—		—		—		—		—		98.9		—		(98.9)		—
Other operation and maintenance	400.2		101.8		22.0		524.0		—		3.9		1.3		—		529.2
Depreciation and amortization	155.6		45.7		6.8		208.1		—		23.3		6.0		(3.6)		233.8
Operating income (loss)	290.8		24.8		(2.2)		313.4		—		90.3		(6.0)		(86.8)		310.9
Equity in earnings of transmission affiliates	—		—		—		—		38.7		—		—		—		38.7
Interest expense	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
Nine Months Ended
September 30, 2020
External revenues	$	4,071.4	$	930.7	$	261.4	$	5,263.5	$	—	$	42.8	$	2.0	$	—	$	5,308.3
Intersegment revenues	—		—		—		—		—		335.6		—		(335.6)		—
Other operation and maintenance	1,044.0		306.5		62.5		1,413.0		—		18.7		2.9		(7.1)		1,427.5
Depreciation and amortization	502.7		146.0		24.6		673.3		—		73.4		19.0		(39.1)		726.6
Operating income (loss)	1,053.4		245.6		41.4		1,340.4		—		274.2		(20.1)		(258.9)		1,335.6
Equity in earnings of transmission affiliates	—		—		—		—		132.8		—		—		—		132.8
Interest expense	422.2		47.7		7.4		477.3		14.6		45.4		98.1		(259.6)		375.8


	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
Nine Months Ended
September 30, 2019
External revenues	$	4,226.0	$	977.4	$	302.9	$	5,506.3	$	—	$	65.4	$	3.9	$	—	$	5,575.6
Intersegment revenues	—		—		—		—		—		305.1		—		(305.1)		—
Other operation and maintenance	1,156.8		337.0		73.0		1,566.8		—		14.5		2.1		—		1,583.4
Depreciation and amortization	459.5		135.2		20.0		614.7		—		68.8		18.4		(11.8)		690.1
Operating income (loss)	922.8		205.3		43.9		1,172.0		—		274.3		(17.0)		(261.0)		1,168.3
Equity in earnings of transmission affiliates	—		—		—		—		111.7		—		—		—		111.7
Interest expense	429.0		43.4		6.5		478.9		8.3		46.7		107.5		(267.1)		374.3


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NOTE 21—VARIABLE INTEREST ENTITIES

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

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

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but 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. Therefore, we account for ATC as an equity method investment. At September 30, 2020 and December 31, 2019, our equity investment in ATC was $1,719.1 million and $1,684.7 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a variable interest entity but 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, 2020 and December 31, 2019, our equity investment in ATC Holdco was $31.3 million and $36.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 19, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

Power Purchase Agreement

We have a 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 finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately two years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the power purchase agreement.

We have $15.8 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.

NOTE 22—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.


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The wind generation facilities that are part of our non-utility energy infrastructure segment 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, 2020, including those of our subsidiaries, were approximately $10.9 billion.

Environmental Matters

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

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 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations in April 2018. The following counties within our service territories were designated as partial nonattainment with the 2015 standard: Door, Kenosha, Manitowoc, and Northern Milwaukee/Ozaukee. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. Petitioners in that case have argued that additional portions of Milwaukee, Waukesha, Ozaukee, and Washington Counties (among others) should be designated as nonattainment for ozone. In November 2019, the D.C. Circuit Court of Appeals heard oral arguments for that case. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. We expect that any subsequent EPA re-designation, if necessary, would take place in 2021. The State of Wisconsin submitted the "infrastructure" portion of its state implementation plan outlining how it will implement, maintain, and enforce the 2015 Ozone standard. The plan is subject to EPA review and approval. 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 May 2020, the EPA finalized revisions to the Supplemental Cost Finding for the MATS rule as well as the CAA required RTR. The EPA was required by the United States Supreme Court to 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 final rule, the emission standards and other requirements of the MATS rule first enacted in 2012 remain in place. The EPA did not remove coal- and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also determined that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the rule to have a material impact on our financial condition or results of operations.

Climate Change

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

In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA determined that the BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for


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smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage. The EPA has reviewed comments and intends to take final action on the proposed rule later in 2020.

We have a plan, referred to as our ESG progress plan, which includes the retirement of older, fossil-fueled generation, to be replaced with the construction of zero-carbon emitting renewable generation and clean natural gas-fired generation. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018, which included the March 2019 retirement of the PIPP as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. We expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025. The retirements will contribute to meeting a new, near-term goal of reducing CO2 emissions from our electric generation by 55% below 2005 levels by 2025. In 2019, we met and surpassed our original goal to reduce CO2 emissions by 40% below 2005 levels by 2030. In July 2020, we announced a new goal to reduce CO2 emissions from our electric generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050. In addition to retiring these older, fossil-fueled plants, we expect to invest in low-cost renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning a combination of clean, natural gas-fired generation and zero-carbon-emitting renewable generation facilities.

National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines

Effective in March 2020, the EPA issued a final regulation, The Combustion Turbine Rule. The Combustion Turbine Rule was issued to complete the RTR required by the CAA every five years, and applies only to combustion turbines constructed or reconstructed after January 14, 2003. The Combustion Turbine Rule clarifies certain performance testing, semi-annual and excess emission reporting requirements, implements electronic reporting requirements, and changes certain requirements applicable during startup, shutdown, and malfunction. We have evaluated the rule and do not expect the rule will have a material impact on our financial condition or results of operations.

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 that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental 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.

We have received BTA determinations for OC 5 through OC 8, Weston Units 2, 3, and 4, and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility, which is expected to be in 2021. We anticipate that the permit renewal will include a final BTA determination to address all of the Section 316(b) rule requirements.

As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant additional costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final 2015 ELG rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater. As a result of past capital investments at WE and WPS, we believe our fleet is well positioned to meet the existing ELG regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be modifications to the BATW systems at Weston Unit 3 and OC 7 and OC 8. Also, a wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. Based on preliminary engineering, we estimate that compliance with the current rule will require $60 million in capital costs.

The ELG requirements for BATW and wet FGD systems were being re-evaluated 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


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wastewater requirements while it re-evaluated the ELG rule. The Postponement Rule left unchanged the latest ELG rule compliance date of December 31, 2023. In August 2020, the EPA Administrator signed the ELG Reconsideration Rule to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. This rule is effective December 14, 2020 and includes provisions that:

•Exempt facility owners from the new BATW and wet FGD requirements if a generating unit is retired by December 31, 2028.

•Would limit the investment required to meet these new rule requirements if the coal-fueled unit has a low utilization rate where the 2-year average annual capacity utilization rating is less than 10%.

•Modified the Voluntary Incentives Program to provide the certainty of more time (until December 31, 2028) to implement new requirements if a company adopts additional process changes and controls that achieve more stringent limitations on mercury, arsenic, selenium, nitrate/nitrite, bromide, and total dissolved solids in FGD wastewater.

We are currently evaluating what impact, if any, the rule may have on our estimated compliance cost of $60 million noted above.

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.

We have established the following regulatory assets and reserves for manufactured gas plant sites:


(in millions)	September 30, 2020		December 31, 2019
Regulatory assets	$	696.6	$	685.5
Reserves for future environmental remediation	589.4		589.2

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

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

With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. We are working with the EPA on a closeout process for the Consent Decree.


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Joint Ownership Power Plants – Columbia and Edgewater

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

NOTE 23—SUPPLEMENTAL CASH FLOW INFORMATION


	Nine Months Ended September 30
(in millions)	2020		2019
Cash paid for interest, net of amount capitalized	$	332.4	$	317.9
Cash paid for income taxes, net	27.6		15.4
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	177.8		162.7
Non-cash capital contributions from noncontrolling interest	—		14.6

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of the cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. Our restricted cash also includes the restricted cash we received when WECI 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 any remaining costs associated with the construction of these wind generation facilities. See Note 2, Acquisitions, for more information on the acquisition of Upstream.

The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:


(in millions)	September 30, 2020		December 31, 2019
Cash and cash equivalents	$	13.1	$	37.5

Restricted cash included in other long term assets	48.1		44.8
Cash, cash equivalents, and restricted cash	$	61.2	$	82.3

NOTE 24—REGULATORY ENVIRONMENT

Coronavirus Disease – 2019

The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territories. Each of the states in which our regulated utilities operate declared a public health emergency and issued shelter-in-place orders in response to the COVID-19 pandemic. All of the shelter-in-place orders have since expired or been lifted. The PSCW, the ICC, the MPUC, and the MPSC have all issued written orders requiring certain actions to ensure that essential utility services were, and continue to be, available to customers in their respective jurisdictions. A summary of these orders is included below.


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Wisconsin

On March 24, 2020, the PSCW issued two orders in response to the COVID-19 pandemic. The first order required all public utilities in the state of Wisconsin, including WE, WPS, and WG, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.

In the second order issued on March 24, 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW has affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As WE, WPS, and WG already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for their commercial and industrial customers. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of September 30, 2020, the total amount deferred at our Wisconsin utilities related to the COVID-19 pandemic was $4.6 million.

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

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

Illinois

On March 18, 2020, the ICC issued an order to all Illinois utilities, including PGL and NSG, requiring, among other things, a moratorium on disconnections of utility service and a suspension of late fees and penalties during the declared public health emergency. These provisions applied to all utility customer classes. Illinois utilities were also required to temporarily enact more flexible credit and collections procedures.

On June 18, 2020, the ICC issued a written order approving a settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of the settlement agreement included the following:

•The moratorium on disconnections and the suspension of late fees and penalties were extended until July 26, 2020.

•Customers disconnected after June 18, 2019 could be reconnected without being assessed a reconnection fee if reconnection was requested prior to August 25, 2020.

•Flexible deferred payment arrangements are required to be offered to residential and commercial and industrial customers for an extended period of time and with reduced down payment requirements.

•Deposit requirements were waived until August 25, 2020 for all residential customers, and will be waived for an additional four months for residential customers that verbally express financial hardship.

•PGL and NSG established a bill payment assistance program with approximately $12.0 million and $1.2 million, respectively, available for eligible residential customers to provide relief from high arrearages.

In addition to the above, the settlement agreement authorized PGL and NSG to implement a SPC rider for the recovery of incremental direct costs resulting from COVID-19, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. PGL and NSG began recovering costs under the SPC rider on October 1, 2020. Amounts deferred under the SPC rider are being recovered over 36 months and will be subject to review and reconciliation by the ICC. As of September 30, 2020, PGL and NSG had deferred $18.5 million, collectively, related to the COVID-19 pandemic.


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Subsequent to the approval of the settlement agreement, and at the request of the ICC, PGL and NSG agreed to extend the moratorium on disconnections for qualified low-income residential customers and residential customers expressing financial hardship through March 31, 2021. The annual winter moratorium in Illinois that generally prohibits PGL and NSG from disconnecting residential customers for non-payment begins on December 1 and ends on March 31.

Minnesota

On May 22, 2020, the MPUC issued a written order authorizing Minnesota utilities, including MERC, to track and defer COVID-19 related expenses and certain foregone revenues. The MPUC will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of September 30, 2020, amounts deferred at MERC related to the COVID-19 pandemic were not significant.

On June 18, 2020, the MPUC verbally ordered Minnesota utilities to temporarily suspend disconnections and waive reconnection fees, service deposits, late fees, interest, and penalties for all residential customers. In addition, utilities were required to immediately reconnect residential customers that were previously disconnected. On August 13, 2020, the MPUC issued a written order affirming these temporary provisions. The order will remain in effect until 60 days after Minnesota's declared peacetime emergency expires. Currently, the peacetime order is set to expire on November 12, 2020, meaning the MPUC's order would expire on January 11, 2021; however, the annual winter moratorium in Minnesota that generally prohibits MERC from disconnecting residential customers for non-payment began on October 15, 2020 and does not end until April 15, 2021. The expiration date of Minnesota's peacetime emergency, and the corresponding expiration date of the MPUC order, are subject to change.

Prior to the verbal order issued by the MPUC, MERC had voluntarily taken actions to ensure its customers continued to receive utility services during the pandemic. These actions included, but were not limited to, temporarily suspending disconnections and waiving late payment fees for residential and small commercial and industrial customers that entered into payment plans.

Michigan

On April 15, 2020, the MPSC issued a written order requiring Michigan utilities, including MGU and UMERC, to put certain minimum protections in place during the COVID-19 pandemic. The minimum protections required by the order include the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities are required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19. The order will remain in effect until further notice from the MPSC.

As required in the MPSC order, MGU and UMERC filed responses with the MPSC on April 20, 2020 affirming the actions they are taking to protect customers. The actions being taken by MGU and UMERC provide protections to more customers than required by the MPSC order. These actions include suspending disconnections for all residential customers, waiving deposit requirements for new service, suspending the assessment of late fees for customers that have entered into payment plans, and enhancing payment plan options for all customers.

The April 15, 2020 MPSC order also authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeds the amounts being recovered in rates. On July 23, 2020, the MPSC issued an order denying Michigan utilities' ability to defer additional COVID-19 related expenses and certain foregone revenues. The MPSC indicated that utilities can still seek recovery of these costs and foregone revenues by filing additional information on the specifics of their request by November 2, 2020. MGU and UMERC filed comments with the MPSC on November 2, 2020 indicating that they have not experienced any material additional COVID-19 related expenses or foregone revenues, but that they will continue to monitor these expenses and foregone revenues and will notify the MPSC if they become material. At September 30, 2020, our Michigan utilities had not recorded any deferrals related to the COVID-19 pandemic.

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

2020 and 2021 Rates

In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. In August 2019, all three utilities filed applications 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. In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and


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addressed the remaining outstanding issues that were not included in the settlement agreements. The new rates became effective January 1, 2020. The final orders reflect the following:


	WE					WPS					WG
2020 Effective rate increase (decrease)
Electric (1) (2)	$	15.3	million	/	0.5%	$	15.8	million	/	1.6%	N/A
Gas (3)	$	10.4	million	/	2.8%	$	4.3	million	/	1.4%	$	(1.5)	million	/	(0.2)%
Steam	$	1.9	million	/	8.6%	N/A					N/A

ROE	10.0%					10.0%					10.2%

Common equity component average on a financial basis	52.5%					52.5%					52.5%

(1)Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits are being amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators.

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

(3)The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense will be amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits will be amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

In accordance with its rate order, WE filed an application with the PSCW on July 20, 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related fees. The securitization is expected to reduce the carrying costs for the $100 million, benefiting customers. In its meeting on November 5, 2020, the PSCW verbally approved WE's application without any known material adverse conditions. The terms of this approval are subject to our receipt and review of the final written order from the PSCW, which WE expects to receive by November 17, 2020, the statutory deadline for an order to be issued in this proceeding.

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

All three Wisconsin utilities will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under the new 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. In addition, the rate orders also require WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.

2018 and 2019 Rates

During April 2017, WE, WPS, and WG 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 froze base rates through 2019 for electric, natural gas, and steam customers of WE, WPS, and WG. Based on the PSCW order, the authorized ROE for WE, WPS, and WG remained at 10.2%, 10.0%, and 10.3%, respectively, and the capital cost structure for all of our Wisconsin utilities remained unchanged through 2019.


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In addition to freezing base rates, the settlement agreement extended and expanded the electric real-time market pricing program options for large commercial and industrial customers and mitigated the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE was flowing through the tax benefit of its repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While WE would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate-making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.

The agreement also allowed 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.

Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that had been in place for WE and WG since January 2016, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WPS, or WG earned above its authorized ROE, 50% of the first 50 basis points of additional utility earnings were required to be refunded to customers. All utility earnings above the first 50 basis points were also required to be refunded to customers.

Liquefied Natural Gas Facilities

In November 2019, WE and WG filed a joint application with the PSCW requesting approval for each company to construct its own LNG facility. If approved, each facility would provide one billion cubic feet of natural gas supply to meet peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility. Commercial operation of the LNG facilities is targeted for the end of 2023.

Solar Generation Project

In August 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. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be $130 million. The PSCW issued a written order approving the acquisition of this project in March 2020. Commercial operation of Badger Hollow II is targeted for December 2022.

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

North Shore Gas Company 2021 Rate Case

On October 15, 2020, NSG filed a request with the ICC to increase its natural gas rates. NSG's request is targeting a rate increase of $7.6 million (8.5%) and reflects a 10.0% ROE and a common equity component average of 52.5%. The proposed natural gas rate increase is primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 1, 2015. New rates are expected to be effective in September 2021.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities 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 January 2014, the ICC approved a QIP rider for PGL, which is in effect through 2023.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2020, PGL filed its 2019 reconciliation with the ICC, which, along with the 2018, 2017, and 2016 reconciliations, are still pending.

As of September 30, 2020, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.


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Michigan Gas Utilities Corporation

2021 Rate Application

In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU decided that it would not file a rate case during the COVID-19 pandemic and will re-evaluate the timing of the rate filing at a later date.

In May 2020, MGU filed an application with the MPSC requesting approval to defer $5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case. In July 2020, the MPSC issued a written order approving MGU's request. The deferral of these costs will help to mitigate the impacts from delaying the filing of the rate case.

NOTE 25—NEW ACCOUNTING PRONOUNCEMENTS

Cloud Computing

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements and related disclosures.

Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and OPEB plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the effects of this pronouncement on the notes to our financial statements.

Simplifying the Accounting for Income Taxes

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance will be effective for annual and interim periods beginning after December 15, 2020. We plan to adopt the new standard effective January 1, 2021, and do not expect the adoption to have a material impact on our financial statements and related disclosures.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.


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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our 2019 Annual Report on Form 10-K.

Introduction

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

In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead Wind Energy LLC (Thunderhead), a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska. In January 2020, WECI signed an agreement to acquire an 80% ownership interest in Blooming Grove Wind Energy Center LLC (Blooming Grove), a 250 MW wind generating facility under construction in McLean County, Illinois. In February 2020, WECI agreed to acquire an additional 10% ownership interest in both Thunderhead and Blooming Grove. In July 2020, WECI signed an agreement to acquire an 85% ownership interest in Tatanka Ridge Wind LLC (Tatanka Ridge), a 155 MW wind generating facility under construction in Deuel County, South Dakota. See Note 2, Acquisitions, for more information.

Corporate Strategy

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

Creating a Cleaner Energy Future

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

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

We have already retired more than 1,800 megawatts (MW) of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units. As part of our ESG progress plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025.

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

•800 MW of utility-scale solar;

•600 MW of battery storage;

•100 MW of wind; and

•100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation.


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

We have received approval to invest in 300 MW of utility-scale solar within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to construct two solar projects in Wisconsin. Two Creeks Solar Park (Two Creeks) is located in Manitowoc County, Wisconsin, and the Badger Hollow Solar Park I (Badger Hollow I) is located in Iowa County, Wisconsin. Upon completion, WPS will own 100 MW of each project for a total of 200 MW. The Public Service Commission of Wisconsin (PSCW) approved the acquisition of these two projects in April 2019. Commercial operation was achieved in the first week of November 2020 for Two Creeks, and is targeted for April 2021 for Badger Hollow I. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to construct a solar project, Badger Hollow Solar Park II (Badger Hollow II) that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. The PSCW issued a written order approving the acquisition of this project in March 2020. Commercial operation of Badger Hollow II is targeted for December 2022.

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 generation to WE's portfolio, allowing non-profit and governmental entities, as well as commercial and industrial customers to site utility owned solar arrays on their property. Under this program, in 2019, WE constructed 5 MW of solar generation and is on track to construct more than that in 2020. 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.

We also have a goal to decrease the rate of methane emissions from the natural gas distribution lines in our network by 30% per mile by the year 2030 from a 2011 baseline. We were over half way toward meeting that goal at the end of 2019. In April 2019, we issued a climate report, which analyzes our GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. We will evaluate potential GHG reduction pathways as climate change policies and relevant technologies evolve over time.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with our ESG progress plan, expect 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 and WPS being recognized in 2019 by PA Consulting Group, an independent consulting firm, for superior reliability of their electric delivery networks. This was the ninth consecutive year that We Energies has been named the most reliable utility in the Midwest and the first time WPS has been recognized.

Below are a few examples of reliability projects that are proposed or currently underway.

•WE plans to install approximately 46 miles of natural gas transmission main in southeastern Wisconsin. This project, which was approved in a written order by the PSCW in June 2020, has been designated as the "Lakeshore Lateral Project." The primary purpose of this project is to increase the quantity and reliability of natural gas service, both on a peak day and annually, in southeastern Wisconsin. Construction for the project is tentatively scheduled to begin during the fourth quarter of 2020, and the project is expected to be completed by the end of 2021.

•WE and Wisconsin Gas LLC (WG) each plan to construct their own liquefied natural gas (LNG) facility. Subject to PSCW approval, each facility would provide approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. Commercial operation of the LNG facilities is targeted for the end of 2023.

•The Peoples Gas Light and Coke Company continues to work on its Natural Gas System Modernization Program, which primarily involves replacing old 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


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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 and will continue to do so under the ESG progress plan. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between 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 the resources of all our businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements. We also strive to provide the best value to our customers and shareholders by embracing constructive change, leveraging capabilities and expertise, and using creative solutions to meet or exceed our customers' expectations.

Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.

•See Note 2, Acquisitions, for information about our acquisitions or planned acquisitions of portions of wind energy generation facilities in Illinois, Nebraska, and South Dakota.

•See Note 3, Disposition, for information on the sale of certain WPS Power Development, LLC solar power generation facilities.

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $15.0 billion from 2021 to 2025. Specific projects are discussed in more detail below under Liquidity and Capital Resources.

From 2021 to 2025, we expect capital contributions to ATC to be approximately $45 million. Capital investments at ATC will be funded utilizing these capital contributions, in addition to cash generated by ATC from operations and debt. We currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.1 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 demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

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, 2020

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2020 with the third quarter of 2019, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2020		2019		B (W)		Change Related to 2019 Tax Repairs		Change Related to We Power Lease		Remaining Change B (W)
Wisconsin	$	349.0	$	290.8	$	58.2	$	41.9	$	(1.1)	$	17.4
Illinois	24.5		24.8		(0.3)		—		—		(0.3)
Other states	(2.0)		(2.2)		0.2		—		—		0.2
Non-utility energy infrastructure	91.3		90.3		1.0		—		—		1.0
Corporate and other	(6.9)		(6.0)		(0.9)		—		—		(0.9)
Reconciling eliminations	(85.7)		(86.8)		1.1		—		1.1		—
Total operating income	370.2		310.9		59.3		41.9		—		17.4
Equity in earnings of transmission affiliates	40.1		38.7		1.4		—		—		1.4
Other income, net	25.7		21.8		3.9		—		—		3.9
Interest expense	122.0		125.8		3.8		—		—		3.8
Income before income taxes	314.0		245.6		68.4		41.9		—		26.5
Income tax expense	46.9		11.3		(35.6)		(41.9)		—		6.3
Preferred stock dividends of subsidiary	0.3		0.3		—		—		—		—
Net loss attributed to noncontrolling interests	—		0.3		(0.3)		—		—		(0.3)
Net income attributed to common shareholders	$	266.8	$	234.3	$	32.5	$	—	$	—	$	32.5

Diluted earnings per share	$	0.84	$	0.74	$	0.10

Earnings increased $32.5 million during the third quarter of 2020, compared with the same quarter in 2019. The table above shows the income statement impacts due to the flow through of tax repairs during the third quarter of 2019. WE was flowing through the tax benefit of its repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. As shown in the table above, the changes related to the flow through of tax repairs had no impact on net income attributed to common shareholders. See Note 24, Regulatory Environment, for more information on the flow through of tax repairs.

The significant factors impacting the $32.5 million increase in earnings were:

•A $17.4 million remaining increase in operating income at the Wisconsin segment, driven by a net increase in electric and natural gas margins. Higher residential sales volumes related to favorable weather, the positive impact from collections of fuel and purchased power costs, and the net impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, all contributed to the net increase in margins. The impact from the rate orders includes amounts returned to customers related to the unprotected excess deferred tax benefits from the Tax Legislation. The negative impact on margins from the return of these tax savings to customers was offset by a reduction to income tax expense, and had no impact on net income attributed to common shareholders. Lower operation and maintenance expense, driven by a decrease in electric and natural gas distribution expenses during the third quarter of 2020, also contributed to the remaining increase in operating income at the Wisconsin segment.


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•A $6.3 million remaining decrease in income tax expense, driven by the amortization of the unprotected excess deferred tax benefits from the Tax Legislation in accordance with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, which was offset in operating income at the Wisconsin segment and had no impact on net income attributed to common shareholders. See Note 24, Regulatory Environment, for more information on the Wisconsin rate orders. Wind production tax credits generated by our Coyote Ridge wind farm that achieved commercial operation in December 2019 also contributed to the decrease in income tax expense. These decreases in income tax expense were partially offset by the impact from higher income before income taxes.

•A $3.9 million increase in other income, net, primarily driven by higher net gains on the investments held in the Integrys rabbi trust during the third quarter of 2020. These investment gains partially offset the increase in benefits costs related to deferred compensation, which is included in operating income. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

•A $3.8 million decrease in interest expense, primarily due to lower interest rates on short-term debt during the third quarter of 2020. Also contributing to the decrease was the retirement of long-term debt with higher interest rates than new debt issued since September 30, 2019. These decreases were partially offset by the impact of higher long-term debt balances, primarily related to continued capital investment. See Note 10, Long-Term Debt, for more information.

Non-GAAP Financial Measures

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 useful basis for evaluating utility operations 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 third quarter of 2020 and 2019 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
(in millions)	2020		2019		B (W)
Electric revenues	$	1,215.4	$	1,187.2	$	28.2
Fuel and purchased power	374.0		385.9		11.9
Total electric margins	841.4		801.3		40.1

Natural gas revenues	150.9		152.1		(1.2)
Cost of natural gas sold	67.1		67.5		0.4
Total natural gas margins	83.8		84.6		(0.8)

Total electric and natural gas margins	925.2		885.9		39.3

Other operation and maintenance	363.8		400.2		36.4
Depreciation and amortization	169.7		155.6		(14.1)
Property and revenue taxes	42.7		39.3		(3.4)
Operating income	$	349.0	$	290.8	$	58.2

The following table shows a breakdown of other operation and maintenance:


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Operation and maintenance not included in line items below	$	170.6	$	187.8	$	17.2
Transmission (1)	129.4		105.1		(24.3)
Regulatory amortizations and other pass through expenses (2)	34.5		36.4		1.9
We Power (3)	29.3		36.9		7.6
Transmission expense related to Tax Legislation (4)	—		17.5		17.5
Transmission expense related to the flow through of tax repairs (5)	—		16.5		16.5

Total other operation and maintenance	$	363.8	$	400.2	$	36.4

(1)Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended September 30, 2020 and 2019, $125.0 million and $128.9 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the three months ended September 30, 2020 and 2019, $24.1 million and $26.6 million, respectively, 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.

(4)Represents additional transmission expense recorded in 2019 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. Since WE's transmission regulatory asset was eliminated at December 31, 2019, there were no tax benefits used in 2020.

(5)Represents additional transmission expense recorded in 2019 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. This decrease in expenses was offset in income taxes. Since WE's transmission regulatory asset was eliminated at December 31, 2019, there were no tax benefits used in 2020.


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The following tables provide information on delivered sales volumes by customer class and weather statistics:


	Three Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2020	2019	B (W)
Customer Class
Residential	3,364.4	3,140.1	224.3
Small commercial and industrial (1)	3,409.0	3,495.5	(86.5)
Large commercial and industrial (1)	3,163.5	3,312.4	(148.9)
Other	34.3	36.0	(1.7)
Total retail (1)	9,971.2	9,984.0	(12.8)
Wholesale	843.6	872.2	(28.6)
Resale	1,730.7	1,107.5	623.2
Total sales in MWh (1)	12,545.5	11,963.7	581.8

(1)Includes distribution sales for customers who purchased power from an alternative electric supplier in Michigan.


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2020	2019	B (W)
Customer Class
Residential	64.4	57.7	6.7
Commercial and industrial	55.3	54.6	0.7
Total retail	119.7	112.3	7.4
Transport	264.5	285.7	(21.2)
Total sales in therms	384.2	398.0	(13.8)


	Three Months Ended September 30
	Degree Days
Weather	2020	2019	B (W)
WE and WG (1)
Heating (109 Normal)	103	24	329.2	%
Cooling (565 Normal)	708	649	9.1	%

WPS (2)
Heating (189 Normal)	198	98	102.0	%
Cooling (376 Normal)	471	424	11.1	%

UMERC (3)
Heating (315 Normal)	339	261	29.9	%
Cooling (251 Normal)	311	235	32.3	%

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

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

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


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Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $40.1 million during the third quarter of 2020, compared with the same quarter in 2019. The significant factors impacting the higher electric utility margins were:

•A $25.4 million increase in margins associated with the negative impact of WE's flow through of tax benefits of its repair-related deferred tax liabilities during the third quarter of 2019, in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. These tax benefits were no longer in effect for 2020. This increase in margins was offset in income taxes.

•A $12.6 million increase in margins related to higher residential sales volumes, primarily driven by the impact of favorable weather. As measured by cooling degree days, the third quarter of 2020 was 9.1% and 11.1% warmer than the same quarter in 2019 in the Milwaukee area and Green Bay area, respectively. As measured by heating degree days, the third quarter of 2020 was 329.2% and 102.0% colder than the same quarter in 2019 in the Milwaukee area and Green Bay area, respectively.

•A $10.9 million quarter-over-quarter positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

•A $5.5 million net increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. This increase in margins includes the impact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in income taxes.

These increases in margins were partially offset by an $11.5 million decrease in margins related to other revenues, which included late payment charges and revenues from third party use of our assets.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $0.8 million during the third quarter of 2020, compared with the same quarter in 2019. The most significant factor impacting the lower natural gas utility margins was a $2.7 million decrease related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. This decrease in margins includes the impact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in income taxes. This decrease was partially offset by a $1.1 million increase in margins from higher sales volumes, driven by an increase in heating degree days during the third quarter of 2020, compared to the same quarter in 2019.

Operating Income

Operating income at the Wisconsin segment increased $58.2 million during the third quarter of 2020, compared with the same quarter in 2019. This increase was driven by the $39.3 million net increase in margins discussed above and $18.9 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes).

The significant factors impacting the decrease in operating expenses during the third quarter of 2020, compared with the same quarter in 2019, were:

•An $18.1 million decrease in electric and natural gas distribution expenses, driven by lower maintenance and storm restoration expense, as well as our focus on operating efficiency.

•A $17.5 million decrease in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset by a corresponding decrease in margins.

•A $16.5 million decrease in transmission expense related to the flow through of tax repairs during the third quarter of 2019, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes.


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•A $7.6 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

These decreases in operating expenses were partially offset by:

•A $24.3 million increase in transmission expense as approved in the PSCW's 2019 rate orders, which were effective January 1, 2020. See the notes under the other operation and maintenance table above for more information.

•A $14.1 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan as well as an increase related to the We Power leases.

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)	2020		2019		B (W)
Natural gas revenues	$	221.9	$	198.0	$	23.9
Cost of natural gas sold	32.3		20.3		(12.0)
Total natural gas margins	189.6		177.7		11.9

Other operation and maintenance	109.2		101.8		(7.4)
Depreciation and amortization	49.9		45.7		(4.2)
Property and revenue taxes	6.0		5.4		(0.6)
Operating income	$	24.5	$	24.8	$	(0.3)

The following table shows a breakdown of other operation and maintenance:


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Operation and maintenance not included in the line items below	$	92.6	$	89.9	$	(2.7)
Riders (1)	17.2		12.3		(4.9)
Regulatory amortizations (1)	(0.6)		(0.4)		0.2

Total other operation and maintenance	$	109.2	$	101.8	$	(7.4)

(1)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 delivered sales volumes by customer class and weather statistics:


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2020	2019	B (W)
Customer Class
Residential	45.9	42.4	3.5
Commercial and industrial	23.0	23.8	(0.8)
Total retail	68.9	66.2	2.7
Transport	86.1	98.0	(11.9)
Total sales in therms	155.0	164.2	(9.2)


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	Three Months Ended September 30
	Degree Days
Weather (1)	2020	2019	B (W)
Heating (72 Normal)	62	13	376.9	%

(1)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 $4.9 million impact of the riders referenced in the table above, increased $7.0 million during the third quarter of 2020, compared with the same quarter in 2019. The increase in margins was primarily driven by higher revenues at PGL due to continued capital investment in the SMP project. 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 24, Regulatory Environment, for more information.

Operating Income

Operating income at the Illinois segment decreased $0.3 million during the third quarter of 2020, compared with the same quarter in 2019. This decrease was driven by $7.3 million of higher 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, and which was substantially offset by the $7.0 million net increase in margins discussed above.

The significant factors impacting the increase in operating expenses during the third quarter of 2020, compared with the same quarter in 2019, were:

•A $4.7 million increase in natural gas distribution maintenance costs, primarily due to the timing of performing certain services.

•A $4.2 million increase in depreciation expense, primarily driven by PGL'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)	2020		2019		B (W)
Natural gas revenues	$	48.3	$	48.9	$	(0.6)
Cost of natural gas sold	16.9		18.0		1.1
Total natural gas margins	31.4		30.9		0.5

Other operation and maintenance	20.4		22.0		1.6
Depreciation and amortization	8.5		6.8		(1.7)
Property and revenue taxes	4.5		4.3		(0.2)
Operating loss	$	(2.0)	$	(2.2)	$	0.2


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The following table shows a breakdown of other operation and maintenance:


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Operation and maintenance not included in line items below	$	16.4	$	18.4	$	2.0
Regulatory amortizations and other pass through expenses (1)	4.0		3.3		(0.7)
Other	—		0.3		0.3
Total other operation and maintenance	$	20.4	$	22.0	$	1.6

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

The following tables provide information on delivered sales volumes by customer class and weather statistics:


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2020	2019	B (W)
Customer Class
Residential	14.7	15.7	(1.0)
Commercial and industrial	14.5	13.1	1.4
Total retail	29.2	28.8	0.4
Transport	146.8	172.7	(25.9)
Total sales in therms	176.0	201.5	(25.5)


	Three Months Ended September 30
	Degree Days
Weather (1)	2020	2019	B (W)
MERC
Heating (214 Normal)	243	159	52.8	%

MGU
Heating (112 Normal)	131	26	403.8	%

(1)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 $0.5 million during the third quarter of 2020, compared to the same quarter in 2019.

Operating Loss

The operating loss at the other states segment decreased $0.2 million during the third quarter of 2020, compared to the same quarter in 2019. This decrease was driven by the $0.5 million increase in margins, partially offset by a $0.3 million increase in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes). The increase in operating expenses was driven by an increase in depreciation and amortization, partially offset by effective cost control.

Non-Utility Energy Infrastructure Segment Contribution to Operating Income


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Operating income	$	91.3	$	90.3	$	1.0


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Corporate and Other Segment Contribution to Operating Income


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Operating loss	$	(6.9)	$	(6.0)	$	(0.9)

Electric Transmission Segment Operations


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Equity in earnings of transmission affiliates	$	40.1	$	38.7	$	1.4

Earnings from our ownership interests in transmission affiliates increased $1.4 million during the third quarter of 2020, compared with the same quarter in 2019, primarily driven by continued capital investment by ATC.

Consolidated Other Income, Net


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Gains from investments held in rabbi trust	$	6.0	$	1.4	$	4.6
AFUDC – Equity	6.0		3.3		2.7
Non-service components of net periodic benefit costs	11.8		9.6		2.2
Other, net	1.9		7.5		(5.6)
Other income, net	$	25.7	$	21.8	$	3.9

Other income, net increased $3.9 million during the third quarter of 2020, compared with the same quarter in 2019. The increase was primarily driven by higher net gains on the investments held in the Integrys rabbi trust during the third quarter of 2020. These investment gains partially offset the increase in benefits costs related to deferred compensation, which is included in operating income. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. Also contributing to the increase were both higher AFUDC–Equity, due to continued capital investment, and higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our pension and OPEB costs. Theses increases in other income, net were partially offset by the 2019 deferral of costs that were offset in other income statement line items and had no impact on net income.

Consolidated Interest Expense


	Three Months Ended September 30
(in millions)	2020		2019		B (W)
Interest expense	$	122.0	$	125.8	$	3.8

Interest expense decreased $3.8 million during the third quarter of 2020, compared with the same quarter in 2019, primarily due to lower interest rates on short-term debt. Also contributing to the decrease was the retirement of long-term debt with higher interest rates than new debt issued since September 30, 2019. These decreases were partially offset by the impact of higher long-term debt balances, primarily related to continued capital investment. See Note 10, Long-Term Debt, for more information.

Consolidated Income Tax Expense


	Three Months Ended September 30
	2020		2019		B (W)
Effective tax rate	14.9	%	4.6	%	(10.3)	%

Our effective tax rate increased by 10.3% during the third quarter of 2020, compared with the same quarter in 2019. The increase was primarily due to the benefit from the flow through of tax repairs during the third quarter of 2019, in connection with the 2017 Wisconsin rate settlement. This item was partially offset by the 2020 amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, as well as wind production tax credits generated by our Coyote Ridge wind farm that achieved commercial operation in December 2019. The


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impacts due to the benefit from the flow through of tax repairs and the amortization of the unprotected excess deferred tax benefits from the Tax Legislation were offset in operating income at the Wisconsin segment. See Note 13, Income Taxes, and Note 24, Regulatory Environment, for more information.

NINE MONTHS ENDED SEPTEMBER 30, 2020

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2020 with the nine months ended September 30, 2019, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2020		2019		B (W)		Change Related to 2019 Tax Repairs		Change Related to We Power Lease		Remaining Change B (W)
Wisconsin	$	1,053.4	$	922.8	$	130.6	$	124.6	$	(2.1)	$	8.1
Illinois	245.6		205.3		40.3		—		—		40.3
Other states	41.4		43.9		(2.5)		—		—		(2.5)
Non-utility energy infrastructure	274.2		274.3		(0.1)		—		—		(0.1)
Corporate and other	(20.1)		(17.0)		(3.1)		—		—		(3.1)
Reconciling eliminations	(258.9)		(261.0)		2.1		—		2.1		—
Total operating income	1,335.6		1,168.3		167.3		124.6		—		42.7
Equity in earnings of transmission affiliates	132.8		111.7		21.1		—		—		21.1
Other income, net	59.9		76.3		(16.4)		—		—		(16.4)
Interest expense	375.8		374.3		(1.5)		—		—		(1.5)
Income before income taxes	1,152.5		982.0		170.5		124.6		—		45.9
Income tax expense	190.7		91.5		(99.2)		(124.6)		—		25.4
Preferred stock dividends of subsidiary	0.9		0.9		—		—		—		—
Net loss attributed to noncontrolling interests	—		0.5		(0.5)		—		—		(0.5)
Net income attributed to common shareholders	$	960.9	$	890.1	$	70.8	$	—	$	—	$	70.8

Diluted Earnings Per Share	$	3.04	$	2.81	$	0.23

Earnings increased $70.8 million during the nine months ended September 30, 2020, compared with the same period in 2019. The table above shows the income statement impacts due to the flow through of tax repairs during the first nine months of 2019. WE was flowing through the tax benefit of its repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. As shown in the table above, the changes related to the flow through of tax repairs had no impact on net income attributed to common shareholders.

The significant factors impacting the $70.8 million increase in earnings were:

•A $40.3 million increase in operating income at the Illinois segment, driven by higher natural gas margins at PGL, due to continued capital investment in the SMP project under its QIP rider, and lower operating expenses during the nine months ended September 30, 2020. A decrease in natural gas distribution maintenance costs, which reflects the benefit of warmer than normal winter weather in 2020 and the timing of performing certain services, drove the lower operating expenses.

•A $25.4 million remaining decrease in income tax expense, driven by the amortization of the unprotected excess deferred tax benefits from the Tax Legislation in accordance with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, which was offset in operating income at the Wisconsin segment and had no impact on net income attributed to common shareholders. Wind production tax credits generated by our Coyote Ridge wind farm that achieved commercial operation in December 2019 also contributed to the decrease in income tax expense. These decreases in income tax expense were partially offset by the impact from higher income before income taxes.


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•A $21.1 million increase in earnings from our ownership interests in transmission affiliates, primarily due to an increase in the base ROE that ATC is allowed to collect as a result of a FERC order issued in May 2020, which was retroactive to November 2013. For more information on the ROE increase, see Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints. Continued capital investment by ATC also contributed to the increase in earnings from our ownership interests in transmission affiliates.

•An $8.1 million remaining increase in operating income at the Wisconsin segment. The increase was primarily due to lower operation and maintenance expense, driven by a decrease in electric and natural gas distribution expenses and lower benefits costs. A net increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, and the positive impact from collections of fuel and purchased power costs also contributed to the increase in operating income. The increase in margins from the Wisconsin rate orders is net of the amounts returned to customers related to the unprotected excess deferred tax benefits from the Tax Legislation. The negative impact on margins from the return of these tax savings to customers was offset by the reduction to income tax expense discussed above, and had no impact on net income attributed to common shareholders. These increases in operating income were partially offset by the negative impact on margins from lower overall sales volumes, primarily due to impacts from the COVID-19 pandemic, and an increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

These increases in earnings were partially offset by a $16.4 million decrease in other income, net, primarily driven by the impact from the 2019 deferral of costs that were offset in other income statement line items and had no impact on net income. Also contributing to the decrease were lower net gains on the investments held in the Integrys rabbi trust during the nine months ended September 30, 2020. The decrease related to the investments held in the rabbi trust partially offsets lower benefits costs related to deferred compensation, which are included in operating income.

Non-GAAP Financial Measures

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, 2020 and 2019 for each of our segments is presented in the “Consolidated Earnings” table above.


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Wisconsin Segment Contribution to Operating Income


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Electric revenues	$	3,251.9	$	3,278.2	$	(26.3)
Fuel and purchased power	957.2		1,035.4		78.2
Total electric margins	2,294.7		2,242.8		51.9

Natural gas revenues	819.5		947.8		(128.3)
Cost of natural gas sold	395.2		536.5		141.3
Total natural gas margins	424.3		411.3		13.0

Total electric and natural gas margins	2,719.0		2,654.1		64.9

Other operation and maintenance	1,044.0		1,156.8		112.8
Depreciation and amortization	502.7		459.5		(43.2)
Property and revenue taxes	118.9		115.0		(3.9)
Operating income	$	1,053.4	$	922.8	$	130.6

The following table shows a breakdown of other operation and maintenance:


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Operation and maintenance not included in line items below	$	462.5	$	518.8	$	56.3
Transmission (1)	388.2		314.5		(73.7)
Regulatory amortizations and other pass through expenses (2)	103.8		118.0		14.2
We Power (3)	89.5		107.0		17.5
Transmission expense related to Tax Legislation (4)	—		50.2		50.2
Transmission expense related to the flow through of tax repairs (5)	—		48.3		48.3

Total other operation and maintenance	$	1,044.0	$	1,156.8	$	112.8

(1)Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the nine months ended September 30, 2020 and 2019, $359.7 million and $367.0 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the nine months ended September 30, 2020 and 2019, $84.7 million and $103.0 million, respectively, 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.

(5)Represents additional transmission expense recorded in 2019 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. This decrease in expenses was offset in income taxes. Since WE's transmission asset was eliminated at December 31, 2019, there were no tax benefits used in 2020.


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The following tables provide information on delivered sales volumes by customer class and weather statistics:


	Nine Months Ended September 30
	MWh (in thousands)
Electric Sales Volumes	2020	2019	B (W)
Customer Class
Residential	8,782.2	8,287.6	494.6
Small commercial and industrial (1)	9,299.0	9,731.4	(432.4)
Large commercial and industrial (1)	8,734.3	9,554.3	(820.0)
Other	113.0	120.2	(7.2)
Total retail (1)	26,928.5	27,693.5	(765.0)
Wholesale	2,311.4	2,536.7	(225.3)
Resale	5,152.6	4,252.2	900.4
Total sales in MWh (1)	34,392.5	34,482.4	(89.9)

(1)Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2020	2019	B (W)
Customer Class
Residential	734.2	804.9	(70.7)
Commercial and industrial	445.9	500.8	(54.9)
Total retail	1,180.1	1,305.7	(125.6)
Transport	979.9	1,037.8	(57.9)
Total sales in therms	2,160.0	2,343.5	(183.5)


	Nine Months Ended September 30
	Degree Days
Weather	2020	2019	B (W)
WE and WG (1)
Heating (4,354 Normal)	4,023	4,480	(10.2)	%
Cooling (726 Normal)	931	725	28.4	%

WPS (2)
Heating (4,854 Normal)	4,644	4,979	(6.7)	%
Cooling (509 Normal)	656	502	30.7	%

UMERC (3)
Heating (5,525 Normal)	5,337	5,898	(9.5)	%
Cooling (328 Normal)	425	284	49.6	%

(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 increased $51.9 million during the nine months ended September 30, 2020, compared with the same period in 2019. The significant factors impacting the higher electric utility margins were:

•A $76.3 million increase in margins associated with the negative impact of WE's flow through of tax benefits of its repair-related deferred tax liabilities during the nine months ended September 30, 2019, in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. These tax benefits were no longer in effect for 2020. This increase in margins was offset in income taxes.

•An $11.8 million period-over-period positive impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

These increases in margins were partially offset by:

•A $20.4 million decrease in margins related to other revenues, which included late payment charges and revenues from third party use of our assets.

•A $10.0 million net decrease in margins related to lower retail sales volumes, including the impact of weather. We recognized a $30.2 million net reduction in margins related to lower retail sales volumes driven by the COVID-19 pandemic. Sales volumes for our commercial and industrial customers decreased, primarily related to business interruptions and closings, while residential sales volumes increased. These changes in volumes were both driven, in large part, by a shelter-in-place order issued by the state of Wisconsin during the COVID-19 pandemic. This net decrease in margins was partially offset by a $20.2 million increase in margins related to favorable weather. As measured by cooling degree days, the nine months ended September 30, 2020 were 28.4% and 30.7% warmer than the same period in 2019 in the Milwaukee area and Green Bay area, respectively.

•A $6.6 million net decrease in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. This decrease in margins includes the impact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in income taxes.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $13.0 million during the nine months ended September 30, 2020, compared with the same period in 2019. The most significant factor impacting the higher natural gas utility margins was a $34.1 million increase related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. This increase in margins includes the impact related to the Tax Legislation, including unprotected tax benefits, which we agreed to return to customers and is offset in income taxes.

This increase in margins was partially offset by a $23.8 million net reduction in margins related to lower sales volumes, driven primarily by warmer winter weather during 2020. As measured by heating degree days, the nine months ended September 30, 2020 were 10.2% and 6.7% warmer than the same period in 2019 in the Milwaukee area and Green Bay area, respectively. In addition to the weather impact, the decrease in sales volumes for our commercial and industrial customers was also driven by business interruptions and closings related to, in large part, a shelter-in-place order issued by the state of Wisconsin during the COVID-19 pandemic.

Operating Income

Operating income at the Wisconsin segment increased $130.6 million during the nine months ended September 30, 2020, compared with the same period in 2019. This increase was driven by $65.7 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), and the $64.9 million increase in margins discussed above.


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

•A $50.2 million decrease in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset by a corresponding decrease in margins.

•A $48.3 million decrease in transmission expense related to the flow through of tax repairs during 2019, as discussed in the notes under the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes.

•A $32.4 million decrease in electric and natural gas distribution expenses, driven by lower maintenance and storm restoration expense, as well as our focus on operating efficiency.

•A $20.6 million decrease in benefit costs, primarily due to lower deferred compensation costs, stock-based compensation, and medical costs.

•A $17.5 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

•A $14.2 million decrease in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

These decreases in operating expenses were partially offset by:

•A $73.7 million increase in transmission expense as approved in the PSCW's 2019 rate orders, which were effective January 1, 2020. See the notes under the other operation and maintenance table above for more information.

•A $43.2 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan as well as an increase related to the We Power leases.

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
(in millions)	2020		2019		B (W)
Natural gas revenues	$	930.7	$	977.4	$	(46.7)
Cost of natural gas sold	212.2		282.9		70.7
Total natural gas margins	718.5		694.5		24.0

Other operation and maintenance	306.5		337.0		30.5
Depreciation and amortization	146.0		135.2		(10.8)
Property and revenue taxes	20.4		17.0		(3.4)
Operating income	$	245.6	$	205.3	$	40.3


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The following table shows a breakdown of other operation and maintenance:


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Operation and maintenance not included in the line items below	$	237.2	$	269.4	$	32.2
Riders (1)	71.3		68.4		(2.9)
Regulatory amortizations (1)	(2.0)		(1.1)		0.9
Other	—		0.3		0.3
Total other operation and maintenance	$	306.5	$	337.0	$	30.5

(1)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 delivered sales volumes by customer class and weather statistics:


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2020	2019	B (W)
Customer Class
Residential	566.8	618.1	(51.3)
Commercial and industrial	227.5	256.1	(28.6)
Total retail	794.3	874.2	(79.9)
Transport	552.0	626.9	(74.9)
Total sales in therms	1,346.3	1,501.1	(154.8)


	Nine Months Ended September 30
	Degree Days
Weather (1)	2020	2019	B (W)
Heating (4,012 Normal)	3,627	4,171	(13.0)	%

(1)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 $2.9 million impact of the riders referenced in the table above, increased $21.1 million during the nine months ended September 30, 2020, compared with the same period in 2019. The increase in margins was primarily driven by higher revenues at PGL due to continued capital investment in the SMP project. 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 24, Regulatory Environment, for more information.

Operating Income

Operating income at the Illinois segment increased $40.3 million during the nine months ended September 30, 2020, compared with the same period in 2019. This increase was driven by $19.2 million of lower 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, as well as the $21.1 million net increase in margins discussed above.

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

•A $22.2 million decrease in natural gas distribution maintenance costs, which reflects the benefit of warmer than normal winter weather in 2020 and the timing of performing certain services.

•A $5.6 million decrease in customer service expenses, primarily due to lower call volumes and metering costs.


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•A $3.8 million decrease in benefit costs, primarily due to lower deferred compensation costs, pension settlement costs, and stock-based compensation.

These decreases in operating expenses were partially offset by a $10.8 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

Other States Segment Contribution to Operating Income

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.


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Natural gas revenues	$	261.4	$	302.9	$	(41.5)
Cost of natural gas sold	119.9		153.4		33.5
Total natural gas margins	141.5		149.5		(8.0)

Other operation and maintenance	62.5		73.0		10.5
Depreciation and amortization	24.6		20.0		(4.6)
Property and revenue taxes	13.0		12.6		(0.4)
Operating income	$	41.4	$	43.9	$	(2.5)

The following table shows a breakdown of other operation and maintenance:


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Operation and maintenance not included in line items below	$	49.9	$	56.1	$	6.2
Regulatory amortizations and other pass through expenses (1)	12.6		16.6		4.0
Other	—		0.3		0.3
Total other operation and maintenance	$	62.5	$	73.0	$	10.5

(1)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
	Therms (in millions)
Natural Gas Sales Volumes	2020	2019	B (W)
Customer Class
Residential	210.1	235.5	(25.4)
Commercial and industrial	131.6	157.2	(25.6)
Total retail	341.7	392.7	(51.0)
Transport	529.4	576.2	(46.8)
Total sales in therms	871.1	968.9	(97.8)


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	Nine Months Ended September 30
	Degree Days
Weather (1)	2020	2019	B (W)
MERC
Heating (5,157 Normal)	5,029	5,615	(10.4)	%

MGU
Heating (4,101 Normal)	3,897	4,129	(5.6)	%

Natural Gas Utility Margins

Natural gas utility margins decreased $8.0 million during the nine months ended September 30, 2020, compared with the same period in 2019. The decrease was primarily driven by lower sales volumes as a result of warmer than normal winter weather in 2020 and the COVID-19 driven stay-at-home orders issued in March, partially offset by an increase in revenues related to MERC's GUIC rider. The GUIC rider allows MERC to recover previously approved GUIC 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 Income

Operating income at the other states segment decreased $2.5 million during the nine months ended September 30, 2020, compared with the same period in 2019. The decrease was driven by the $8.0 million decrease in margins discussed above, partially offset by a $5.5 million decrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes). The decrease in operating expenses was driven by effective cost control, partially offset by an increase in depreciation and amortization.

Non-Utility Energy Infrastructure Segment Contribution to Operating Income


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Operating income	$	274.2	$	274.3	$	(0.1)

Corporate and Other Segment Contribution to Operating Income


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Operating loss	$	(20.1)	$	(17.0)	$	(3.1)

Electric Transmission Segment Operations


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Equity in earnings of transmission affiliates	$	132.8	$	111.7	$	21.1

Earnings from our ownership interests in transmission affiliates increased $21.1 million during the nine months ended September 30, 2020, compared with the same period in 2019, primarily due to an increase in the base ROE that ATC is allowed to collect as a result of a FERC order issued in May 2020, retroactive to November 2013. For further discussion of the ROE increase, see Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints. Also contributing to the increase in earnings from our ownership interests in transmission affiliates was continued capital investment by ATC.


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Consolidated Other Income, Net


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Gains from investments held in rabbi trust	$	4.4	$	14.0	$	(9.6)
Non-service components of net periodic benefit costs	36.7		27.5		9.2
AFUDC – Equity	14.7		10.6		4.1
Other, net	4.1		24.2		(20.1)
Other income, net	$	59.9	$	76.3	$	(16.4)

Other income, net decreased $16.4 million during the nine months ended September 30, 2020, compared with the same period in 2019. The decrease was primarily driven by the impact from the 2019 deferral of costs that were offset in other income statement line items and had no impact on net income. Also contributing to the decrease were lower net gains on the investments held in the Integrys rabbi trust during the nine months ended September 30, 2020. The decrease related to the investments held in the rabbi trust partially offsets lower benefits costs related to deferred compensation, which are included in operating income. Higher net credits from the non-service components of our net periodic pension and OPEB costs and higher AFUDC–Equity due to continued capital investment partially offset these decreases in other income, net.

Consolidated Interest Expense


	Nine Months Ended September 30
(in millions)	2020		2019		B (W)
Interest expense	$	375.8	$	374.3	$	(1.5)

Interest expense increased $1.5 million during the nine months ended September 30, 2020, compared with the same period in 2019, primarily due to higher long-term debt balances, partially offset by lower interest rates on short-term debt. The increase in long-term debt balances was primarily related to continued capital investment.

Consolidated Income Tax Expense


	Nine Months Ended September 30
	2020		2019		B (W)
Effective tax rate	16.5	%	9.3	%	(7.2)	%

Our effective tax rate increased by 7.2% during the nine months ended September 30, 2020, compared with the same period in 2019. The increase was primarily due to the benefit from the flow through of tax repairs during the nine months ended September 30, 2019, in connection with the 2017 Wisconsin rate settlement. This increase in our effective tax rate was partially offset by the 2020 amortization of the unprotected excess deferred tax benefits from the Tax Legislation in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020, as well as wind production tax credits generated by our Coyote Ridge wind farm that achieved commercial operation in December 2019. The impacts due to the benefit from the flow through of tax repairs and the amortization of the unprotected excess deferred tax benefits from the Tax Legislation were offset in operating income at the Wisconsin segment.

We expect our 2020 annual effective tax rate to be between 16% and 17%, which includes an estimated 4% effective tax rate benefit due to the amortization of unprotected excess deferred taxes in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2020. Excluding this estimated effective tax rate benefit, the expected 2020 range would be between 20% and 21%.


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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the nine months ended September 30:


(in millions)	2020		2019		Change in 2020 Over 2019
Cash provided by (used in):
Operating activities	$	1,949.7	$	1,840.7	$	109.0
Investing activities	(1,563.1)		(1,734.5)		171.4
Financing activities	(407.7)		(185.7)		(222.0)

Operating Activities

Net cash provided by operating activities increased $109.0 million during the nine months ended September 30, 2020, compared with the same period in 2019, driven by higher cash earnings, partially offset by higher working capital requirements, including COVID-19 impacts.

The significant factors impacting the increase in net cash provided by operating activities include:

•A $92.4 million increase in cash related to lower payments for fuel and purchased power at our plants during the nine months ended September 30, 2020, compared with the same period in 2019. Our payments for fuel and purchased power decreased due to lower natural gas costs used to fuel our plants. The average per-unit cost of natural gas sold decreased 17.2% during the nine months ended September 30, 2020, compared with the same period in 2019. Lower fuel and purchased power costs were also driven by the retirement of PIPP in March 2019.

•A $47.8 million increase in cash due to lower collateral requirements, driven by an increase in the fair value of our natural gas derivative assets during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $42.5 million increase in cash from lower payments for other operation and maintenance expenses. During the nine months ended September 30, 2020, our payments were lower for electric and natural gas distribution and maintenance costs, benefits, and transmission, compared with the same period in 2019.

•An $18.6 million increase in cash due to higher distributions from our transmission affiliate during the nine months ended September 30, 2020, compared with the same period in 2019.

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

•A $57.5 million decrease in cash related to lower overall collections from customers, primarily due to a moratorium on disconnections causing an increase in past due balances and business interruptions and closings during the COVID-19 pandemic, as well as lower sales volumes driven by warmer winter weather, for the nine months ended September 30, 2020, compared with the same period in 2019.

•A $14.5 million decrease in cash related to an increase in payments for interest related to higher long-term debt balances during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $12.2 million decrease in cash related to an increase in cash paid for income taxes during the nine months ended September 30, 2020, compared with the same period in 2019. This increase in cash paid for income taxes was primarily due to higher levels of taxable income in 2020.


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Investing Activities

Net cash used in investing activities decreased $171.4 million during the nine months ended September 30, 2020, compared with the same period in 2019, 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 $22.2 million increase in cash related to insurance proceeds received for property damage during the nine months ended September 30, 2020.

•A $22.1 million increase in cash related to lower capital contributions paid to our transmission affiliates during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $16.9 million increase in proceeds from the sale of investments held in the Integrys rabbi trust during the nine months ended September 30, 2020, compared with the same period in 2019.

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

•A $107.2 million increase in cash paid for capital expenditures during the nine months ended September 30, 2020, compared with the same period in 2019, which is discussed in more detail below.

•A $32.4 million decrease in cash related to a reimbursement from ATC for construction costs during the nine months ended September 30, 2019. See Note 19, Investment in Transmission Affiliates, for more information.

•A $22.4 million decrease in proceeds from the sale of assets during the nine months ended September 30, 2020, compared with the same period in 2019.

Capital Expenditures

Capital expenditures by segment for the nine months ended September 30 were as follows:


Reportable Segment (in millions)	2020		2019		Change in 2020 Over 2019
Wisconsin	$	992.7	$	968.2	$	24.5
Illinois	494.7		423.6		71.1
Other states	104.7		79.0		25.7
Non-utility energy infrastructure	12.7		30.2		(17.5)
Corporate and other	13.9		10.5		3.4
Total capital expenditures	$	1,618.7	$	1,511.5	$	107.2

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2020, compared with the same period in 2019, was primarily driven by upgrades to the electric distribution system and capital expenditures related to Badger Hollow I and II during the nine months ended September 30, 2020. These increases in cash paid for capital expenditures were partially offset by a decrease in cash paid for capital expenditures during the nine months ended September 30, 2020 for capital expenditures related to Two Creeks, construction of the new natural gas-fired generation facility in the Upper Peninsula of Michigan, which became commercially operational on March 31, 2019, and upgrades to the natural gas distribution system.

The increase in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2020, compared with the same period in 2019, was driven by an increase in facilities projects, upgrading of automated meter reading devices, a higher number of meter replacements, and dehydration system upgrades at the Manlove Gas Storage Field during the nine months ended September 30, 2020.

The increase in cash paid for capital expenditures at the other states segment during the nine months ended September 30, 2020, compared with the same period in 2019, was primarily driven by the installation of automated meter reading devices and a higher number of meter replacements during the nine months ended September 30, 2020.


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The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2020, compared with the same period in 2019, was primarily driven by projects completed at the ERGS during the nine months ended September 30, 2019.

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

Financing Activities

Net cash used in financing activities increased $222.0 million during the nine months ended September 30, 2020, compared with the same period in 2019, driven by:

•A $510.0 million decrease in cash due to lower issuances of long-term debt during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $376.6 million decrease in cash due to higher repayments of long-term debt during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $42.8 million decrease in cash from stock options exercised during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $40.1 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2020, compared with the same period in 2019. In January 2020, our Board of Directors increased our quarterly dividend by $0.0425 per share (7.2%) effective with the March 2020 dividend payment.

•The acquisition of an additional 10% ownership interest in Upstream in April 2020 for $31.0 million. See Note 2, Acquisitions, for more information.

These decreases in cash were partially offset by:

•A $353.9 million increase in cash which resulted from lower net repayments of commercial paper during the nine months ended September 30, 2020, compared with the same period in 2019.

•A $340.0 million increase in cash due to the issuance of a 364-day term loan during the nine months ended September 30, 2020, to enhance our liquidity position in response to the COVID-19 pandemic. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information.

•An $81.5 million increase in cash due to a decrease in the number and cost of shares of our common stock purchased during the nine months ended September 30, 2020, compared with the same period in 2019, to satisfy requirements of our stock-based compensation plans.

Significant Financing Activities

For more information on our financing activities, see Note 9, Short-Term Debt and Lines of Credit, and Note 10, 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.


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We currently have access to the capital markets and have been able to generate funds both 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. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information on the impacts of the COVID-19 pandemic.

WEC Energy Group, WE, WPS, WG, 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. In March 2020, in order to enhance our liquidity position in response to the COVID-19 pandemic and the ensuing volatility in the commercial paper market, WEC Energy Group entered into a $340 million 364-day term loan, which was used to pay down commercial paper. See Note 9, Short-Term Debt and Lines of Credit, for more information about these credit agreements.

The following table shows our capitalization structure as of September 30, 2020, 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
Common shareholders' equity	$	10,450.7		$	10,700.7
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	12,248.7			11,998.7
Short-term debt	771.0			771.0
Total capitalization	$	23,500.8		$	23,500.8

Total debt	$	13,019.7		$	12,769.7

Ratio of debt to total capitalization	55.4		%	54.3		%

Included in long-term debt on our balance sheet as of September 30, 2020, 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 to reflect the treatment of the 2007 Junior Notes by the majority of rating agencies. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Working Capital

As of September 30, 2020, our current liabilities exceeded our current assets by $1.1 billion. 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, a division of S&P Global Inc., and/or Baa3 at Moody's Investors Service, Inc. 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.


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

If we are unable to successfully take actions to manage any impacts from the COVID-19 pandemic and/or any additional adverse impacts of the Tax Legislation as a result of additional interpretations, regulations, amendments or technical corrections, these potential impacts could result in credit rating agencies placing our 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.

See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information.

Capital Requirements

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, impacts from the Tax Legislation, additional changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, and the COVID-19 pandemic. Our estimated capital expenditures and acquisitions for the next three years are as follows:


(in millions)	2020		2021		2022
Wisconsin	$	1,399.8	$	1,763.4	$	1,844.6
Illinois	706.6		573.9		581.8
Other states	154.6		98.4		106.8
Non-utility energy infrastructure	689.8		640.0		504.9
Corporate and other	22.7		17.1		10.1
Total	$	2,973.5	$	3,092.8	$	3,048.2

WE, WPS, and WG continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include the AMI program. AMI is an integrated system of smart meters, communication networks, and data management systems that enable two-way communication between utilities and customers. WPS is also continuing work on the System Modernization and Reliability Project. 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 $100 million between 2020 and 2022 on this project.

We are committed to investing in solar, wind, and battery storage. As part of this commitment, we have received approval to invest in 300 MW of utility-scale solar within our Wisconsin segment. WPS has partnered with an unaffiliated utility to construct two solar projects in Wisconsin. Two Creeks is located in Manitowoc County, Wisconsin, and Badger Hollow I is located in Iowa County, Wisconsin. Upon completion, WPS will own 100 MW of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be approximately $260 million. Commercial operation was achieved in the first week of November 2020 for Two Creeks, and is targeted for April 2021 for Badger Hollow I. WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be $130 million. Commercial operation of Badger Hollow II is targeted for December 2022.

WE plans to install approximately 46 miles of natural gas transmission main in southeastern Wisconsin. This project, which was approved in a written order by the PSCW in June 2020, has been designated as the "Lakeshore Lateral Project." The primary purpose of this project is to increase the quantity and reliability of natural gas service, both on a peak day and annually, in southeastern Wisconsin. The cost of the project is estimated to be between $174 and $180 million. Construction for the project is tentatively scheduled to begin during the fourth quarter of 2020, and the project is expected to be completed by the end of 2021.

WE and WG each plan to construct their own LNG facility. Subject to PSCW approval, each facility will provide approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate


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pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility. Commercial operation for the LNG facilities is targeted for the end of 2023.

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 2022 is between $280 million and $300 million.

The non-utility energy infrastructure line item in the table above includes WECI's planned investments in Thunderhead, Blooming Grove, and Tatanka Ridge. 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 $42 million from 2020 through 2022. We do not expect to make any contributions to ATC Holdco during that period.

See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information on the impacts to our capital projects as a result of the COVID-19 pandemic.

Common Stock Dividends

Our current quarterly dividend rate is $0.6325 per share, which equates to an annual dividend of $2.53 per share. For information related to our most recent common stock dividend declared, see Note 8, 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 9, Short-Term Debt and Lines of Credit, Note 16, Guarantees, and Note 21, Variable Interest Entities.

Contractual Obligations

For 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 2019 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the nine months ended September 30, 2020.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2019 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental matters, critical accounting policies and estimates, and other matters.

Coronavirus Disease – 2019

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


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Liquidity and Financial Markets

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

In response to the factors discussed above, we have taken several steps to enhance our liquidity position. In March 2020, we entered into a $340 million, 364-day term loan, which was used to pay down commercial paper. Also, while not directly related to COVID-19, we have completed several long-term debt offerings in 2020 in order to finance capital investment in accordance with our long-term capital plan and also to take advantage of the current low interest rate environment. See Note 10, Long-Term Debt, for more information on recent borrowings.

Our overall liquidity position remains strong. As of September 30, 2020, we had approximately $2.4 billion available under our credit facilities, providing sufficient backing for our commercial paper program.

Pensions and Other Benefits

Our pension and OPEB plans were well funded at December 31, 2019, with total plan assets exceeding total benefit obligations by $204.3 million. There has been significant volatility in global capital markets during the COVID-19 pandemic, although the market losses recorded during the early stages of the pandemic in the first quarter of 2020 have reversed course in the second and third quarters of 2020 in response to government stimulus and relief efforts and the gradual reopening of businesses. During the nine months ended September 30, 2020, we recognized a $121 million increase in the value of long-term investments held in our pension and OPEB plan trusts as second and third quarter gains more than offset first quarter losses.

We could still see earnings volatility associated with certain other benefit plans that we maintain, primarily related to performance units that we grant to certain employees, and our deferred compensation plans. Certain of the liabilities associated with the deferred compensation plans are indexed to mutual funds and our common stock, and the liabilities associated with outstanding performance units are indexed to our common stock. These liabilities are marked to fair value through earnings each period, with earnings increasing as market prices decrease. Earnings volatility associated with our deferred compensation plans is partially mitigated by investments we hold in a rabbi trust.

Allowance for Credit Losses

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

Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WG, and WPS in our Wisconsin segment include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) and foregone revenues related to the COVID-19 pandemic. The additional protections provided by these COVID-19 specific regulatory orders are still being assessed and will be subject to prudency reviews. See Note 24, Regulatory Environment, for more information on these orders.


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Loss of Business

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

Based on market conditions and disruptions in manufacturing and steel production due to the impact of COVID-19, our largest customer, the Tilden mine, temporarily idled production at the end of April. Since then, Tilden has seen demand for its products recover, and as a result, resumed production in June. UMERC’s natural gas-fired generation facilities began commercial operation effective March 31, 2019, and the total cost was approximately $255 million including AFUDC. Through an agreement between UMERC and Tilden, Tilden is responsible for 50% of the cost of these generation facilities and all of the operation and maintenance expense incurred at these facilities, whether or not the mine is operating. Because Tilden remained responsible for these costs, its temporary shut-down did not have a significant impact on our results of operations.

Supply Chain and Capital Projects

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

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

Employee Safety

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

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

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

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

Regulatory Environment

Our utilities have taken actions to ensure that essential utility services are available to customers in their service territories during the COVID-19 pandemic. In addition, the PSCW, the ICC, the MPUC, and the MPSC have all issued written orders regarding certain measures required in their respective jurisdictions. See Note 24, Regulatory Environment, for more information on these orders and the potential recovery of expenditures incurred as a result of the measures being taken.


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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 2019 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB Accounting Standards Codification. 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.

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:

•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, 2020, we had not received any significant disallowances of the costs incurred for this project. WPS and MERC received approval to recover these costs in their most recent rate orders; however, the costs incurred for this project in our other regulatory jurisdictions are still subject to approval by the applicable regulators.

•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 2020, PGL filed its 2019 reconciliation with the ICC, which, along with the 2018, 2017, and 2016 reconciliations, are still pending. As of September 30, 2020, 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 24, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Environmental Matters

See Note 22, 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. In 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. The various remaining impacts of the Tax Legislation on our Wisconsin operations were addressed in the rate orders issued by the PSCW in December 2019. See Note 24, Regulatory Environment, for more information on these rate orders. Also, the MPSC approved a settlement in May 2018 with Tilden that addressed all base rate impacts of the Tax Legislation, and the FERC approved the revised formula rate tariffs for WPS and WE that incorporated the impacts on the Tax Legislation in July 2019 and August 2020, respectively. 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.


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American Transmission Company Allowed Return on Equity Complaints

On November 21, 2019, the FERC issued an order (November 2019 Order) related to the methodology used to calculate the base ROE for all MISO transmission owners, including ATC. Based on this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC's modified methodology reduced the base ROE that ATC is allowed to collect on a going-forward basis, as discussed below. In response to the FERC's decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

On May 21, 2020, the FERC issued an order (May 2020 Order) that granted in part and denied in part the requests to rehear the November 2019 Order. In the May 2020 Order, the FERC made additional revisions to its base ROE methodology, including adding the use of the risk premium model. As discussed below, the additional revisions made by the FERC increased ATC's base ROE authorized in the November 2019 Order on a going-forward basis, but various parties have filed requests to rehear certain parts of the May 2020 Order with the FERC. Petitions for review of the November 2019 Order and relevant parts of the May 2020 Order have also been filed with the D.C. Circuit Court of Appeals.

First Return on Equity Complaint

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 September 2016, the FERC issued an order requiring MISO transmission owners to collect a reduced 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 FERC then issued the November 2019 Order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. The November 2019 Order further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88%, effective as of September 28, 2016 and prospectively. The November 2019 Order also continued to allow the collection of the 0.5% ROE incentive adder, which only applies to revenues collected after January 6, 2015. In response to the rehearing requests filed related to the November 2019 Order, the FERC issued another order in May 2020. This May 2020 Order increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02%, effective as of September 28, 2016 and prospectively. The May 2020 Order also allowed the continued collection of the 0.5% ROE incentive adder.

ATC is required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through May 21, 2020. As a result, ATC is expected to provide WE and WPS with refunds related to the transmission costs they paid during the two refund periods by the end of September 2021, and these refunds will be applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

Second Return on Equity Complaint

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. The FERC also addressed this second complaint in the November 2019 Order. Similar to the first complaint, the November 2019 Order stated that the base ROE of 9.88% and the 0.5% incentive adder were reasonable for the period covered by the second complaint, February 12, 2015 through May 10, 2016. However, in the November 2019 Order, the FERC relied on certain provisions of the Federal Power Act to dismiss the second complaint and to determine that refunds were not allowed for this period. In its May 2020 Order, the FERC stated the new base ROE of 10.02% and the 0.5% incentive adder were reasonable for the period covered by the second complaint. However, the FERC relied on the same provisions of the Federal Power Act to again dismiss the complaint and determine that refunds were not allowed for this period. The FERC also denied the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.

Due to the various outstanding rehearing requests and petitions related to the May 2020 Order and the November 2019 Order, refunds could still be required for the second complaint period. Therefore, our financials continue to reflect a liability of $39.1 million, which reduced our equity earnings from ATC. This liability is based on a 10.52% ROE for the second complaint period. If it is ultimately determined that a refund is required for the second complaint period, we would not expect any such refund to have a material impact on our financial statements or results of operations in the future. In addition, WE and WPS would be entitled to receive a portion of the refund from ATC for the benefit of their customers.


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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 2019 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill Impairment

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2020. No impairments were recorded as a result of these tests.

Our reporting units had the following goodwill balances at July 1, 2020:


(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 reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the 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 after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for 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, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

See Note 18, 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 2019 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019 and Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 14, Fair Value Measurements, Note 15, Derivative Instruments, and Note 16, 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 2020 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 2019 Annual Report on Form 10-K. See Note 22, Commitments and Contingencies, and Note 24, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed in Note 22, Commitments and Contingencies, Note 24, 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

Manlove Field Matter

In 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 natural gas leak and the Illinois state agencies to investigate and remediate the impacts of the natural gas leak to the Mahomet 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 2019 whereby PGL agreed, among other things, to continue actions it was already undertaking proactively, including the submittal of a GMZ application to the IEPA in August 2019. A supplemental filing was sent to the IEPA in December 2019. Proposed modifications to the GMZ application were submitted to the Illinois AG and the IEPA in May 2020. In September 2020, the IEPA sent PGL a letter conditionally approving the GMZ application.

In addition, in December 2017, the IEPA 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 operation of flaring equipment at the leak site. Both of the IEPA VN matters have been referred to the AG for enforcement.

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

ITEM 1A. RISK FACTORS

The following risk factor updates and supplements those risk factors disclosed in Item 1A. Risk Factors in Part I of our 2019 Annual Report on Form 10-K and Part II of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.

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

Such measures have significantly disrupted economic activity in our service territories and have caused disruptions and volatility in the capital markets. In addition, some of our utility subsidiaries are continuing to temporarily suspend disconnections for non-payment by certain customer classes. The effects of the continued outbreak of COVID-19 and related government responses have


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included, and may continue to include, extended disruptions to supply chains and capital markets, reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could continue to have a variety of adverse impacts on us and our subsidiaries, including continued reductions in demand for energy, particularly from commercial and industrial customers; impairment of goodwill or long-lived assets; continued decreases in revenue due to the inability to collect late fees; increased bad debt expense; impairment of our and our subsidiaries' ability to develop, construct, and operate facilities; and impaired ability to successfully access funds from credit and capital markets.

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

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

Despite our efforts to manage the impacts of the COVID-19 pandemic, the extent to which COVID-19 may continue to affect us depends on factors beyond our knowledge or control. Therefore, we are currently unable to determine what additional impact the COVID-19 pandemic may have on our business plans and operations, liquidity, financial condition, and results of operations, but will continue to monitor COVID-19 developments and modify our plans as conditions change.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended September 30, 2020:


Issuer Purchases of Equity Securities
2020	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 – July 31	9,838	$	88.55	—	$	—
August 1 – August 31	—	—		—	—
September 1 – September 30	—	—		—	—
Total (1)	9,838	$	88.55	—

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


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ITEM 6. EXHIBITS


Number	Exhibit
4	Instruments Defining the Rights of Security Holders, Including Indentures

	4.1	Securities Resolution No. 9 of WEC Energy Group, effective as of September 14, 2020, under the Indenture for Debt Securities, dated as of March 15, 1999, between WEC Energy Group and The Bank of New York Mellon Trust Company, N.A. (as successor to the First National Bank of Chicago), as Trustee. (Exhibit 4.1 to WEC Energy Group's Form 8-K filed September 17, 2020.)

	4.2	Securities Resolution No. 10 of WEC Energy Group, effective as of October 5, 2020, under the Indenture for Debt Securities, dated as of March 15, 1999, between WEC Energy Group and The Bank of New York Mellon Trust Company, N.A. (as successor to the First National Bank of Chicago), as Trustee. (Exhibit 4.1 to WEC Energy Group's Form 8-K filed October 9, 2020.)




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.INS	Inline 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.SCH	Inline XBRL Taxonomy Extension Schema

	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase

	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase

	101.LAB	Inline XBRL Taxonomy Extension Label Linkbase

	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase

104	Cover 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 6, 2020	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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