WEC ENERGY GROUP, INC. - Quarter Report: 2021 September (Form 10-Q)

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, 2021


☐			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, 2021):

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, 2021

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 6

Property, Plant, and Equipment

Note 7

Common Equity

Note 8

Short-Term Debt and Lines of Credit

Note 9

Long-Term Debt

Note 10

Materials, Supplies, and Inventories

Note 11

Income Taxes

Note 12

Fair Value Measurements

Note 13

Derivative Instruments

Goodwill and Intangibles

Note 17

Investment in Transmission Affiliates

Note 18

Segment Information

Note 19

Variable Interest Entities

Note 20

Commitments and Contingencies

Note 21

Supplemental Cash Flow Information

Note 22

Regulatory Environment

Note 23

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

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ITEM 6.

EXHIBITS

SIGNATURE


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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
Blooming Grove						Blooming Grove Wind Energy Center LLC
Bluewater						Bluewater Natural Gas Holding, LLC
Coyote Ridge						Coyote Ridge Wind, LLC
Integrys						Integrys Holding, Inc.
Jayhawk						Jayhawk Wind, LLC
MERC						Minnesota Energy Resources Corporation
MGU						Michigan Gas Utilities Corporation
NSG						North Shore Gas Company

PGL						The Peoples Gas Light and Coke Company
Tatanka Ridge						Tatanka Ridge Wind LLC
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
WECI Wind Holding I						WEC Infrastructure Wind Holding I LLC
WG						Wisconsin Gas LLC
WEPCo Environmental Trust						WEPCo Environmental Trust Finance I, LLC
Wispark						Wispark LLC
WPS						Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
DOC						United States Department of Commerce
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
WDNR						Wisconsin Department of Natural Resources

Accounting Terms


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
VIE						Variable Interest Entity

Environmental Terms
ACE						Affordable Clean Energy
BATW						Bottom Ash Transport Water

BTA						Best Technology Available
CAA						Clean Air Act
CO2						Carbon Dioxide
CSAPR						Cross-State Air Pollution Rule


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ELG						Steam Electric Effluent Limitation Guidelines
FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
GMZ						Groundwater Management Zone

NAAQS						National Ambient Air Quality Standards
NOV						Notice of Violation
NOx						Nitrogen Oxide


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
2013 Junior Notes						Integrys Holding, Inc.'s 6.00% Junior Notes due August 1, 2073
AG						Attorney General
AMI						Advanced Metering Infrastructure
Badger Hollow I						Badger Hollow Solar Park I
Badger Hollow II						Badger Hollow Solar Park II
CDC						Centers for Disease Control and Prevention
CIP						Conservation Improvement Program
COVID-19						Coronavirus Disease – 2019
Crane Creek						Crane Creek Wind Park
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
Executive Order 13990						Executive Order 13990 of January 20, 2021 – Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis
ERGS						Elm Road Generating Station
ESG Progress Plan						WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth
ETB						Environmental Trust Bond
EV						Electric Vehicle
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
GCRM						Gas Cost Recovery Mechanism
GUIC						Gas Utility Infrastructure Cost
ITC						Investment Tax Credit
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 7						Oak Creek Power Plant Unit 7
OC 8						Oak Creek Power Plant Unit 8

PPA						Power Purchase Agreement
PSB						Public Service Building
PTC						Production Tax Credit
QIP						Qualifying Infrastructure Plant
ROE						Return on Equity
Sapphire Sky						Sapphire Sky Wind Energy LLC
SMP						Natural Gas System Modernization Program

SPC						COVID-19 Special Purpose Charge
SSR						System Support Resource
Supreme Court						United States Supreme Court
Tax Legislation						Tax Cuts and Jobs Act of 2017
Thunderhead						Thunderhead Wind Energy LLC


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TPTFA						Third-Party Transaction Fee Adjustment

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, including 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, climate-related matters, our ESG Progress Plan, 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 our 2020 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 or regulatory developments, varying, adverse, or unusually severe weather conditions, 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 health pandemics, including 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 those that affect our ability to use PTCs and ITCs;

•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;

•Supply chain disruptions, including any that may occur as a result of the DOC's impending decision on whether to impose new tariffs on solar panels and cells imported from several Southeastern Asian countries;

•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;


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•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 inflation and changing commodity prices, including natural gas and electricity;

•The availability and cost of sources of natural gas and other fossil fuels, purchased power, materials needed to operate environmental controls at our electric 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;

•Risks related to our non-utility renewable energy facilities, including unfavorable weather, the ability to replace expiring long-term PPAs under acceptable terms, and the availability of reliable interconnection and electricity grids;

•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 continuing to integrate and consolidate our enterprise systems;


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•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.

Except as may be required by law, 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)	2021		2020		2021		2020
Operating revenues	$	1,746.5	$	1,651.0	$	6,114.1	$	5,308.3

Operating expenses
Cost of sales	560.7		482.8		2,352.2		1,662.0
Other operation and maintenance	473.7		498.7		1,417.4		1,427.5
Depreciation and amortization	271.6		245.0		799.2		726.6
Property and revenue taxes	50.5		54.3		157.2		156.6
Total operating expenses	1,356.5		1,280.8		4,726.0		3,972.7

Operating income	390.0		370.2		1,388.1		1,335.6

Equity in earnings of transmission affiliates	42.3		40.1		126.2		132.8
Other income, net	25.2		25.7		97.7		59.9
Interest expense	118.0		122.0		357.5		375.8
Other expense	(50.5)		(56.2)		(133.6)		(183.1)

Income before income taxes	339.5		314.0		1,254.5		1,152.5
Income tax expense	50.8		46.9		179.8		190.7
Net income	288.7		267.1		1,074.7		961.8

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Net loss attributed to noncontrolling interests	1.6		—		2.3		—
Net income attributed to common shareholders	$	290.0	$	266.8	$	1,076.1	$	960.9

Earnings per share
Basic	$	0.92	$	0.85	$	3.41	$	3.05
Diluted	$	0.92	$	0.84	$	3.40	$	3.04

Weighted average common shares outstanding
Basic	315.4		315.4		315.4		315.4
Diluted	316.3		316.5		316.3		316.6

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 COMPREHENSIVE INCOME (Unaudited)	Three Months Ended				Nine Months Ended
	September 30				September 30
(in millions)	2021		2020		2021		2020
Net income	$	288.7	$	267.1	$	1,074.7	$	961.8

Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Net derivative loss, net of tax benefit of $— , $—, $—, and $(1.6), respectively	—		—		—		(4.2)
Reclassification of realized net derivative loss to net income, net of tax expense of $0.5 , $0.4, $1.2, and $0.6, respectively	0.9		0.9		2.9		1.4
Cash flow hedges, net	0.9		0.9		2.9		(2.8)

Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.1		—		0.3		0.5

Other comprehensive income (loss), net of tax	1.0		0.9		3.2		(2.3)

Comprehensive income	289.7		268.0		1,077.9		959.5

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Comprehensive loss attributed to noncontrolling interests	1.6		—		2.3		—
Comprehensive income attributed to common shareholders	$	291.0	$	267.7	$	1,079.3	$	958.6

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, 2021		December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	26.0	$	24.8
Accounts receivable and unbilled revenues, net of reserves of $199.7 and $220.1, respectively	1,103.8		1,202.8
Materials, supplies, and inventories	645.7		528.6

Prepayments	195.7		263.4
Amounts recoverable from customers	139.4		20.0
Derivative assets	247.1		17.0
Other	51.2		26.4
Current assets	2,408.9		2,083.0

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $9,799.3 and $9,364.7, respectively	26,622.7		25,707.4
Regulatory assets (September 30, 2021 includes $102.9 related to WEPCo Environmental Trust)	3,488.7		3,524.1
Equity investment in transmission affiliates	1,791.3		1,764.3
Goodwill	3,052.8		3,052.8
Other	1,036.5		896.5
Long-term assets	35,992.0		34,945.1
Total assets	$	38,400.9	$	37,028.1

Liabilities and Equity
Current liabilities
Short-term debt	$	1,508.9	$	1,776.9
Current portion of long-term debt (September 30, 2021 includes $8.5 related to WEPCo Environmental Trust)	496.7		785.8
Accounts payable	872.8		880.7


Other	814.2		704.7
Current liabilities	3,692.6		4,148.1

Long-term liabilities
Long-term debt (September 30, 2021 includes $107.0 related to WEPCo Environmental Trust)	12,678.1		11,728.1
Deferred income taxes	4,295.8		4,059.8
Deferred revenue, net	394.9		412.2
Regulatory liabilities	4,131.2		3,928.1
Environmental remediation liabilities	510.3		532.9
Pension and OPEB obligations	307.8		327.0
Other	1,283.6		1,229.4
Long-term liabilities	23,601.7		22,217.5

Commitments and contingencies (Note 20)

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	4,144.4		4,143.7
Retained earnings	6,764.5		6,329.6
Accumulated other comprehensive loss	(3.6)		(6.8)
Common shareholders' equity	10,908.5		10,469.7

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	167.7		162.4
Total liabilities and equity	$	38,400.9	$	37,028.1

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)	2021		2020
Operating activities
Net income	$	1,074.7	$	961.8
Reconciliation to cash provided by operating activities
Depreciation and amortization	799.2		726.6
Deferred income taxes and ITCs, net	158.0		152.5
Contributions and payments related to pension and OPEB plans	(11.3)		(10.1)
Equity income in transmission affiliates, net of distributions	(27.0)		(20.3)
Change in –
Accounts receivable and unbilled revenues, net	162.4		262.3
Materials, supplies, and inventories	(117.1)		(23.6)
Prepayments	67.7		92.3
Amounts recoverable from customers	(119.4)		(1.3)
Other current assets	13.8		38.5
Accounts payable	(15.1)		(178.9)
Other current liabilities	107.5		(23.3)
Other, net	(86.7)		(26.8)
Net cash provided by operating activities	2,006.7		1,949.7

Investing activities
Capital expenditures	(1,627.9)		(1,618.7)
Acquisition of Jayhawk	(119.8)		—
Capital contributions to transmission affiliates	—		(15.2)
Proceeds from the sale of assets	21.6		9.8
Proceeds from the sale of investments held in rabbi trust	12.7		17.1
Insurance proceeds received for property damage	—		22.2
Other, net	24.7		21.7
Net cash used in investing activities	(1,688.7)		(1,563.1)

Financing activities
Exercise of stock options	6.5		23.3
Purchase of common stock	(15.7)		(56.7)
Dividends paid on common stock	(641.2)		(598.5)
Issuance of long-term debt	1,018.8		810.0
Retirement of long-term debt	(356.2)		(482.6)
Issuance of short-term loan	0.5		340.0
Repayment of short-term loan	(340.0)		—
Change in other short-term debt	71.5		(399.8)
Purchase of additional ownership interest in Upstream from noncontrolling interest	—		(31.0)
Other, net	(25.6)		(12.4)
Net cash used in financing activities	(281.4)		(407.7)

Net change in cash, cash equivalents, and restricted cash	36.6		(21.1)
Cash, cash equivalents, and restricted cash at beginning of period	72.6		82.3
Cash, cash equivalents, and restricted cash at end of period	$	109.2	$	61.2

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, 2020	$	3.2	$	4,143.7	$	6,329.6	$	(6.8)	$	10,469.7	$	30.4	$	162.4	$	10,662.5
Net income attributed to common shareholders	—		—		510.1		—		510.1		—		—		510.1
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.1)		(0.1)
Other comprehensive income	—		—		—		1.1		1.1		—		—		1.1
Common stock dividends of $0.6775 per share	—		—		(213.7)		—		(213.7)		—		—		(213.7)
Exercise of stock options	—		1.2		—		—		1.2		—		—		1.2
Purchase of common stock	—		(6.6)		—		—		(6.6)		—		—		(6.6)
Acquisition of a noncontrolling interest	—		—		—		—		—		—		6.2		6.2
Capital contributions from noncontrolling interest	—		—		—		—		—		—		2.0		2.0
Distributions to noncontrolling interests	—		—		—		—		—		—		(0.4)		(0.4)
Stock-based compensation and other	—		5.3		—		—		5.3		—		—		5.3
Balance at March 31, 2021	$	3.2	$	4,143.6	$	6,626.0	$	(5.7)	$	10,767.1	$	30.4	$	170.1	$	10,967.6
Net income attributed to common shareholders	—		—		276.0		—		276.0		—		—		276.0
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.6)		(0.6)
Other comprehensive income	—		—		—		1.1		1.1		—		—		1.1
Common stock dividends of $0.6775 per share	—		—		(213.8)		—		(213.8)		—		—		(213.8)
Exercise of stock options	—		2.8		—		—		2.8		—		—		2.8
Purchase of common stock	—		(4.7)		—		—		(4.7)		—		—		(4.7)
Capital contributions from noncontrolling interest	—		—		—		—		—		—		0.5		0.5
Distributions to noncontrolling interests	—		—		—		—		—		—		(0.9)		(0.9)
Stock-based compensation and other	—		2.4		—		—		2.4		—		—		2.4
Balance at June 30, 2021	$	3.2	$	4,144.1	$	6,688.2	$	(4.6)	$	10,830.9	$	30.4	$	169.1	$	11,030.4
Net income attributed to common shareholders	—		—		290.0		—		290.0		—		—		290.0
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(1.6)		(1.6)
Other comprehensive income	—		—		—		1.0		1.0		—		—		1.0
Common stock dividends of $0.6775 per share	—		—		(213.7)		—		(213.7)		—		—		(213.7)
Exercise of stock options	—		2.5		—		—		2.5		—		—		2.5
Purchase of common stock	—		(4.4)		—		—		(4.4)		—		—		(4.4)
Capital contributions from noncontrolling interest	—		—		—		—		—		—		2.2		2.2
Distributions to noncontrolling interests	—		—		—		—		—		—		(2.0)		(2.0)
Stock-based compensation and other	—		2.2		—		—		2.2		—		—		2.2
Balance at September 30, 2021	$	3.2	$	4,144.4	$	6,764.5	$	(3.6)	$	10,908.5	$	30.4	$	167.7	$	11,106.6


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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, 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

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, 2021

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.6 million electric customers and 3.0 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, which we control, and VIEs, of which we are the primary beneficiary. We 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, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties.

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 17, 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, 2020. 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, 2021, are not necessarily indicative of expected results for 2021 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

The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs and interconnection agreements. See Note 16, Goodwill and Intangibles, for more information.

Acquisition of a Wind Energy Generation Facility in Illinois

In June 2021, WECI signed an agreement to acquire a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility under construction in McLean County, Illinois, for approximately $412 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 12 years. WECI's investment in Sapphire Sky is expected to qualify for PTCs. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of 2022, at which time the transaction is expected to close. Sapphire Sky will be included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in Kansas

In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility under construction in Bourbon and Crawford counties, Kansas, for $119.8 million, which included transaction costs, and was allocated primarily to property, plant, and equipment. As of September 30, 2021, WECI incurred an additional $88.3 million of capital expenditures for the project for a total investment of $208.1 million. Upon completion, we expect WECI's total investment to be


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approximately $302 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 10 years. WECI's investment in Jayhawk is expected to qualify for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Commercial operation is expected to begin no later than the first quarter of 2022. Jayhawk is included in the non-utility energy infrastructure segment.

Acquisition of a Wind Energy Generation Facility in South Dakota

In December 2020, WECI completed the acquisition of an 85% ownership interest in Tatanka Ridge, a 155 MW wind generating facility in Deuel County, South Dakota that became commercially operational in January 2021. WECI's total investment was $240.1 million, which included transaction costs. Tatanka Ridge has offtake agreements for all the energy produced with an affiliate of an investment grade multinational company for 12 years and a well-established electric cooperative that serves utilities in multiple states for 10 years. WECI's investment in Tatanka Ridge qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Tatanka Ridge is included in the non-utility energy infrastructure segment.

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 for all of the energy to be produced by the facility for 12 years. WECI's investment in Thunderhead is expected to qualify for PTCs. 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 delay in construction of the required substation, Thunderhead is now expected to begin commercial operation during the first half of 2022. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment.

In April 2020, WECI acquired an additional 10% ownership interest in Upstream for $31.0 million, bringing its total ownership interest to 90%. Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue is substantially fixed over the first 10 years through an agreement with an unaffiliated third party. WECI's investment in Upstream qualifies for PTCs. Upstream is included in the non-utility energy infrastructure segment.


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NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2020 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, 2021
Electric	$	1,284.6	$	—	$	—	$	1,284.6	$	—	$	—	$	—		$	1,284.6
Natural gas	169.0		208.3		48.1		425.4		9.7		—		(9.1)			426.0
Total regulated revenues	1,453.6		208.3		48.1		1,710.0		9.7		—		(9.1)			1,710.6
Other non-utility revenues	—		—		4.3		4.3		19.7		—		(1.6)			22.4
Total revenues from contracts with customers	1,453.6		208.3		52.4		1,714.3		29.4		—		(10.7)			1,733.0
Other operating revenues	5.0		7.9		0.4		13.3		100.1		0.2		(100.1)		(1)	13.5
Total operating revenues	$	1,458.6	$	216.2	$	52.8	$	1,727.6	$	129.5	$	0.2	$	(110.8)		$	1,746.5


(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)		(1)	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
Nine Months Ended September 30, 2021
Electric	$	3,462.8	$	—	$	—	$	3,462.8	$	—	$	—	$	—		$	3,462.8
Natural gas	1,009.0		1,167.9		340.6		2,517.5		33.7		—		(31.1)			2,520.1
Total regulated revenues	4,471.8		1,167.9		340.6		5,980.3		33.7		—		(31.1)			5,982.9
Other non-utility revenues	—		—		13.4		13.4		67.1		—		(7.1)			73.4
Total revenues from contracts with customers	4,471.8		1,167.9		354.0		5,993.7		100.8		—		(38.2)			6,056.3
Other operating revenues	26.0		27.2		4.2		57.4		299.8		0.4		(299.8)		(1)	57.8
Total operating revenues	$	4,497.8	$	1,195.1	$	358.2	$	6,051.1	$	400.6	$	0.4	$	(338.0)		$	6,114.1


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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, 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)		(1)	39.8
Total operating revenues	$	4,071.4	$	930.7	$	261.4	$	5,263.5	$	378.4	$	2.0	$	(335.6)		$	5,308.3

(1)Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2021		2020		2021		2020
Residential	$	512.2	$	500.8	$	1,354.9	$	1,324.4
Small commercial and industrial	396.9		373.6		1,074.9		1,004.3
Large commercial and industrial	271.9		244.0		705.9		626.4
Other	7.0		6.9		21.7		21.1
Total retail revenues	1,188.0		1,125.3		3,157.4		2,976.2
Wholesale	41.1		46.5		119.4		129.9
Resale	45.0		33.7		145.1		107.3
Steam	2.7		2.5		21.7		15.0
Other utility revenues	7.8		4.9		19.2		18.7
Total electric utility operating revenues	$	1,284.6	$	1,212.9	$	3,462.8	$	3,247.1

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, 2021
Residential	$	89.4	$	146.5	$	23.7	$	259.6
Commercial and industrial	45.4		40.7		14.6		100.7
Total retail revenues	134.8		187.2		38.3		360.3
Transportation	16.1		43.4		6.0		65.5
Other utility revenues (1)	18.1		(22.3)		3.8		(0.4)
Total natural gas utility operating revenues	$	169.0	$	208.3	$	48.1	$	425.4


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(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
Transportation	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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2021
Residential	$	625.6	$	679.5	$	149.5	$	1,454.6
Commercial and industrial	312.0		194.9		75.8		582.7
Total retail revenues	937.6		874.4		225.3		2,037.3
Transportation	58.3		166.4		23.6		248.3
Other utility revenues (1)	13.1		127.1		91.7		231.9
Total natural gas utility operating revenues	$	1,009.0	$	1,167.9	$	340.6	$	2,517.5


(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
Transportation	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

(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. The amounts for the nine months ended September 30, 2021 reflect the higher natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues. See Note 22, Regulatory Environment, for more information. In addition to costs related to the extreme weather event, we incurred higher natural gas costs throughout the nine months ended September 30, 2021, compared with the same period in 2020, as a result of an increase in the price of natural gas.

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 the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.


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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)	2021		2020		2021		2020
Wind generation revenues	$	12.2	$	7.4	$	42.5	$	24.0
We Power revenues (1)	5.9		5.8		17.5		17.1
Appliance service revenues	4.3		4.2		13.4		12.8

Other	—		0.5		—		1.8
Total other non-utility operating revenues	$	22.4	$	17.9	$	73.4	$	55.7

(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, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE.

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2021		2020		2021		2020
Late payment charges (1)	$	11.9	$	6.0	$	44.2	$	18.1
Alternative revenues	0.9		5.4		10.0		18.2
Other	0.7		1.0		3.6		3.5
Total other operating revenues	$	13.5	$	12.4	$	57.8	$	39.8

(1)The increase in late payment charges during the three and nine months ended September 30, 2021, compared with the same periods in 2020, was a result of the expiration of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 22, Regulatory Environment, for more information.

NOTE 4—CREDIT LOSSES

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.

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.

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


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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 22, 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 tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2021 and December 31, 2020, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
September 30, 2021
Accounts receivable and unbilled revenues	$	927.9		$	316.6		$	45.2		$	1,289.7		$	9.4		$	4.4		$	1,303.5
Allowance for credit losses	76.4			114.7			8.6			199.7			—			—			199.7
Accounts receivable and unbilled revenues, net (1)	$	851.5		$	201.9		$	36.6		$	1,090.0		$	9.4		$	4.4		$	1,103.8

Total accounts receivable, net – past due greater than 90 days (1)	$	51.9		$	26.4		$	8.9		$	87.2		$	—		$	—		$	87.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	96.5		%	100.0		%	—		%	87.7		%	—		%	—		%	87.7		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2020
Accounts receivable and unbilled revenues	$	899.8		$	393.9		$	79.8		$	1,373.5		$	45.0		$	4.4		$	1,422.9
Allowance for credit losses	102.1			111.6			6.4			220.1			—			—			220.1
Accounts receivable and unbilled revenues, net (1)	$	797.7		$	282.3		$	73.4		$	1,153.4		$	45.0		$	4.4		$	1,202.8

Total accounts receivable, net – past due greater than 90 days (1)	$	84.8		$	34.5		$	3.5		$	122.8		$	—		$	—		$	122.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.6		%	100.0		%	—		%	95.5		%	—		%	—		%	95.5		%

(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, 2021, $527.5 million, or 47.8%, 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 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 22, 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, 2021 and 2020 is included below:


Three Months Ended September 30, 2021 (in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Corporate and Other		WEC Energy Group Consolidated
Balance at June 30, 2021	$	114.4	$	109.0	$	8.3	$	231.7	$	—	$	231.7
Provision for credit losses	10.7		4.4		0.8		15.9		—		15.9
Provision for credit losses deferred for future recovery or refund	(38.2)		26.5		—		(11.7)		—		(11.7)
Write-offs charged against the allowance	(16.2)		(29.9)		(0.7)		(46.8)		—		(46.8)
Recoveries of amounts previously written off	5.7		4.7		0.2		10.6		—		10.6
Balance at September 30, 2021	$	76.4	$	114.7	$	8.6	$	199.7	$	—	$	199.7


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Nine Months Ended September 30, 2021 (in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Corporate and Other		WEC Energy Group Consolidated
Balance at December 31, 2020	$	102.1	$	111.6	$	6.4	$	220.1	$	—	$	220.1
Provision for credit losses	33.8		16.7		3.1		53.6		—		53.6
Provision for credit losses deferred for future recovery or refund	(28.1)		10.7		—		(17.4)		—		(17.4)
Write-offs charged against the allowance	(51.2)		(36.7)		(1.8)		(89.7)		—		(89.7)
Recoveries of amounts previously written off	19.8		12.4		0.9		33.1		—		33.1
Balance at September 30, 2021	$	76.4	$	114.7	$	8.6	$	199.7	$	—	$	199.7

In total, the allowance for credit losses decreased over both the three and nine month periods ended September 30, 2021. The allowance for credit losses related to our Wisconsin segment decreased, as normal collection practices began in April 2021 for our Wisconsin Utilities, earlier than in our other service territories. Normal collection practices in our Illinois and Other States segments didn't begin until June 30, 2021 and August 2, 2021, respectively. As a result, we continued to see an increase in the allowance for credit losses in these service territories through September 30, 2021, but expect that the allowance for credit losses will decrease as we continue to ramp up our collection efforts. See Note 22, Regulatory Environment, for more information on the impact that the COVID-19 pandemic has had on our allowed collection practices.


Three Months Ended September 30, 2020 (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


Nine Months Ended September 30, 2020 (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 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 received, we were also unable to disconnect any of our Wisconsin and Illinois customers during the second and third quarters of 2020.


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NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2021 and December 31, 2020. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2020 Annual Report on Form 10-K.


(in millions)	September 30, 2021		December 31, 2020
Regulatory assets
Pension and OPEB costs	$	1,019.1	$	1,101.6
Plant retirements	726.5		740.8
Environmental remediation costs	601.9		638.2
Income tax related items	459.3		454.6
Asset retirement obligations	208.9		181.3
SSR	131.6		135.6
Energy costs recoverable through rate adjustments (1)	125.9		1.1
Securitization (2)	102.9		105.2
MERC extraordinary natural gas costs (3)	64.7		—
Uncollectible expense	55.7		82.0
Derivatives	25.9		26.5
Other, net	105.7		77.2
Total regulatory assets	$	3,628.1	$	3,544.1

Balance sheet presentation
Amounts recoverable from customers (1)	$	139.4	$	20.0
Regulatory assets	3,488.7		3,524.1
Total regulatory assets	$	3,628.1	$	3,544.1

(1)The increase in these regulatory assets primarily relates to the high natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. See Note 22, Regulatory Environment, for more information.

(2)See Note 19, Variable Interest Entities, for more information.

(3)This regulatory asset relates to the extraordinary natural gas costs MERC incurred during February 2021 that are being recovered over 27 months, beginning in September 2021. See Note 22, Regulatory Environment, for more information.


(in millions)	September 30, 2021		December 31, 2020
Regulatory liabilities
Income tax related items	$	2,030.1	$	2,137.7
Removal costs	1,244.5		1,221.1
Pension and OPEB benefits	366.3		378.1
Derivatives (1)	298.7		16.4
Electric transmission costs	83.5		78.5
Uncollectible expense	47.2		25.5
Earnings sharing mechanisms	25.2		36.9
Energy costs refundable through rate adjustments	5.5		59.9
Other, net	36.9		25.0
Total regulatory liabilities	$	4,137.9	$	3,979.1

Balance sheet presentation
Other current liabilities	$	6.7	$	51.0
Regulatory liabilities	4,131.2		3,928.1
Total regulatory liabilities	$	4,137.9	$	3,979.1

(1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 13, Derivative Instruments, for more information.


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NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by the end of 2023 and 2024, respectively. The net book value of WPS's ownership share of these generating units was $279.3 million at September 30, 2021. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Public Service Building

During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB. The damage to the building from the flooding and steam was extensive and requires significant repairs and restorations. As of September 30, 2021, WE had incurred $93.5 million of costs related to these repairs and restorations. WE received $20.0 million of insurance proceeds in 2020 to cover a portion of these costs and $61.0 million was recorded in accounts receivable on our balance sheet as of September 30, 2021 for future insurance recoveries. The remaining $12.5 million of costs were included in other operation and maintenance expense in 2020 as we do not intend to seek recovery of these costs.

In June 2021, we received approval from the PSCW to restore the PSB and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, we do not currently expect a significant impact to our future 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 7—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2021, 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)						530,612
Restricted shares (2)						69,681
Performance units						152,382

(1)Stock options awarded had a weighted-average exercise price of $91.06 and a weighted-average grant date fair value of $13.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $91.06 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; Bluewater Gas Storage, LLC; 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 11, Common Equity, in our 2020 Annual Report on Form 10-K for additional information on these and other restrictions.

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


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Common Stock Dividends

On October 21, 2021, our Board of Directors declared a quarterly cash dividend of $0.6775 per share, payable on December 1, 2021, to shareholders of record on November 12, 2021.

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:


(in millions, except percentages)	September 30, 2021			December 31, 2020
Commercial paper
Amount outstanding	$	1,508.4		$	1,436.9
Weighted-average interest rate on amounts outstanding	0.16		%	0.21		%
Term loan
Amount outstanding	$	—		$	340.0
Weighted-average interest rate on amounts outstanding	N/A			0.99		%
Operating expense loans
Amount outstanding (1)	$	0.5		$	—

(1)Coyote Ridge and Tatanka Ridge entered into operating expense loans and borrowed funds from their noncontrolling interests. In accordance with their limited liability company operating agreements, Coyote Ridge and Tatanka Ridge received loans from their owners in proportion to their ownership interests.

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2021 was $1,415.4 million with a weighted-average interest rate during the period of 0.17%.

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. In March 2021, we repaid the term loan using the net proceeds from the issuance of our 0.80% Senior Notes. See Note 9, Long-Term Debt, for more information.

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


(in millions)	Maturity	September 30, 2021
WEC Energy Group (1)	September 2026	$	1,500.0
WE (1)	September 2026	500.0
WPS (2)	October 2022	400.0
WG (1)	September 2026	350.0
PGL (1)	September 2026	350.0
Total short-term credit capacity		$	3,100.0

Less:
Letters of credit issued inside credit facilities		$	2.3
Commercial paper outstanding		1,508.4
Available capacity under existing agreements		$	1,589.3

(1) In September 2021, WEC Energy Group increased its credit facility to $1,500.0 million, and each of WEC Energy Group, WE, WG, and PGL extended the maturities of their credit facilities to September 2026.

(2) WPS intends to request approval from the PSCW to extend the maturity of its facility to September 2026.


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NOTE 9—LONG-TERM DEBT

WEC Energy Group, Inc.

In March 2021, we issued $600.0 million of 0.80% Senior Notes due March 15, 2024, and used the net proceeds to repay the $340.0 million 364-day term loan entered into in March 2020 and for general corporate purposes.

Wisconsin Electric Power Company

In June 2021, WE issued $300.0 million of 1.70% Debentures due June 15, 2028, and used the net proceeds to redeem all $300.0 million outstanding of its 2.95% Debentures due September 15, 2021 at par.

Integrys Holding, Inc.

On October 28, 2021, pursuant to a tender offer, Integrys purchased $178.6 million aggregate principal amount of the $400.0 million outstanding of its 2013 Junior Notes for $196.4 million (which includes payment of accrued interest) with proceeds received from WEC Energy Group issuing commercial paper. Integrys exercised its right to early settlement of the 2013 Junior Notes tendered and not validly withdrawn as of October 26, 2021. Integrys' estimated loss is $13.6 million. Integrys does not anticipate purchasing any additional 2013 Junior Notes in the tender offer, which expires on November 9, 2021.

WEPCo Environmental Trust Finance I, LLC

In May 2021, WEPCo Environmental Trust, a special purpose entity formed by WE, issued $118.8 million of 1.578% ETBs due December 15, 2035, and used the net proceeds to purchase environmental control property from WE. Principal and interest will be paid semiannually, beginning December 15, 2021, and the ETBs are expected to be fully repaid by December 15, 2033. For additional information, see Note 19, Variable Interest Entities – WEPCo Environmental Trust Finance I, LLC.

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:


(in millions)	September 30, 2021		December 31, 2020
Natural gas in storage	$	365.3	$	224.9
Materials and supplies	229.0		218.1
Fossil fuel	51.4		85.6
Total	$	645.7	$	528.6

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, 2021, 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.


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NOTE 11—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, 2021				Three Months Ended September 30, 2020
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	71.8	21.0	%	$	65.9	21.0	%
State income taxes net of federal tax benefit	21.5		6.3	%	19.7		6.3	%
PTCs	(17.0)		(5.0)	%	(11.2)		(3.6)	%
Federal excess deferred tax amortization – Wisconsin unprotected	(16.3)		(4.8)	%	(12.5)		(4.0)	%
Federal excess deferred tax amortization	(7.8)		(2.3)	%	(8.3)		(2.6)	%



Other	(1.4)		(0.2)	%	(6.7)		(2.2)	%
Total income tax expense	$	50.8	15.0	%	$	46.9	14.9	%


	Nine Months Ended September 30, 2021				Nine Months Ended September 30, 2020
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	263.7	21.0	%	$	242.0	21.0	%
State income taxes net of federal tax benefit	79.2		6.3	%	72.1		6.3	%
PTCs	(64.5)		(5.1)	%	(39.0)		(3.4)	%
Federal excess deferred tax amortization – Wisconsin unprotected	(62.9)		(5.0)	%	(45.7)		(4.0)	%
Federal excess deferred tax amortization	(30.3)		(2.4)	%	(30.2)		(2.6)	%



Other	(5.4)		(0.5)	%	(8.5)		(0.8)	%
Total income tax expense	$	179.8	14.3	%	$	190.7	16.5	%

The effective tax rates of 15.0% and 14.3% for the three and nine months ended September 30, 2021, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and 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, 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. These items were partially offset by state income taxes.

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 addition, PTCs 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. These items were 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 22, Regulatory Environment, for more information on unprotected tax benefits.

NOTE 12—FAIR VALUE MEASUREMENTS

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


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

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

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

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

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

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

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, 2021
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	209.6	$	12.6	$	—	$	222.2
FTRs	—		—		3.7		3.7
Coal contracts	—		44.2		—		44.2
Total derivative assets	$	209.6	$	56.8	$	3.7	$	270.1

Investments held in rabbi trust	$	77.8	$	—	$	—	$	77.8

Derivative liabilities
Natural gas contracts	$	0.1	$	20.5	$	—	$	20.6

Interest rate swaps	—		1.7		—		1.7
Total derivative liabilities	$	0.1	$	22.2	$	—	$	22.3


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	December 31, 2020
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	11.7	$	2.0	$	—	$	13.7
FTRs	—		—		2.4		2.4
Coal contracts	—		1.8		—		1.8
Total derivative assets	$	11.7	$	3.8	$	2.4	$	17.9

Investments held in rabbi trust	$	79.6	$	—	$	—	$	79.6

Derivative liabilities
Natural gas contracts	$	7.7	$	6.4	$	—	$	14.1
Coal contracts	—		1.2		—		1.2
Interest rate swaps	—		6.8		—		6.8
Total derivative liabilities	$	7.7	$	14.4	$	—	$	22.1

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. During the three months ended September 30, 2021, we recorded $0.1 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $5.7 million of net unrealized gains recorded during the same period in 2020. For the nine months ended September 30, 2021 and 2020, the net unrealized gains included in earnings related to the investments held at the end of the period were $9.7 million and $2.9 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)	2021		2020		2021		2020
Balance at the beginning of the period	$	5.4	$	6.5	$	2.4	$	3.1
Purchases	—		—		6.1		7.5
Settlements	(1.7)		(2.5)		(4.8)		(6.6)
Balance at the end of the period	$	3.7	$	4.0	$	3.7	$	4.0

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, 2021				December 31, 2020
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	30.5	$	30.4	$	32.3
Long-term debt, including current portion (1)	13,114.9		14,573.8		12,450.5		14,343.2

(1)The carrying amount of long-term debt excludes finance lease obligations of $59.9 million and $63.4 million at September 30, 2021 and December 31, 2020, respectively.

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

NOTE 13—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.


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

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. On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities.


	September 30, 2021				December 31, 2020
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	204.7	$	20.6	$	13.0	$	12.9
FTRs	3.7		—		2.4		—
Coal contracts	38.7		—		1.6		0.8
Interest rate swaps	—		1.7		—		6.8
Total current	247.1		22.3		17.0		20.5

Long-term
Natural gas contracts	17.5		—		0.7		1.2
Coal contracts	5.5		—		0.2		0.4
Total long-term	23.0		—		0.9		1.6
Total	$	270.1	$	22.3	$	17.9	$	22.1

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, 2021			Three Months Ended September 30, 2020
(in millions)	Volumes	Gains		Volumes	Gains (Losses)
Natural gas contracts	39.4 Dth	$	41.2	36.2 Dth	$	(12.0)
FTRs	6.3 MWh	3.0		8.3 MWh	1.1
Total		$	44.2		$	(10.9)

	Nine Months Ended September 30, 2021			Nine Months Ended September 30, 2020
(in millions)	Volumes	Gains		Volumes	Gains (Losses)
Natural gas contracts	147.1 Dth	$	38.5	139.3 Dth	$	(53.9)
FTRs	22.1 MWh	15.3		22.7 MWh	3.1
Total		$	53.8		$	(50.8)

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, 2021 and December 31, 2020, we had posted cash collateral of $10.5 million and $18.9 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2021, we had also received cash collateral of $134.1 million. This amount was recorded on our balance sheet in other current liabilities.


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


	September 30, 2021					December 31, 2020
(in millions)	Derivative Assets			Derivative Liabilities		Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	270.1		$	22.3	$	17.9	$	22.1
Gross amount not offset on the balance sheet	(134.9)		(1)	(1.3)		(6.9)		(7.7)		(2)
Net amount	$	135.2		$	21.0	$	11.0	$	14.4

(1)Includes cash collateral received of $133.6 million.

(2)Includes cash collateral posted of $0.8 million.

Cash Flow Hedges

As of September 30, 2021, 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 income (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)	2021		2020		2021		2020
Derivative loss recognized in other comprehensive loss	$	—	$	—	$	—	$	(5.8)
Net derivative loss reclassified from accumulated other comprehensive loss to interest expense	(1.4)		(1.3)		(4.1)		(2.0)
Total interest expense line item on the income statements	118.0		122.0		357.5		375.8

We estimate that during the next twelve months $0.4 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense.

NOTE 14—GUARANTEES

The following table shows our outstanding guarantees:


			Expiration
(in millions)	Total Amounts Committed at September 30, 2021		Less Than 1 Year		1 to 3 Years		Over 3 Years
Guarantees supporting transactions of subsidiaries (1)	$	125.5	$	51.5	$	1.5	$	72.5
Standby letters of credit (2)	127.2		54.3		—		72.9
Surety bonds (3)	12.8		12.8		—		—
Other guarantees (4)	10.7		—		—		10.7
Total guarantees	$	276.2	$	118.6	$	1.5	$	156.1

(1)Consists of $4.2 million, $8.1 million, and $113.2 million to support the business operations of UMERC, Bluewater, 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.


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(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 $10.7 million related to workers compensation coverage for which a liability was recorded on our balance sheets.

NOTE 15—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)	2021		2020		2021		2020
Service cost	$	13.3	$	12.5	$	40.8	$	37.3
Interest cost	22.2		25.6		65.8		77.8
Expected return on plan assets	(50.1)		(47.4)		(150.8)		(143.0)
Loss on plan settlement	0.9		5.2		2.9		15.5
Amortization of prior service cost	0.4		0.4		1.2		1.2
Amortization of net actuarial loss	26.4		26.1		82.0		75.8
Net periodic benefit cost	$	13.1	$	22.4	$	41.9	$	64.6


	OPEB Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2021		2020		2021		2020
Service cost	$	4.0	$	3.8	$	11.8	$	11.4
Interest cost	3.7		4.7		10.9		14.0
Expected return on plan assets	(16.5)		(15.0)		(49.5)		(45.2)

Amortization of prior service credit	(4.1)		(3.8)		(12.0)		(11.3)
Amortization of net actuarial gain	(5.9)		(5.6)		(18.1)		(16.8)
Net periodic benefit credit	$	(18.8)	$	(15.9)	$	(56.9)	$	(47.9)

During the nine months ended September 30, 2021, we made contributions and payments of $9.8 million related to our pension plans and $1.5 million related to our OPEB plans. We expect to make contributions and payments of $1.9 million related to our pension plans and $0.7 million related to our OPEB plans during the remainder of 2021, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 16—GOODWILL AND INTANGIBLES

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, 2021. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2021.


(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, 2021.

During the third quarter of 2021, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2021. No impairments resulted from these tests.


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Intangible Assets

At September 30, 2021, we had $5.7 million of indefinite-lived intangible assets primarily related to an MGU trade name obtained through an acquisition, which is included in other long-term assets on our balance sheets. We had no changes to the carrying amount of these intangible assets during the nine months ended September 30, 2021.

Intangible Liabilities

The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. See Note 2, Acquisitions, for more information.


	September 30, 2021						December 31, 2020
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	84.3	$	(4.9)	$	79.4	$	76.1	$	—	$	76.1
Proxy revenue swap (2)	7.2		(1.9)		5.3		7.2		(1.3)		5.9
Interconnection agreements (3)	5.1		(0.4)		4.7		5.1		(0.3)		4.8
Total intangible liabilities	$	96.6	$	(7.2)	$	89.4	$	88.4	$	(1.6)	$	86.8

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining life of the PPAs is approximately 11 years.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining life of the proxy revenue swap is approximately seven years.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining life of the interconnection agreements is approximately 19 years.

Amortization related to these intangibles for the three and nine months ended September 30, 2021 was $1.9 million and $5.6 million, respectively. Amortization for the three and nine months ended September 30, 2020 was not significant. Amortization for the next five years is estimated to be:


	For the Years Ending December 31
(in millions)	2022		2023		2024		2025		2026
Amortization to be recorded in operating revenues	$	8.1	$	8.1	$	8.1	$	8.1	$	8.1
Amortization to be recorded in other operation and maintenance	0.2		0.2		0.2		0.2		0.2


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NOTE 17—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, 2021
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,749.7	$	32.3	$	1,782.0
Add: Earnings from equity method investment	41.7		0.6		42.3

Less: Distributions	33.0		—		33.0


Balance at end of period	$	1,758.4	$	32.9	$	1,791.3

	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

	Nine Months Ended September 30, 2021
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,733.5	$	30.8	$	1,764.3
Add: Earnings from equity method investment	124.1		2.1		126.2

Less: Distributions	99.2		—		99.2

Balance at end of period	$	1,758.4	$	32.9	$	1,791.3

	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

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 also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2021		2020		2021		2020
Charges to ATC for services and construction	$	5.5	$	5.7	$	17.2	$	18.7
Charges from ATC for network transmission services	90.3		87.8		270.7		262.7
Net refund from ATC related to FERC ROE orders	8.7		2.3		7.4		10.7


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


(in millions)	September 30, 2021		December 31, 2020
Accounts receivable for services provided to ATC	$	2.1	$	3.7

Accounts payable for services received from ATC	26.9		29.3
Amounts due from ATC for transmission infrastructure upgrades (1)	8.9		4.6

(1)The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of their new solar projects, Badger Hollow II and Badger Hollow I, respectively.

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2021		2020		2021		2020
Income statement data
Operating revenues	$	186.8	$	187.8	$	561.4	$	577.7
Operating expenses	91.3		93.0		278.8		285.7
Other expense, net	28.6		28.1		85.2		82.0
Net income	$	66.9	$	66.7	$	197.4	$	210.0


(in millions)	September 30, 2021		December 31, 2020
Balance sheet data
Current assets	$	87.0	$	92.7
Noncurrent assets	5,539.8		5,400.6
Total assets	$	5,626.8	$	5,493.3

Current liabilities	$	483.0	$	310.8
Long-term debt	2,412.8		2,512.2
Other noncurrent liabilities	398.9		378.2
Members' equity	2,332.1		2,292.1
Total liabilities and members' equity	$	5,626.8	$	5,493.3

NOTE 18—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 2021, 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 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,

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


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▪90% ownership interest in Blooming Grove, located in McLean County, Illinois,

▪85% ownership interest in Tatanka Ridge, located in Deuel County, South Dakota, and

▪90% ownership interest in Jayhawk, under construction in Bourbon and Crawford counties, Kansas.

See Note 2, Acquisitions, for more information on Tatanka Ridge and Jayhawk.

•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, Wisvest LLC, Wisconsin Energy Capital Corporation, WEC Business Services LLC, and also included the operations of WPS Power Development, LLC in 2020 prior to the sale of its remaining solar facilities in the fourth quarter of 2020.

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, 2021 and 2020:


	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, 2021
External revenues	$	1,458.6	$	216.2	$	52.8	$	1,727.6	$	—	$	18.7	$	0.2	$	—	$	1,746.5
Intersegment revenues	—		—		—		—		—		110.8		—		(110.8)		—
Other operation and maintenance	359.1		91.2		19.6		469.9		—		9.9		(4.5)		(1.6)		473.7
Depreciation and amortization	184.4		55.4		9.6		249.4		—		31.2		6.3		(15.3)		271.6
Equity in earnings of transmission affiliates	—		—		—		—		42.3		—		—		—		42.3
Interest expense	137.9		16.5		1.6		156.0		4.8		17.6		24.7		(85.1)		118.0
Income tax expense (benefit)	33.6		7.0		(1.0)		39.6		9.7		5.0		(3.5)		—		50.8
Net income (loss)	197.8		19.1		(2.7)		214.2		27.8		62.8		(16.1)		—		288.7
Net income (loss) attributed to common shareholders	197.5		19.1		(2.7)		213.9		27.8		64.4		(16.1)		—		290.0


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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, 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
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
Income tax expense (benefit)	37.5		(4.0)		(1.2)		32.3		9.0		13.4		(7.8)		—		46.9
Net income (loss)	187.9		13.0		(3.3)		197.6		26.3		62.9		(19.7)		—		267.1
Net income (loss) attributed to common shareholders	187.6		13.0		(3.3)		197.3		26.3		62.9		(19.7)		—		266.8


	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, 2021
External revenues	$	4,497.8	$	1,195.1	$	358.2	$	6,051.1	$	—	$	62.6	$	0.4	$	—	$	6,114.1
Intersegment revenues	—		—		—		—		—		338.0		—		(338.0)		—
Other operation and maintenance	1,047.1		291.3		64.0		1,402.4		—		31.2		(9.1)		(7.1)		1,417.4
Depreciation and amortization	540.4		162.1		28.2		730.7		—		93.5		19.3		(44.3)		799.2
Equity in earnings of transmission affiliates	—		—		—		—		126.2		—		—		—		126.2
Interest expense	417.8		49.6		4.6		472.0		14.5		53.5		73.5		(256.0)		357.5
Income tax expense (benefit)	104.8		64.4		8.2		177.4		28.9		5.8		(32.3)		—		179.8
Net income (loss)	601.2		174.8		24.5		800.5		82.8		202.3		(10.9)		—		1,074.7
Net income (loss) attributed to common shareholders	600.3		174.8		24.5		799.6		82.8		204.6		(10.9)		—		1,076.1


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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
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
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
Income tax expense (benefit)	110.5		47.7		8.7		166.9		33.4		35.8		(45.4)		—		190.7
Net income (loss)	565.0		152.4		25.8		743.2		84.8		193.2		(59.4)		—		961.8
Net income (loss) attributed to common shareholders	564.1		152.4		25.8		742.3		84.8		193.2		(59.4)		—		960.9

NOTE 19—VARIABLE INTEREST ENTITIES

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

We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, 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.

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to WE's retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized WE to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is a wholly-owned subsidiary of WE.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge, and funds on deposit in trust accounts, are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to WE or any of WE's affiliates. See Note 9, Long-Term Debt, for more information on the ETBs.

WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, WE is authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. WE remits all collections of the environmental control charge to an indenture trustee of WEPCo Environmental Trust.


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WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, WE has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, WE is considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet.


(in millions)	September 30, 2021
Assets
Other current assets (restricted cash)	$	4.6
Regulatory assets	102.9
Other long-term assets (restricted cash)	0.6

Liabilities
Current portion of long-term debt	8.5
Other current liabilities (accrued interest)	0.7
Long-term debt	107.0

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 VIE 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, 2021 and December 31, 2020, our equity investment in ATC was $1,758.4 million and $1,733.5 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 VIE 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, 2021 and December 31, 2020, our equity investment in ATC Holdco was $32.9 million and $30.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, 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 PPA 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 one year. 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 PPA.

We have $6.5 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 20—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.


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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.

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. In order to support these sales obligations, these companies enter into easements and other service agreements associated with the wind generating facilities.

Our minimum future commitments related to these purchase obligations as of September 30, 2021, including those of our subsidiaries, were approximately $10.8 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, NOx, 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

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard. Under Executive Order 13990, the Biden Administration ordered that all agencies review existing regulations, orders, guidance documents, policies, and similar actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021. Consequently, the December 2020 decision to retain the 2015 ozone standards with no changes is currently under review by the EPA.

The EPA issued final nonattainment area designations for the 2015 ozone standard in April 2018. The following counties within our Wisconsin service territories were designated as partial nonattainment: Door, Kenosha, Sheboygan, 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. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. As a result of the July 2020 remand, in June 2021, the EPA published its final action to revise the boundaries for 13 counties associated with six nonattainment areas, including several in Illinois and Wisconsin. Under the new designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the nonattainment area. Additionally, the Chicago, Illinois, Indiana, and Wisconsin nonattainment area now includes an expanded portion of Kenosha county, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties have also been expanded. Preliminary 2019-2021 monitoring data indicates that the Milwaukee, Sheboygan, and Chicago nonattainment areas will likely be adjusted to "moderate" nonattainment for the 2015 standard.

In February 2021, the WDNR proposed draft revisions to the Wisconsin Administrative Code to adopt the 2015 ozone standard and incorporate by reference the federal air pollution monitoring requirements related to the NAAQS. The Natural Resources Board adopted the rule as proposed during their June 2021 meeting and the rule is now in legislative review. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with associated state or federal rules.


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Particulate Matter

In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including fine particulate matter. The EPA determined that no revisions were necessary to the current standard. This determination was also subject to review under Executive Order 13990 and in June 2021, the EPA announced it would reconsider the December 2020 decision. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the particulate matter NAAQS to below the current level of 12 micrograms per cubic meter, while retaining the 24-hour standard. A proposed rule-making is expected in summer 2022, and a final rule is expected in spring 2023. All counties within our service territories are in attainment with the current 2012 standards.

Climate Change

The ACE rule, effective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the Clean Power Plan and provided existing coal-fired generating units with standards for achieving GHG emission reductions. In a memorandum issued to the EPA regional administrators in February 2021, the EPA stated that the D.C. Circuit Court decision meant that no existing rule regulates GHG emissions from electric generating units. The EPA is currently reviewing its options for such regulations and has signaled that a draft rule will not be ready until 2022 at the earliest. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling vacating the EPA's ACE rule. The Supreme Court will review a number of issues regarding the scope of the EPA's regulatory authority to utilize Section 111(d) of the CAA to address CO2 emissions. Arguments are expected to take place in early 2022 with a decision expected by the summer of 2022.

In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The rule became effective in March 2021; however, the EPA asked the D.C. Circuit Court of Appeals to vacate and remand the final rule, which was granted by the D.C. Circuit Court of Appeals in April 2021. Despite this uncertainty, we continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation by 2025. By the end of 2020, we were able to reduce CO2 emissions from our electric generation fleet by more than 50% below 2005 levels. As a result, we announced new goals in May 2021. We committed to a 60% reduction in carbon emissions from our electric generation fleet by 2025 and an 80% reduction by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero carbon emissions by 2050. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. As part of the ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of OCPP Units 5-8 and the jointly-owned Columbia Units 1-2.

We continue to reduce methane emissions by improving our natural gas distribution system. Our initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, we set a new target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

Cross-State Air Pollution Rule Update Rule Revision

In 2015, the EPA determined that several upwind states had failed to submit state implementation plans that addressed their "Good Neighbor" obligations (i.e., the states projected NOx emissions significantly contribute to a continuing downwind nonattainment and/or maintenance problem); therefore, by statute, the EPA was required to issue a federal implementation plan. In March 2021, the EPA finalized a CSAPR update rule revision that keeps nine of the 21 CSAPR affected states (including Wisconsin) in a Group 2 NOx ozone season trading program and found that the prior CSAPR update is sufficient to meet Wisconsin's "Good Neighbor" obligations. No further NOx reductions will be needed within these nine states. This rule became effective June 29, 2021 and did not have a material impact on our financial condition or results of operations.


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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act 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 federal 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. In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code. This new state rule became effective in June 2020, and the WDNR will apply this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into Wisconsin Pollutant Discharge Elimination System permits for WE and WPS facilities.

We have received BTA determinations for OC 5 through OC 8 and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station satisfies the BTA requirements, a final determination will not be made until the discharge permit is renewed for this facility, which is expected to be in the second quarter of 2022. We have received interim BTA determinations for Weston Units 2, 3, and 4. A final BTA decision for the Weston facility is expected during its next permit renewal in late 2023.

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 continue to meet this regulation and do not expect to incur significant additional compliance costs.

Steam Electric Effluent Limitation Guidelines

The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. 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. 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 facility modifications to meet water permit requirements for the BATW systems at Weston Unit 3 and OC 7 and OC 8. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the OCPP and ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require approximately $110 million in capital investment. In February 2021, we applied for PSCW approval of this project.

In July 2021, the EPA announced that it intends to initiate rulemaking to revise the ELG Rule as modified in 2020. The EPA has stated that the ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process. The EPA plans to propose a revised rule in the fall of 2022.

Waters of the United States

In September 2021, the EPA and the United States Army Corps of Engineers together announced they have halted implementation of the April 2020 Navigable Waters Protection Rule and are interpreting "Waters of the United States" consistent with the pre-2015 regulatory regime until further notice. The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction. We continue to move forward on company projects subject to federal permits and will monitor these actions to better understand potential future impacts.

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.


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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, 2021		December 31, 2020
Regulatory assets	$	601.9	$	638.2
Reserves for future environmental remediation	510.3		532.9

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.

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.

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, 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 Company, 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. Wisconsin Power and Light Company has started the process to close out this Consent Decree.


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NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION


	Nine Months Ended September 30
(in millions)	2021		2020
Cash paid for interest, net of amount capitalized	$	310.9	$	332.4
Cash paid for income taxes, net	33.8		27.6
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	144.0		177.8
Increase in receivable related to insurance proceeds for property damage (1)	58.3		—

(1)See Note 6, Property, Plant, and Equipment, for information about a steam incident at WE's PSB.

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 consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WECI Wind Holding I and WEPCo Environmental Trust. The restricted cash we received when WECI acquired ownership interests in certain wind generation projects is included in our restricted cash as well. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the wind generation facilities.

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, 2021		December 31, 2020
Cash and cash equivalents	$	26.0	$	24.8
Restricted cash included in other current assets	36.4		—
Restricted cash included in other long term assets	46.8		47.8
Cash, cash equivalents, and restricted cash	$	109.2	$	72.6

NOTE 22—REGULATORY ENVIRONMENT

Recovery of Natural Gas Costs

Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. All of our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs.

On March 23, 2021, WE and WG requested approval from the PSCW to recover approximately $54 million and $24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs. On March 30, 2021, the PSCW approved the requests and both WE and WG recovered these excess costs over a period of three months, beginning in April 2021. In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in its GCRM. WPS recovered these excess costs over a period of three months, beginning in April 2021.

PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs are being recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs will be reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation, which we expect to file with the ICC in April 2022.

In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In July 2021, MERC and four other Minnesota utilities filed a joint proposal with the MPUC to recover their respective excess natural gas costs. Under the proposal, MERC will recover $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million over 27 months, both beginning in September 2021. On August 30, 2021, the MPUC issued a written order approving this proposal; however, recovery of these costs and the issue of prudence has been referred to a contested-case proceeding. As a result of the proceeding, the MPUC could disallow recovery or order the refund of any costs determined to be imprudent. A decision regarding this review is expected in August 2022.


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Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant.

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 all issued written orders requiring certain actions to ensure that essential utility services were available to customers in their respective jurisdictions. A summary of these orders is included below.

Wisconsin

In March 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 in March 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 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. See Note 4, Credit Losses, for information regarding changes to our allowance for credit losses. As of September 30, 2021, the total amount deferred at our Wisconsin utilities related to the COVID-19 pandemic was not significant. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings.

In June 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 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.

Subsequent to the June 2020 order, 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 began on November 1, 2020 and ended on April 15, 2021. Utilities were allowed to continue assessing late payment fees during the winter moratorium. On April 5, 2021, the PSCW issued a written order indicating that it would not extend the moratorium on disconnections further; therefore, utilities could begin disconnecting residential customers for non-payment after April 15, 2021. Utilities are required to offer a deferred payment arrangement to low-income residential customers prior to disconnecting service. The order also allowed our Wisconsin utilities to resume charging late payment fees on the full balance of all outstanding arrears, regardless of the associated dates the service was provided, after April 15, 2021.

Illinois

In March 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.


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In June 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 were 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 were waived for an additional four months for residential customers that verbally expressed financial hardship.

•PGL and NSG were required to establish 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 approved in June 2020 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, 2021, PGL's and NSG's regulatory assets related to the COVID-19 pandemic were $25.3 million, collectively.

Subsequent to the approval of the June 2020 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 began on December 1, 2020 and ended on March 31, 2021.

In March 2021, the ICC issued a written order approving a second settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of this new settlement agreement were as follows:

•Utilities could start sending disconnection notices, on a staggered basis, as of April 1, 2021. Disconnections were done on a staggered schedule based on customer arrears and income levels (e.g. low income versus non-low income customers). Utilities were not allowed to disconnect customers for non-payment prior to June 30, 2021 if the customer's household income was below 300% of the federal poverty level and the customer was on a deferred payment plan.

•Utilities were required to continue offering flexible deferred payment arrangements with reduced down payment requirements to residential customers through June 30, 2021.

•Reconnection fees were waived for eligible low income customers through June 30, 2021. In addition, utilities will continue to exempt eligible low income customers from late payment fees and deposits.

•Each utility was required to continue, or renew, its bill payment assistance program through 2021. In addition to the $12.0 million PGL initially funded, PGL was required to fund an additional $6.0 million to its bill payment assistance program. No additional funding was required for NSG due to the amount still available for assistance from its initial funding. During April 2021, PGL's bill payment assistance program ended as all $18.0 million of funds were exhausted. NSG's bill payment assistance program ended in August 2021 when its funds were exhausted.

•Costs related to the provisions in the settlement agreement, including costs related to the bill payment assistance programs, are recoverable through the SPC rider.

Minnesota

In May 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, 2021, amounts deferred at MERC related to the COVID-19 pandemic were not significant.

In June 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. In August 2020, the MPUC issued a written order affirming these temporary provisions. Prior to the June 2020 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


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suspending disconnections and waiving late payment fees for residential and small commercial and industrial customers that entered into payment plans.

In March 2021, the MPUC issued an order requiring Minnesota utilities to file a transition plan to resume collections and disconnections upon the earlier of an Executive Secretary finding the transition plan was complete, or 90 days following the expiration of Minnesota's declared peacetime emergency. MERC filed its transition plan in April 2021, and it was subsequently deemed complete by the Executive Secretary. In accordance with the transition plan, MERC resumed disconnections on August 2, 2021. MERC will not disconnect residential customers with past due balances if the customer has a pending application or has been deemed eligible for a financial assistance program. In addition, MERC will continue to offer flexible deferred payment arrangements to residential customers. For customers who enter, or are complying with, a payment arrangement, MERC will not impose any service deposits, down payments, interest, late payment fees, or reconnections fees through April 30, 2022.

Michigan

In April 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 included the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities were required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19.

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

The April 2020 MPSC order also authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeded the amounts being recovered in rates. In July 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 could still seek recovery of these costs and foregone revenues by filing additional information on the specifics of their request. MGU and UMERC filed comments with the MPSC in November 2020 indicating they had not experienced any material additional COVID-19 related expenses or foregone revenues, but will continue to monitor them and will notify the MPSC if they become material. At September 30, 2021, our Michigan utilities had not recorded any deferrals related to the COVID-19 pandemic.

In June 2021, MGU and UMERC worked with MPSC staff to develop a transition plan to resume collections and disconnections, while continuing to assist customers in managing their arrears balances. In accordance with the agreed upon transition plan, MGU and UMERC resumed pre-pandemic collection activities and residential service disconnections on August 2, 2021. Flexible deferred payment arrangements will continue to be available to customers.

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

2022 Rates

In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that will allow them to maintain their current electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year. In connection with the request, the three utilities also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. On September 22, 2021, the PSCW issued written orders approving the application.

The final orders reflect the following:

•WE, WPS, and WG will amortize, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies.

•WG will defer interest and depreciation expense associated with capital investments since its last rate case that otherwise would have been added to rate base in a 2022 test-year rate case.

•WE, WPS, and WG are allowed to defer any increases in tax expense due to changes in tax law that occur in 2021 and/or 2022.


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•WE, WPS, and WG will maintain their earnings sharing mechanisms for 2022, with modification. The earnings sharing mechanisms will be modified to authorize the utility to retain 100% of the first 15 basis points of earnings above its currently authorized ROE. This modification expires on December 31, 2022. The earnings sharing mechanisms will otherwise remain as currently authorized.

•WE, WPS, and WG will file a full 2023-2024 test-year rate case no later than May 1, 2022.

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 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 were amortized in 2020 and approximately $39 million are being amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of certain of WE's 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 are being made to customers evenly over two years, with half returned in 2020 and the remainder being returned 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 in July 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 financing fees. In November 2020, the PSCW issued a written order approving the application. The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs. In May 2021, WEPCo Environmental Trust issued $118.8 million of 1.578% ETBs due December 15, 2035. See Note 9, Long-Term Debt, for more information regarding the issuance of the ETBs. See Note 19, Variable Interest Entities, for more information regarding WEPCo Environmental Trust.

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.

The PSCW approved all three Wisconsin utilities continuing to have 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 this earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the


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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.

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

Third-Party Transaction Fee Adjustment Rider

On October 27, 2021, PGL and NSG filed requests with the ICC for approval of a TPTFA rider. In accordance with the Climate and Equitable Jobs Act that was signed into law in Illinois, effective September 15, 2021, utilities are prohibited from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses. The proposed TPTFA rider would allow PGL and NSG to recover the third-party transaction fee expenses they are now incurring. If approved, the TPTFA rider would be effective for expenses incurred back to September 15, 2021. Amounts deferred under the rider would be recovered over a period of 12 months and would be subject to an annual reconciliation whereby costs would be reviewed by the ICC for accuracy and prudency. We expect a decision from the ICC in 2022.

North Shore Gas Company 2021 Rate Case

In October 2020, NSG filed a request with the ICC to increase its natural gas rates. On September 8, 2021, the ICC issued a written order authorizing a rate increase of $4.1 million (4.5%). The rate increase reflects a 9.67% ROE and a common equity component average of 51.58%. The 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 28, 2015. The new rates were effective September 15, 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 2021, PGL filed its 2020 reconciliation with the ICC, which, along with the 2019, 2018, 2017, and 2016 reconciliations, are still pending.

As of September 30, 2021, 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.

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 delay its filing of the rate case as a result of the COVID-19 pandemic.

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 are helping to mitigate the impacts from delaying the filing of the rate case.

In March 2021, MGU filed its request with the MPSC to increase its natural gas rates. In July 2021, MGU filed with the MPSC, a settlement agreement it reached with certain intervenors, which the MPSC approved in a written order on September 9, 2021. The order authorizes a rate increase of $9.3 million (6.35%) and reflects a 9.85% ROE and a common equity component average of 51.5%. The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its last rate review that resulted in revised base rates effective January 1, 2016. The order also allows MGU to implement a rider for its Main Replacement Program that will support recovery of planned capital investment related to pipeline replacements to maintain system


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safety and reliability between 2023 and 2027, without having to file a rate case. We expect approximately $31.7 million of costs to be recovered through this rider. All costs recovered through the rider are subject to prudence review by the MPSC. New rates will be effective January 1, 2022.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

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 was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant 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 2020 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 Federal Energy Regulatory Commission and certain state regulatory commissions), and non-utility energy infrastructure operations through W.E. Power, LLC (which owns generation assets in Wisconsin), Bluewater Natural Gas Holding, LLC (which owns underground natural gas storage facilities in Michigan), and WEC Infrastructure LLC (WECI), which holds ownership interests in several wind generating facilities.

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: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. Our capital investment plan for efficiency, sustainability and growth, referred to as our ESG Progress Plan, provides a roadmap for us to achieve 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.

Throughout our strategic planning process, we take into account important developments, risks and opportunities, including new technologies, customer preferences and commodity prices, energy resiliency efforts, and sustainability. We published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to our company and its stakeholders over the short and long terms. Our risk and priority assessments have formed our direction as a company.

Creating a Sustainable Future

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables 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 our goals to reduce carbon dioxide (CO2) emissions from our electric generation.

By the end of 2020, we were able to reduce CO2 emissions from our electric generation fleet by more than 50% below 2005 levels. As a result, we announced new goals in May 2021. We committed to a 60% reduction in carbon emissions from our electric generation fleet by 2025 and an 80% reduction by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero CO2 emissions by 2050.

In addition, we are exploring co-firing with natural gas at our ERGS coal-fired units. By the end of 2030, we expect our use of coal will account for less than 5% of the power we supply to our customers, and we believe we will be in a position to eliminate coal as an energy source by 2035.

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 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of Oak Creek Power Plant Units 5-8 and the jointly-owned Columbia Units 1-2.


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In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $3.5 billion from 2022-2026 in regulated renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

•1,500 MW of utility-scale solar;

•800 MW of battery storage; and

•100 MW of wind.

We also plan on investing in a combination of clean, natural gas-fired generation, including:

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

•the planned purchase of 200 MW of capacity in the West Riverside Energy Center — a new, combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin.

For more details, see Liquidity and Capital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.

In addition, we previously received approval from the Public Service Commission of Wisconsin (PSCW) 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), now in service, and Badger Hollow Solar Park I (Badger Hollow I), expected to enter commercial operation in the fourth quarter of 2021. WPS owns 100 MW of Two Creeks and will own 100 MW of Badger Hollow I for a total of 200 MW. Wisconsin Electric Power Company (WE) has partnered with an unaffiliated utility to construct Badger Hollow Solar Park II that is expected to enter commercial operation in December 2022. Once constructed, WE will own 100 MW of this project.

In December 2018, WE received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 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, WE has energized 20 Solar Now projects and currently has another four under construction, together totaling more than 27 MW. 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 helping these larger customers meet their sustainability and renewable energy goals.

In August 2021, the PSCW approved pilot programs for WE and WPS to install and maintain electric vehicle (EV) charging equipment for customers at their homes or businesses. The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment. In October 2021, subject to the receipt of any necessary regulatory approvals, we pledged to expand the EV charging network within the service territories of our electric utilities. In doing so, we joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition we joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

We also continue to reduce methane emissions by improving our natural gas distribution system. Our initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, we set a new target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

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, as well as our electric and natural gas distribution networks to further improve reliability.

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

•WE constructed approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, called the Lakeshore Lateral Project, was completed in October 2021.


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•WE and Wisconsin Gas LLC (WG) each plan to construct their own liquefied natural gas (LNG) facilities to meet anticipated peak demand. Subject to PSCW approval, 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 is in the final year of its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. WE, WPS, and WG also continue to upgrade their electric and natural gas distribution systems to enhance reliability.

For more details, see Liquidity and Capital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.

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.

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.

Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. In our non-utility energy infrastructure segment, we have acquired or agreed to acquire majority interests in eight wind parks, capable of providing more than 1,550 MW of carbon-free energy in total. These renewable energy assets represent more than $2.3 billion in committed investments and have long-term agreements to serve customers outside our traditional service areas. Production tax credits from these wind investments reduce our cash tax expense. See Note 2, Acquisitions, for additional information on recent transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $16.4 billion from 2022 to 2026. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be $1.3 billion. Specific projects included in the $17.7 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.

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.

A multiyear effort is driving a standardized, seamless approach to digital customer service across our companies. We have moved all utilities to a common platform for all customer-facing self-service options. Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service to customers.


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Safety

Safety is one of our core values and a critical component of our culture. We are committed to keeping our employees and the public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across our companies.

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.

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2021

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2021 with the third quarter of 2020, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2021		2020		B (W)
Wisconsin	$	197.5	$	187.6	$	9.9
Illinois	19.1		13.0		6.1
Other states	(2.7)		(3.3)		0.6
Electric transmission	27.8		26.3		1.5
Non-utility energy infrastructure	64.4		62.9		1.5
Corporate and other	(16.1)		(19.7)		3.6
Net income attributed to common shareholders	$	290.0	$	266.8	$	23.2

Diluted earnings per share	$	0.92	$	0.84	$	0.08

Earnings increased $23.2 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the $23.2 million increase in earnings were:

•A $9.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by lower benefit costs and an increase in electric margins due to higher retail sales volumes, including the impact of weather. The positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove an increase in earnings. See Note 22, Regulatory Environment, for more information on the Wisconsin rate orders. These positive impacts were partially offset by higher depreciation and amortization during the third quarter of 2021 and the negative quarter-over-quarter impact from collections of fuel and purchased power costs compared with costs approved in rates.

•A $6.1 million increase in net income attributed to common shareholders at the Illinois segment, driven by lower benefit costs and higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider. These increases in earnings were partially offset by the impact from the change in unrecognized tax benefits recorded during the third quarter of 2020.

•A $3.6 million increase in earnings from the corporate and other segment, driven by the positive quarter-over-quarter impact from charges taken at Wispark during 2020 and lower interest expense. These positive impacts were partially offset by lower net gains from investments held in the Integrys rabbi trust. The investment gains from the rabbi trust offset benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.


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Non-GAAP Financial Measures

The discussions below address the contribution of each of our segments to net income attributed to common shareholders. The discussions 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 margins (electric revenues less fuel and purchased power costs) and natural gas margins (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 (loss) as determined in accordance with GAAP as an indicator of operating performance. The following table shows operating income (loss) by segment for our utility operations during the third quarter of 2021 and 2020:


	Three Months Ended September 30
(in millions)	2021		2020
Wisconsin	$	352.8	$	349.0
Illinois	40.7		24.5
Other states	(2.2)		(2.0)

Each applicable segment discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to the most directly comparable GAAP measure, operating income (loss).


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Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $197.5 million during the third quarter of 2021, representing a $9.9 million, or 5.3%, increase over the same quarter in 2020. The higher earnings were driven by lower benefit costs and an increase in electric margins due to higher retail sales volumes, including the impact of weather. The positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove an increase in earnings. See Note 22, Regulatory Environment, for more information on the Wisconsin rate orders. These positive impacts were partially offset by higher depreciation and amortization during the third quarter of 2021 and the negative quarter-over-quarter impact from collections of fuel and purchased power costs compared with costs approved in rates.


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Electric revenues	$	1,288.2	$	1,215.4	$	72.8
Fuel and purchased power	437.7		374.0		(63.7)
Total electric margins	850.5		841.4		9.1

Natural gas revenues	170.4		150.9		19.5
Cost of natural gas sold	87.3		67.1		(20.2)
Total natural gas margins	83.1		83.8		(0.7)

Total electric and natural gas margins	933.6		925.2		8.4

Other operation and maintenance	359.1		363.8		4.7
Depreciation and amortization	184.4		169.7		(14.7)
Property and revenue taxes	37.3		42.7		5.4
Operating income	352.8		349.0		3.8

Other income, net	16.5		15.5		1.0
Interest expense	137.9		139.1		1.2
Income before income taxes	231.4		225.4		$	6.0

Income tax expense	33.6		37.5		3.9
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	197.5	$	187.6	$	9.9

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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line items below	$	169.4	$	170.6	$	1.2
Transmission (1)	127.8		129.4		1.6
Regulatory amortizations and other pass through expenses (2)	34.4		34.5		0.1
We Power (3)	27.5		29.3		1.8

Total other operation and maintenance	$	359.1	$	363.8	$	4.7

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. 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, 2021 and 2020, $122.7 million and $125.0 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 net income.


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(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, 2021 and 2020, $20.4 million and $24.1 million, respectively, of 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.

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	2021	2020	B (W)
Customer Class
Residential	3,374.1	3,364.4	9.7
Small commercial and industrial (1)	3,527.7	3,409.0	118.7
Large commercial and industrial (1)	3,239.2	3,163.5	75.7
Other	31.3	34.3	(3.0)
Total retail (1)	10,172.3	9,971.2	201.1
Wholesale	744.0	843.6	(99.6)
Resale	1,270.3	1,730.7	(460.4)
Total sales in MWh (1)	12,186.6	12,545.5	(358.9)

(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	2021	2020	B (W)
Customer Class
Residential	56.6	64.4	(7.8)
Commercial and industrial	52.4	55.3	(2.9)
Total retail	109.0	119.7	(10.7)
Transportation	280.5	264.5	16.0
Total sales in therms	389.5	384.2	5.3


	Three Months Ended September 30
	Degree Days
Weather	2021	2020	B (W)
WE and WG (1)
Heating (104 Normal)	22	103	(78.6)	%
Cooling (581 Normal)	715	708	1.0	%

WPS (2)
Heating (185 Normal)	114	198	(42.4)	%
Cooling (389 Normal)	389	471	(17.4)	%

UMERC (3)
Heating (311 Normal)	232	339	(31.6)	%
Cooling (260 Normal)	270	311	(13.2)	%

(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 $9.1 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the higher electric utility margins were:

•A $14.8 million increase in margins related to higher retail sales volumes, including the impact of weather. As measured by cooling degree days, the third quarter of 2021 was 1.0% warmer than the same quarter in 2020 in the Milwaukee area. Commercial and industrial retail sales volumes also improved during the third quarter of 2021, compared with the same quarter in 2020, due to the continued economic recovery in Wisconsin from the COVID-19 pandemic.

•A $7.5 million increase in margins from other revenues, primarily related to higher revenues from third party use of our assets as well as higher late payment charges during the third quarter of 2021. Our Wisconsin utilities resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 22, Regulatory Environment, for more information.

•Securitization revenues of $3.8 million received during the third quarter of 2021 related to an environmental control charge from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 9, Long-Term Debt, and Note 19, Variable Interest Entities, for more information. These revenues are all offset in depreciation and amortization as well as interest expense.

•A $0.6 million net increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW. The positive impact of increased rates from the rate orders was partially offset by a $7.5 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers over two years and is offset in income taxes. See Note 22, Regulatory Environment, for more information.

These increases in margins were partially offset by:

•A $9.8 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is deferred for future recovery or refund to customers.

•Lower margins of $9.7 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $0.7 million during the third quarter of 2021, compared with the same quarter in 2020. The most significant factor impacting the lower natural gas utility margins was lower retail sales volumes, primarily driven by warmer weather during the third quarter of 2021. As measured by heating degree days, the third quarter of 2021 was 78.6% and 42.4% warmer than the same quarter in 2020 in the Milwaukee area and Green Bay area, respectively.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Wisconsin segment increased $4.6 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the increase in operating expenses were:

•A $14.7 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. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.

•A $9.9 million increase in electric and natural gas distribution expenses, primarily driven by significant summer storms in 2021.


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•A $4.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

These increases in operating expenses were partially offset by a $23.1 million decrease in benefit costs, primarily due to lower stock-based compensation and deferred compensation costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $1.2 million during the third quarter of 2021, compared with the same quarter in 2020, primarily due to lower interest expense on finance lease liabilities. This decrease was partially offset by interest expense on the ETBs issued by WEPCo Environmental Trust in May 2021, which is offset in revenues. See Note 19, Variable Interest Entities, for more information.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $3.9 million during the third quarter of 2021, compared with the same quarter in 2020. The decrease in income tax expense was due to an approximate $7 million positive impact related to the 2021 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. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as there was an offsetting negative impact in operating income. Partially offsetting this decrease in income tax expense was an increase in pretax income. See Note 11, Income Taxes, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $19.1 million during the third quarter of 2021, representing a $6.1 million, or 46.9%, increase over the same quarter in 2020. The increase was driven by lower benefit costs and higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider. These increases in earnings were partially offset by the impact from the change in unrecognized tax benefits recorded during the third quarter of 2020.

Since the majority of PGL and NSG customers use natural gas for heating, net income attributed to common shareholders at the Illinois segment is sensitive to weather and is generally higher during the winter months.


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Natural gas revenues	$	216.2	$	221.9	$	(5.7)
Cost of natural gas sold	22.4		32.3		9.9
Total natural gas margins	193.8		189.6		4.2

Other operation and maintenance	91.2		109.2		18.0
Depreciation and amortization	55.4		49.9		(5.5)
Property and revenue taxes	6.5		6.0		(0.5)
Operating income	40.7		24.5		16.2

Other income, net	1.9		0.1		1.8
Interest expense	16.5		15.6		(0.9)
Income before income taxes	26.1		9.0		17.1

Income tax expense (benefit)	7.0		(4.0)		(11.0)
Net income attributed to common shareholders	$	19.1	$	13.0	$	6.1


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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in the line items below	$	76.2	$	92.6	$	16.4
Riders (1)	15.5		17.2		1.7
Regulatory amortizations (1)	(0.5)		(0.6)		(0.1)

Total other operation and maintenance	$	91.2	$	109.2	$	18.0

(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net 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	2021	2020	B (W)
Customer Class
Residential	42.8	45.9	(3.1)
Commercial and industrial	24.1	23.0	1.1
Total retail	66.9	68.9	(2.0)
Transportation	87.6	86.1	1.5
Total sales in therms	154.5	155.0	(0.5)


	Three Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
Heating (73 Normal)	18	62	(71.0)	%

(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 $1.7 million impact of the riders referenced in the table above, increased $5.9 million during the third quarter of 2021, compared with the same quarter in 2020. The increase in margins was primarily driven by:

•A $6.2 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL 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.

•A $1.6 million increase in late payment charges driven by the reinstatement of late payment charges during 2021 that were suspended by the ICC in 2020 due to the COVID-19 pandemic.

This increase in natural gas utility margins was partially offset by a $3.4 million decrease in fixed charges during the third quarter of 2021, compared with the same quarter in 2020, driven by higher disconnections during the third quarter of 2021, resulting from the expiration of the moratorium on disconnections from 2020 due to a regulatory order from the ICC in response to the COVID-19 pandemic.

See Note 22, Regulatory Environment, for more information.


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Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Illinois segment decreased $10.3 million, net of the impact of the riders referenced in the table above, during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the decrease in operating expenses were:

•A $9.8 million decrease in benefit costs, primarily due to lower pension and stock-based compensation costs.

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

These decreases in operating expenses were partially offset by a $5.5 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

Other Income, Net

Other income, net at the Illinois segment increased $1.8 million during the third quarter of 2021, compared with the same quarter in 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $0.9 million during the third quarter of 2021, compared with the same quarter in 2020, primarily due to the long-term debt issuance of $200.0 million in November 2020.

Income Tax Expense (Benefit)

Income tax expense at the Illinois segment increased $11.0 million as $7.0 million of income tax expense was recorded during the third quarter of 2021, compared with $4.0 million of income tax benefit recorded during the same quarter in 2020. This increase was due to a $6.3 million change in unrecognized tax benefits in 2020 and an increase in pretax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $2.7 million during the third quarter of 2021, representing a $0.6 million, or 18.2%, decrease in net loss attributed to common shareholders over the same quarter in 2020. The lower net loss was primarily driven by a decrease in interest expense.


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Since the majority of MGU and MERC customers use natural gas for heating, net income attributed to common shareholders at the other states segment is sensitive to weather and is generally higher during the winter months.


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Natural gas revenues	$	52.8	$	48.3	$	4.5
Cost of natural gas sold	21.6		16.9		(4.7)
Total natural gas margins	31.2		31.4		(0.2)

Other operation and maintenance	19.6		20.4		0.8
Depreciation and amortization	9.6		8.5		(1.1)
Property and revenue taxes	4.2		4.5		0.3
Operating loss	(2.2)		(2.0)		(0.2)

Other income, net	0.1		0.2		(0.1)
Interest expense	1.6		2.7		1.1
Loss before income taxes	(3.7)		(4.5)		0.8

Income tax benefit	(1.0)		(1.2)		(0.2)
Net loss attributed to common shareholders	$	(2.7)	$	(3.3)	$	0.6

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


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line item below	$	16.3	$	16.4	$	0.1
Regulatory amortizations and other pass through expenses (1)	3.3		4.0		0.7

Total other operation and maintenance	$	19.6	$	20.4	$	0.8

(1)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net 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	2021	2020	B (W)
Customer Class
Residential	16.0	14.7	1.3
Commercial and industrial	16.7	14.5	2.2
Total retail	32.7	29.2	3.5
Transportation	183.6	146.8	36.8
Total sales in therms	216.3	176.0	40.3


	Three Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
MERC
Heating (206 Normal)	120	243	(50.6)	%

MGU
Heating (113 Normal)	54	131	(58.8)	%

(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.


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Natural Gas Utility Margins

Natural gas utility margins decreased $0.2 million during the third quarter of 2021, compared to the same quarter in 2020. This was primarily driven by a $1.2 million decrease in margin 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. This decrease was partially offset by a $0.7 million increase related to higher weather normalized volumes.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the other states segment was flat during the third quarter of 2021, compared to the same quarter in 2020. This includes an increase of $1.1 million in depreciation and amortization related to continued capital investment, offset by a decrease of $0.8 million in operation and maintenance expense, primarily driven by lower benefits expense.

Interest Expense

Interest expense at the other states segment decreased $1.1 million during the third quarter of 2021, compared with the same quarter in 2020, primarily due to the deferral of interest expense related to capital investments made by MGU since its last rate case. See Note 22, Regulatory Environment, for more information.

Income Tax Benefit

Income tax benefit at the other states segment decreased $0.2 million during the third quarter of 2021, compared with the same quarter in 2020, driven by a lower pretax loss.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	27.8	$	26.3	$	1.5

Net income attributed to common shareholders at our electric transmission segment increased $1.5 million during the third quarter of 2021, compared with the same quarter in 2020. The increase was driven by a $2.2 million increase in equity earnings from transmission affiliates, primarily due to continued capital investment by ATC.

The increase in equity earnings from transmission affiliates was partially offset by a $0.7 million increase in income tax expense during the third quarter of 2021, compared with the same quarter in 2020, driven by an increase in pretax earnings.

Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	64.4	$	62.9	$	1.5

Net income attributed to common shareholders at the non-utility energy infrastructure segment increased $1.5 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factor impacting the increase in net income was:

•An $8.4 million decrease in income tax expense primarily due to a $6.4 million increase in PTCs generated in the third quarter of 2021, driven by our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively, and lower pretax earnings.

This increase in earnings was partially offset by:

•Higher operating losses of $5.6 million at our Coyote Ridge and Tatanka Ridge wind parks due primarily to transmission outages.


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•A $2.6 million increase in interest expense primarily due to WECI Wind Holding I's debt issuance in December 2020.

The majority of earnings from our ownership interests in the wind parks come in the form of the wind PTCs discussed previously.

Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2021		2020		B (W)
Net loss attributed to common shareholders	$	(16.1)	$	(19.7)	$	3.6

The net loss attributed to common shareholders at the corporate and other segment decreased $3.6 million during the third quarter of 2021, compared with the same quarter in 2020. The significant factors impacting the lower net loss were:

•A $6.6 million positive impact from operating income at Wispark during the third quarter of 2021, compared with an operating loss during the same quarter in 2020. The change was driven by the positive quarter-over-quarter impact from reductions in the carrying value of certain real estate-related note receivables during 2020 as market and other factors indicated the receivables may not be fully recoverable.

•A $5.7 million decrease in interest expense, driven by the issuance of new debt in the second half of 2020 with lower interest rates than the debt retired during 2020. Also contributing to the decrease was lower interest rates on our short-term and variable-rate long-term debt.

These increases in earnings were partially offset by:

•A $5.8 million decrease in other income, net, due to lower net gains from the investments held in the Integrys rabbi trust during the third quarter of 2021, compared with the same quarter in 2020. The investment gains from the rabbi trust offset benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 12, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

• A $4.3 million decrease in income tax benefits during the third quarter of 2021, compared with the same quarter in 2020, driven by a lower pretax loss, and a $2.9 million quarter-over-quarter increase in the interim tax expense recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate.

NINE MONTHS ENDED SEPTEMBER 30, 2021

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2021 with the nine months ended September 30, 2020, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2021		2020		B (W)
Wisconsin	$	600.3	$	564.1	$	36.2
Illinois	174.8		152.4		22.4
Other states	24.5		25.8		(1.3)
Electric transmission	82.8		84.8		(2.0)
Non-utility energy infrastructure	204.6		193.2		11.4
Corporate and other	(10.9)		(59.4)		48.5
Net income attributed to common shareholders	$	1,076.1	$	960.9	$	115.2

Diluted Earnings Per Share	$	3.40	$	3.04	$	0.36


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Earnings increased $115.2 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the $115.2 million increase in earnings were:

•A $48.5 million increase in earnings from the corporate and other segment, driven by lower interest expense, an increase in earnings from our equity method investments in technology and energy-focused investment funds, and the positive period-over-period impact from charges taken at Wispark during 2020. A net increase in certain income tax benefits and higher net gains from investments held in the Integrys rabbi trust also contributed to the increase in earnings.

•A $36.2 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric margins due to higher retail sales volumes, including the impact of weather. Lower benefit costs and the positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization and an increase in electric and natural gas distribution expenses during the nine months ended September 30, 2021.

•A $22.4 million increase in net income attributed to common shareholders at the Illinois segment, driven by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and an increase in late payment charges. Lower benefit costs also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization during the nine months ended September 30, 2021.

•An $11.4 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs generated in 2021, primarily due to our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively. Partially offsetting this increase were higher operating losses at the Coyote Ridge and Tatanka Ridge wind parks, primarily due to transmission outages.

Expected 2021 Annual Effective Tax Rate

We expect our 2021 annual effective tax rate to be between 13.0% and 14.0%, which includes an estimated 6.0% effective tax rate benefit due to the amortization of unprotected excess deferred taxes in connection with the 2019 Wisconsin rate orders. Excluding this estimated effective tax rate benefit, the expected 2021 range would be between 19.0% and 20.0%.

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 operating performance. The following table shows operating income by segment for our utility operations during the nine months ended September 30, 2021 and 2020:


	Nine Months Ended September 30
(in millions)	2021		2020
Wisconsin	$	1,072.0	$	1,053.4
Illinois	283.8		245.6
Other states	36.7		41.4


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Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $600.3 million during the nine months ended September 30, 2021, representing a $36.2 million, or 6.4%, increase over the same period in 2020. The higher earnings were driven by an increase in electric margins due to higher retail sales volumes, including the impact of weather. Lower benefit costs and the positive impact of increased rates from the Wisconsin rate orders approved by the PSCW, which includes the recognition of unprotected excess deferred tax benefits from the Tax Legislation, also drove the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization and an increase in electric and natural gas distribution expenses during the nine months ended September 30, 2021.


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Electric revenues	$	3,482.0	$	3,251.9	$	230.1
Fuel and purchased power	1,133.2		957.2		(176.0)
Total electric margins	2,348.8		2,294.7		54.1

Natural gas revenues	1,015.8		819.5		196.3
Cost of natural gas sold	591.6		395.2		(196.4)
Total natural gas margins	424.2		424.3		(0.1)

Total electric and natural gas margins	2,773.0		2,719.0		54.0

Other operation and maintenance	1,047.1		1,044.0		(3.1)
Depreciation and amortization	540.4		502.7		(37.7)
Property and revenue taxes	113.5		118.9		5.4
Operating income	1,072.0		1,053.4		18.6

Other income, net	51.8		44.3		7.5
Interest expense	417.8		422.2		4.4
Income before income taxes	706.0		675.5		30.5

Income tax expense	104.8		110.5		5.7
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	600.3	$	564.1	$	36.2

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line items below	$	472.8	$	462.5	$	(10.3)
Transmission (1)	383.1		388.2		5.1
Regulatory amortizations and other pass through expenses (2)	104.9		103.8		(1.1)
We Power (3)	86.3		89.5		3.2



Total other operation and maintenance	$	1,047.1	$	1,044.0	$	(3.1)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. 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, 2021 and 2020, $378.1 million and $359.7 million, respectively, of costs were billed to our electric utilities by transmission providers.


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(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net 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, 2021 and 2020, $72.0 million and $84.7 million, respectively, of 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.

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	2021	2020	B (W)
Customer Class
Residential	8,838.5	8,782.2	56.3
Small commercial and industrial (1)	9,699.6	9,299.0	400.6
Large commercial and industrial (1)	9,365.8	8,734.3	631.5
Other	104.9	113.0	(8.1)
Total retail (1)	28,008.8	26,928.5	1,080.3
Wholesale	2,181.4	2,311.4	(130.0)
Resale	4,552.5	5,152.6	(600.1)
Total sales in MWh (1)	34,742.7	34,392.5	350.2

(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	2021	2020	B (W)
Customer Class
Residential	715.0	734.2	(19.2)
Commercial and industrial	439.0	445.9	(6.9)
Total retail	1,154.0	1,180.1	(26.1)
Transportation	1,018.9	979.9	39.0
Total sales in therms	2,172.9	2,160.0	12.9


	Nine Months Ended September 30
	Degree Days
Weather	2021	2020	B (W)
WE and WG (1)
Heating (4,313 Normal)	3,880	4,023	(3.6)	%
Cooling (745 Normal)	1,018	931	9.3	%

WPS (2)
Heating (4,808 Normal)	4,450	4,644	(4.2)	%
Cooling (526 Normal)	631	656	(3.8)	%

UMERC (3)
Heating (5,475 Normal)	5,115	5,337	(4.2)	%
Cooling (340 Normal)	426	425	0.2	%

(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 $54.1 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the higher electric utility margins were:

•A $55.8 million increase in margins related to higher sales volumes, including the impact of weather. As measured by cooling degree days, the nine months ended September 30, 2021 were 9.3% warmer than the same period in 2020 in the Milwaukee area. Commercial and industrial retail sales volumes also improved during the nine months ended September 30, 2021, compared with the same period in 2020, due to the continued economic recovery in Wisconsin from the COVID-19 pandemic.

•A $13.3 million increase in margins from other revenues, primarily related to higher late payment charges as well as higher revenues from third party use of our assets during the nine months ended September 30, 2021. Our Wisconsin utilities resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 22, Regulatory Environment, for more information.

•Securitization revenues of $4.7 million received during the nine months ended September 30, 2021 related to an environmental control charge from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 9, Long-Term Debt, and Note 19, Variable Interest Entities, for more information. These revenues are all offset in depreciation and amortization as well as interest expense.

These increases in margins were partially offset by:

•Lower margins of $11.7 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.

•An $8.6 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance beyond the 2% price variance is deferred for future recovery or refund to customers.

•A $1.8 million net decrease in margins related to the impact of the Wisconsin rate orders approved by the PSCW. The positive impact of increased rates from the rate orders was more than offset by a $22.9 million negative impact related to unprotected excess deferred taxes, which we agreed to return to customers over two years and is offset in income taxes. See Note 22, Regulatory Environment, for more information.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment decreased $0.1 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a $2.8 million negative impact from lower retail sales volumes. This decrease in margins was partially offset by a $2.5 million increase from other revenues, primarily related to higher late payment charges during the nine months ended September 30, 2021, as discussed above under Electric Utility Margins.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Wisconsin segment increased $35.4 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the increase in operating expenses were:

•A $37.7 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. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.

•A $13.3 million increase in electric and natural gas distribution expenses, primarily driven by significant summer storms in 2021.


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•An $8.3 million increase in customer service expenses, primarily related to additional costs from an information technology project created to improve the billing, call center, and credit collection functions, as well as higher call volumes and metering costs.

•A $4.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

•A $3.7 million increase in property and liability insurance premiums.

These increases in operating expenses were partially offset by:

•A $26.0 million decrease in benefit costs, primarily due to lower stock-based compensation.

•A $5.1 million decrease 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.

Other Income, Net

Other income, net at the Wisconsin segment increased $7.5 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 15, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $4.4 million during the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to lower interest expense on finance lease liabilities and lower interest rates on short-term debt. These decreases in interest expense were partially offset by the interest expense on the ETBs issued by WEPCo Environmental Trust in May 2021, which is offset in revenues.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $5.7 million during the nine months ended September 30, 2021, compared with the same period in 2020. The decrease was primarily due to an approximate $20 million positive impact related to the 2021 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. The impact due to the benefit from the amortization of the unprotected excess deferred tax benefits from the Tax Legislation did not impact earnings as there was an offsetting negative impact in operating income. Partially offsetting this decrease in income tax expense was an increase in pretax income and a decrease in PTCs.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $174.8 million during the nine months ended September 30, 2021, representing a $22.4 million, or 14.7%, increase over the same period in 2020. The increase was driven by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and an increase in late payment charges. Lower benefit costs also contributed to the increase in earnings. These positive impacts were partially offset by higher depreciation and amortization during the nine months ended September 30, 2021.


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	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Natural gas revenues	$	1,195.1	$	930.7	$	264.4
Cost of natural gas sold	435.0		212.2		(222.8)
Total natural gas margins	760.1		718.5		41.6

Other operation and maintenance	291.3		306.5		15.2
Depreciation and amortization	162.1		146.0		(16.1)
Property and revenue taxes	22.9		20.4		(2.5)
Operating income	283.8		245.6		38.2

Other income, net	5.0		2.2		2.8
Interest expense	49.6		47.7		(1.9)
Income before income taxes	239.2		200.1		39.1

Income tax expense	64.4		47.7		(16.7)
Net income attributed to common shareholders	$	174.8	$	152.4	$	22.4

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in the line items below	$	211.7	$	237.2	$	25.5
Riders (1)	81.3		71.3		(10.0)
Regulatory amortizations (1)	(1.7)		(2.0)		(0.3)

Total other operation and maintenance	$	291.3	$	306.5	$	15.2

(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net 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	2021	2020	B (W)
Customer Class
Residential	572.4	566.8	5.6
Commercial and industrial	226.1	227.5	(1.4)
Total retail	798.5	794.3	4.2
Transport	544.1	552.0	(7.9)
Total sales in therms	1,342.6	1,346.3	(3.7)


	Nine Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
Heating (3,928 Normal)	3,673	3,627	1.3	%

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


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Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $10.0 million impact of the riders referenced in the table above, increased $31.6 million during the nine months ended September 30, 2021, compared with the same period in 2020. The increase in margins was primarily driven by:

•A $19.1 million increase in revenues at PGL due to continued capital investment in the SMP project. PGL 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.

•A $7.9 million increase in late payment charges driven by the reinstatement of late payment charges during 2021 that were suspended by the ICC in 2020 due to the COVID-19 pandemic.

•A $2.5 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Illinois segment decreased $6.6 million, net of the impact of the riders referenced in the table above, during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the decrease in operating expenses were:

•An $18.8 million decrease in benefit costs, primarily due to lower pension and stock-based compensation costs.

•A $5.4 million decrease in costs associated with the investigation and remediation of the natural gas leak at the Manlove Gas Storage Field. See Part II, Other Information, Item 1. Legal Proceedings, for more information.

These decreases in operating expenses were partially offset by:

•A $16.1 million increase in depreciation expense, primarily driven by PGL's continued capital investment in the SMP project.

•A $2.5 million increase in property and revenue taxes driven by an increase in the invested capital tax related to higher plant placed in service during the nine months ended September 30, 2021, compared with the same period in 2020. This increase was offset in natural gas utility margins.

Other Income, Net

Other income, net at the Illinois segment increased $2.8 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

Interest Expense

Interest expense at the Illinois segment increased $1.9 million during the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to the long-term debt issuance of $200.0 million in November 2020.

Income Tax Expense

Income tax expense at the Illinois segment increased $16.7 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by an increase in pretax income and a $6.3 million change in unrecognized tax benefits during 2020.


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Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $24.5 million during the nine months ended September 30, 2021, representing a $1.3 million, or 5.0%, decrease over the same period in 2020. The decrease was driven by higher operating expenses, including increases in depreciation and amortization and customer service expense. These increases were partially offset by decreases in interest expense and benefit costs.

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)	2021		2020		B (W)
Natural gas revenues	$	358.2	$	261.4	$	96.8
Cost of natural gas sold	215.7		119.9		(95.8)
Total natural gas margins	142.5		141.5		1.0

Other operation and maintenance	64.0		62.5		(1.5)
Depreciation and amortization	28.2		24.6		(3.6)
Property and revenue taxes	13.6		13.0		(0.6)
Operating income	36.7		41.4		(4.7)

Other income, net	0.6		0.5		0.1
Interest expense	4.6		7.4		2.8
Income before income taxes	32.7		34.5		(1.8)

Income tax expense	8.2		8.7		0.5
Net income attributed to common shareholders	$	24.5	$	25.8	$	(1.3)

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


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Operation and maintenance not included in line item below	$	48.9	$	49.9	$	1.0
Regulatory amortizations and other pass through expenses (1)	15.1		12.6		(2.5)

Total other operation and maintenance	$	64.0	$	62.5	$	(1.5)

(1)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net 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	2021	2020	B (W)
Customer Class
Residential	208.5	210.1	(1.6)
Commercial and industrial	127.5	131.6	(4.1)
Total retail	336.0	341.7	(5.7)
Transportation	588.6	529.4	59.2
Total sales in therms	924.6	871.1	53.5


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	Nine Months Ended September 30
	Degree Days
Weather (1)	2021	2020	B (W)
MERC
Heating (5,087 Normal)	4,816	5,029	(4.2)	%

MGU
Heating (4,053 Normal)	3,878	3,897	(0.5)	%

Natural Gas Utility Margins

Natural gas utility margins increased $1.0 million during the nine months ended September 30, 2021, compared with the same period in 2020. This was driven by a $2.3 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements. This increase was partially offset by a $0.6 million decrease in revenues due to lower weather normalized sales volumes and lower late payment charges.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the other states segment increased $5.7 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a $3.6 million increase in depreciation and amortization related to continued capital investment. Other operation and maintenance expense also increased $1.5 million, primarily related to MERC's CIP program, which has an offsetting increase in margins. In addition, customer service expense and bad debt expense increased during the first nine months of 2021, partially offset by a decrease in operating expenses due to effective cost control.

Interest Expense

Interest expense at the other states segment decreased $2.8 million during the nine months ended September 30, 2021, compared with the same period in 2020, primarily due to the deferral of interest expense related to capital investments made by MGU since its last rate case. The decrease was partially offset by MERC and MGU's long-term debt issuances in April 2020 of $50.0 million and $60.0 million, respectively. This increase in debt balances was primarily related to continued capital investments.

Income Tax Expense

Income tax expense at the other states segment decreased $0.5 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a decrease in pretax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	82.8	$	84.8	$	(2.0)

Net income attributed to common shareholders at our electric transmission segment decreased $2.0 million during the nine months ended September 30, 2021, compared with the same period in 2020. The decrease was driven by a $6.6 million decrease in equity earnings from transmission affiliates, primarily due to the impact of the FERC order issued in May 2020 addressing complaints related to ATC's ROE. The order resulted in an increase in the base ROE that ATC is allowed to collect, retroactive to November 2013, and increased our equity earnings from ATC by $14.6 million during the nine months ended September 30, 2020. For further discussion of the FERC order, see Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American


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Transmission Company Allowed Return on Equity Complaints. Continued capital investment by ATC partially offset the negative period-over-period impact from the FERC order.

The decrease in equity earnings from transmission affiliates was partially offset by a $4.5 million decrease in income tax expense during the nine months ended September 30, 2021, compared with the same period in 2020, driven by $3.3 million of uncertain tax positions recorded in the second quarter of 2020, and a decrease in pretax earnings.

Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Net income attributed to common shareholders	$	204.6	$	193.2	$	11.4

Net income attributed to common shareholders at the non-utility energy infrastructure segment increased $11.4 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the increase in net income was:

•A $30.0 million decrease in income tax expense primarily due to a $24.3 million increase in PTCs generated in 2021, driven by our Blooming Grove and Tatanka Ridge wind parks that achieved commercial operation in December 2020 and January 2021, respectively, and lower pretax earnings.

This increase in earnings was partially offset by:

•Higher operating losses of $14.5 million at our Coyote Ridge and Tatanka Ridge wind parks due primarily to transmission outages.

•An $8.1 million increase in interest expense primarily due to WECI Wind Holding I's debt issuance in December 2020.

The majority of earnings from our ownership interests in the wind parks come in the form of the wind PTCs discussed previously.

Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2021		2020		B (W)
Net loss attributed to common shareholders	$	(10.9)	$	(59.4)	$	48.5

The net loss attributed to common shareholders at the corporate and other segment decreased $48.5 million during the nine months ended September 30, 2021, compared with the same period in 2020. The significant factors impacting the lower net loss were:

•A $27.4 million increase in other income, net, driven by an $18.1 million increase in earnings from our equity method investments in technology and energy-focused investment funds and $6.4 million of higher net gains from the investments held in the Integrys rabbi trust.

•A $24.6 million decrease in interest expense, driven by the issuance of new debt in the second half of 2020 with lower interest rates than the debt retired during 2020. Also contributing to the decrease was lower interest rates on our short-term and variable-rate long-term debt.

•A $9.6 million positive impact from operating income at Wispark during the nine months ended September 30, 2021, compared with an operating loss during the same period in 2020. The change was driven by the positive period-over-period impact from reductions in the carrying value of certain real estate-related note receivables during 2020 as market and other factors indicated these receivables may not be fully recoverable. Higher gains on the sale of land during the nine months ended September 30, 2021 also contributed to the increase in operating income.

These drivers of the lower net loss were partially offset by a $13.1 million decrease in income tax benefits during the nine months ended September 30, 2021, compared with the same period in 2020, driven by a lower pretax loss and a $5.7 million decrease in excess tax benefits recognized related to stock option exercises. These decreases in income tax benefits were partially offset by a


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$7.6 million decrease in uncertain tax positions and a $3.3 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate, during the nine months ended September 30, 2021, compared with the same period in 2020.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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


(in millions)	2021		2020		Change in 2021 Over 2020
Cash provided by (used in):
Operating activities	$	2,006.7	$	1,949.7	$	57.0
Investing activities	(1,688.7)		(1,563.1)		(125.6)
Financing activities	(281.4)		(407.7)		126.3

Operating Activities

Net cash provided by operating activities increased $57.0 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by:

•A $233.9 million increase in cash due to higher collateral received from counterparties, driven by an increase in the fair value of our natural gas derivative assets during the nine months ended September 30, 2021, compared with the same period in 2020.

•A $24.1 million increase in cash related to higher overall collections from customers as a result of an increase in sales volumes during the nine months ended September 30, 2021, compared with the same period in 2020. This increase was driven by favorable weather and continued economic recovery in Wisconsin from the COVID-19 pandemic. In addition, we continued to recover natural gas costs from our customers related to the extreme weather conditions that occurred in February 2021 in accordance with various orders from our commissions. We expect to recover the majority of these increased gas costs by the end of 2021 through our existing recovery mechanisms. See Note 22, Regulatory Environment, for more information on the recovery of these natural gas costs.

•A $21.5 million increase in cash due to lower cash paid for interest during the nine months ended September 30, 2021, compared with the same period in 2020, driven by the issuance of new debt with lower interest rates than the debt that was retired, as well as lower interest rates on our short-term and variable-rate long-term debt.

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

•A $158.0 million decrease in cash due to higher payments for fuel and purchased power at our plants during the nine months ended September 30, 2021, compared with the same period in 2020. Natural gas costs increased significantly throughout the central part of the country in February 2021 related to extreme weather conditions. In addition to costs related to the extreme weather conditions in February 2021, we incurred higher natural gas costs throughout the nine months ended September 30, 2021, compared with the same period in 2020 as a result of an increase in the price of natural gas. Higher coal costs also drove higher payments for fuel used at our plants.

•A $67.8 million decrease in cash from higher payments for operating and maintenance expenses. During the nine months ended September 30, 2021, our payments were higher for transmission, storm restoration, and customer service.

Investing Activities

Net cash used in investing activities increased $125.6 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by:

•The acquisition of a 90% ownership interest in Jayhawk in February 2021 for $119.8 million. See Note 2, Acquisitions, for more information.


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•Insurance proceeds received of $22.2 million for property damage during the nine months ended September 30, 2020. See Note 6, Property, Plant, and Equipment, for more information.

•A $9.2 million increase in cash paid for capital expenditures during the nine months ended September 30, 2021, compared with the same period in 2020, which is discussed in more detail below.

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

•Capital contributions paid to transmission affiliates of $15.2 million during the nine months ended September 30, 2020. See Note 17, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during the nine months ended September 30, 2021.

•An $11.8 million increase in proceeds received from the sale of assets during the nine months ended September 30, 2021, compared with the same period in 2020.

Capital Expenditures

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


Reportable Segment (in millions)	2021		2020		Change in 2021 Over 2020
Wisconsin	$	1,028.5	$	992.7	$	35.8
Illinois	387.9		494.7		(106.8)
Other states	64.5		104.7		(40.2)
Non-utility energy infrastructure	136.7		12.7		124.0
Corporate and other	10.3		13.9		(3.6)
Total capital expenditures	$	1,627.9	$	1,618.7	$	9.2

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by higher capital expenditures related to upgrades to WE's natural gas distribution system, repairs and restoration of WE's PSB driven by the significant rain event, and WPS's Crane Creek during the nine months ended September 30, 2021. See Note 6, Property, Plant, and Equipment, for more information on the PSB. These increases were partially offset by lower payments for capital expenditures related to Two Creeks, Badger Hollow I, an information technology project created to improve the billing, call center, and credit collection functions, upgrades to WG's gas distribution system, and upgrades of WPS's automated meter reading devices during the nine months ended September 30, 2021.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by lower capital expenditures related to facilities projects, upgrades at the Manlove Gas Storage Field, and upgrades to the natural gas distribution system during the nine months ended September 30, 2021.

The decrease in cash paid for capital expenditures at the other states segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by a decrease in installations of automated meter reading devices during the nine months ended September 30, 2021.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2021, compared with the same period in 2020, was primarily driven by the construction of Jayhawk. See Note 2, Acquisitions, for more information about Jayhawk.

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


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Financing Activities

Net cash used in financing activities decreased $126.3 million during the nine months ended September 30, 2021, compared with the same period in 2020, driven by:

•A $471.3 million increase in cash due to $71.5 million of net borrowings of commercial paper during the nine months ended September 30, 2021, compared with $399.8 million of net repayments of commercial paper during the same period in 2020.

•A $208.8 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2021, compared with the same period in 2020.

•A $126.4 million increase in cash due to lower repayments of long-term debt during the nine months ended September 30, 2021, compared with the same period in 2020.

•A $41.0 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, 2021, compared with the same period in 2020, to satisfy requirements of our stock-based compensation plans.

•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 increases in cash were partially offset by:

•A $680.0 million decrease in cash due to a $340.0 million repayment of a 364-day term loan during the nine months ended September 30, 2021, compared with its issuance during the same period in 2020, to enhance our liquidity position in response to the COVID-19 pandemic.

•A $42.7 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2021, compared with the same period in 2020. In January 2021, our Board of Directors increased our quarterly dividend by $0.045 per share (7.1%) effective with the March 2021 dividend payment.

•A $16.8 million decrease in cash related to the number of stock options exercised during the nine months ended September 30, 2021, compared with the same period in 2020.

Significant Financing Activities

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

Capital Resources and Requirements

Capital Resources

Liquidity

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

We currently have access to the capital markets and have been able to generate funds 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


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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. In March 2021, we repaid the term loan using the net proceeds from the issuance of our 0.80% Senior Notes.

See Note 8, Short-Term Debt and Lines of Credit, for more information about these credit agreements and Note 9, Long-Term Debt, for more information about the issuance of our 0.80% Senior Notes.

The following table shows our capitalization structure as of September 30, 2021, 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	$	10,908.5		$	11,158.5
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	13,174.8			12,924.8
Short-term debt	1,508.9			1,508.9
Total capitalization	$	25,622.6		$	25,622.6

Total debt	$	14,683.7		$	14,433.7

Ratio of debt to total capitalization	57.3		%	56.3		%

Included in long-term debt on our balance sheet as of September 30, 2021, 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, 2021, our current liabilities exceeded our current assets by $1.3 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.

In September 2021, Moody's changed the rating outlook for WG to negative from stable as a result of the decision to defer its next base rate case. The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets. Moody's affirmed WG's ratings including its A3 senior unsecured rating and its P-2 short term rating for commercial paper. See See Note 22, Regulatory Environment, for more information on the rate case delay.


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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 additional impacts from the COVID-19 pandemic, the credit rating agencies could place our or our other subsidiaries’ credit ratings on negative outlook or downgrade 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.

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, 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)	2021 (1)		2022		2023
Wisconsin	$	1,436.5	$	2,131.7	$	2,148.0
Illinois	531.4		573.1		586.8
Other states	104.4		119.1		103.6
Non-utility energy infrastructure	353.5		870.8		325.7
Corporate and other	19.9		22.0		17.5
Total	$	2,445.7	$	3,716.7	$	3,181.6

(1)This includes actual capital expenditures already incurred in 2021, as well as estimated capital expenditures for the remainder of the year.

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. In 2021, WPS expects to invest approximately $50 million on this project at which time it will be substantially complete.

We are committed to investing in solar, wind, battery storage, and clean natural gas-fired generation. Below are examples of projects that are proposed or currently underway.

•We have received approval to invest in 200 MW of utility-scale solar within our Wisconsin segment. WPS has partnered with an unaffiliated utility to construct a solar project, Badger Hollow I, that will be located in Iowa County, Wisconsin. Once constructed, WPS will own 100 MW of this project. WPS's share of the cost of this project is estimated to be approximately $130 million. Commercial operation of Badger Hollow I is expected in the fourth quarter of 2021. 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 approximately $130 million. Commercial operation of Badger Hollow II is targeted for December 2022.

•In February 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $385 million, with construction expected to begin in 2022 and completed by the end of 2023.


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•WE and WPS have received approval to accelerate capital investments in two wind parks. The investment is expected to be approximately $154 million to repower major components of Blue Sky Green Field Wind Park and Crane Creek, which are expected to be completed by the end of 2022.

•In March 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Darien Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 225 MW of solar generation and 68 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $400 million, with construction expected to begin in late 2021 and completed by the end of 2023.

•In March 2021, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Red Barn Wind Park, a utility-scale wind-powered electric generating facility. The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project. If approved, WPS's share of the cost of this project is estimated to be approximately $140 million, with construction expected to begin in early 2022 and completed by the end of 2022.

•In April 2021, WE and WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once constructed, WE and WPS will collectively own 270 MW of solar generation and 149 MW of battery storage of this project. If approved, WE's and WPS's combined share of the cost of this project is estimated to be approximately $585 million, with construction expected to begin in late 2022 and completed by the second quarter of 2024.

•In April 2021, WE and WPS filed an application with the PSCW for approval to construct 128 MWs of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin. The new facility will consist of seven reciprocating internal combustion engines. If approved, we estimate the cost of this project to be approximately $170 million, with construction expected to begin in 2022 and completed in 2023.

WE constructed approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, which was approved by the PSCW in June 2020, was designated as the Lakeshore Lateral Project. The cost of the project was approximately $130 million. Construction for the project began in December 2020 and was completed in October 2021.

WE and WG each plan to construct its own LNG facility. Subject to PSCW approval, each facility would provide approximately one billion cubic foot 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. The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility. If approved, construction is expected to begin by the end of 2021 with commercial operation for the LNG facilities 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 2023 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, Jayhawk, and Sapphire Sky. 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 $105 million from 2021 through 2023. 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 and Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks – United States Department of Commerce Complaint, for additional information on the impacts to our capital projects as a result of the COVID-19 pandemic and the DOC complaint that could impact our solar projects, respectively.


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Common Stock Dividends

Our current quarterly dividend rate is $0.6775 per share, which equates to an annual dividend of $2.71 per share. For information related to our most recent common stock dividend declared, see Note 7, Common Equity.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 8, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 19, 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 2020 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, 2021.

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. This 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 2020 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 are still questions regarding the extent and duration of the COVID-19 pandemic itself, as well as the measures currently in place to try to contain the virus. Shelter-in-place and other orders limiting the capacity of various businesses that were in effect for our service territories have now expired. Similar orders could be adopted in the future depending on how the virus continues to mutate and spread. The effects of the COVID-19 pandemic and related government responses significantly disrupted economic activity in our service territories in 2020 and continue to impact our results in 2021.

Liquidity and Financial Markets

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 continue to have 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.

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, have caused a higher percentage of our accounts receivable to become uncollectible. Although impacts on our results of operations related to uncollectible receivable balances are mitigated by regulatory mechanisms and certain COVID-19 specific regulatory orders we have received, the increase in past due receivables we experienced resulted in higher working capital requirements. However, with normal collection practices now


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underway in all of our service territories, our working capital position has improved in the third quarter from where we were at the end of the first and second quarters of 2021.

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. 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 22, Regulatory Environment, for more information on these orders.

Loss of Business

We saw a decrease in the consumption of electricity and natural gas by some of our commercial and industrial customers as a result of the COVID-19 pandemic. Although many of these customers have started to recover, the extent to which this decreased consumption continues to impact our results of operations and liquidity is dependent upon the duration of the COVID-19 pandemic and the ability of our customers to resume and continue normal operations.

Supply Chain and Capital Projects

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

The timing of Badger Hollow I was impacted by the COVID-19 pandemic. The parties agreed to delay the expected commercial operation date from December 2020 so that initial staffing increases could be minimized in light of state mandated COVID-19 orders. We now expect Badger Hollow I to be placed into commercial operation during the fourth quarter of 2021. 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 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 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.

We continue to provide our employees with educational information regarding the COVID-19 vaccine and will be providing incentives and imposing surcharges on our medical plan to encourage employees to obtain the vaccine. We are developing return-to-the workplace strategies for those employees currently working remotely, taking into consideration factors such as any updated CDC guidelines, the Delta variant, any increases in COVID-19 cases in our service territories, and the overall level of risk to our employees and customers.

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


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Regulatory Environment

Our utilities took actions to ensure that essential utility services were available to customers in their service territories during the COVID-19 pandemic. In addition, the PSCW, the ICC, the MPUC, and the MPSC all issued written orders regarding certain measures required in their respective jurisdictions. See Note 22, Regulatory Environment, for more information on these orders and the potential recovery of expenditures incurred as a result of the measures taken.

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 and legislative matters 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 2020 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.

Regulatory and Legislative Matters

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 generic and/or specific orders 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, 2021, costs incurred for this project at PGL are still subject to approval by the ICC. WPS, NSG, MGU and MERC received approval to recover these costs in their most recent rate orders.

•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 2021, PGL filed its 2020 reconciliation with the ICC, which, along with the 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of September 30, 2021, 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 22, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Climate and Equitable Jobs Act

On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act. This new legislation includes, among other things, a path for Illinois to move towards 100% clean energy, expanded commitments to energy efficiency and renewable energy, additional consumer protections, and expanded ethics reform. The provisions in this legislation with the potential to have the most significant financial impact on PGL and NSG relate to the new consumer protection requirements. Effective January 1, 2023, natural gas utilities will no longer be allowed to charge late payment fees to low-income residential customers. In addition, effective September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card. Instead, utilities will be required to seek recovery of costs incurred to process credit card payments through a rate proceeding or by establishing a recovery mechanism. On October 27, 2021, PGL and NSG filed requests with the ICC for approval of a


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TPTFA rider. The proposed TPTFA rider would allow PGL and NSG to recover the costs incurred for third-party transaction fees. See Note 22, Regulatory Environment, for more information on the proposed rider.

We are currently evaluating the impact this legislation may have on our future results of operations.

United States Department of Commerce Complaint

In August 2021, a group of anonymous domestic solar manufacturers filed a petition with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claim that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In September 2021, the DOC asked that the anonymous group amend its petition to provide more detail and asked the group to identify its members. On October 13, 2021, in its response to the DOC, the anonymous group refused and argued that identifying its members could expose them to retribution from the Chinese solar industry, which dominates the global solar supply chain for critical solar panel components. The DOC has indicated it will make its decision within 45 days of receiving the response. If imposed, the new tariffs are expected to disrupt the United States' supply of solar modules and could impact the cost and timing of our solar projects.

Environmental Matters

See Note 20, 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

Return on Equity Incentive for Membership in a Transmission Organization

The FERC currently allows transmission utilities, including ATC, to increase their ROE by 50 basis points as an incentive for membership in a transmission organization, such as MISO. This incentive was established to stimulate infrastructure development and to support the evolving electric grid. However, a Notice of Proposed Rulemaking was issued by the FERC on April 15, 2021 proposing to limit the 50 basis point increase in ROE to only be available to transmission utilities initially joining a transmission organization for the first three years of membership. If this proposal becomes a final rule, ATC would be required to submit, within 30 days of the final rule's effective date, a compliance filing eliminating the 50 basis point incentive from its tariff. As a result, this proposal, if adopted, would reduce our after-tax equity earnings from ATC by approximately $7 million annually. The transmission costs WE and WPS are required to pay ATC after the effective date would also be reduced by this proposal.

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. Various parties filed requests to rehear certain parts of the May 2020 Order with the FERC, but the FERC issued an order in response to the rehearing requests during November 2020 (November 2020 Order) that confirmed the ROE authorized in the May 2020 Order. Petitions for review of the November 2019 Order, relevant parts of the May 2020 Order, and the November 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


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MISO transmission owners to collect a reduced base ROE of 10.32%. This order also allowed the continued collection of any previously authorized ROE incentive adders. For MISO transmission owners, a 0.5% incentive adder was approved by the FERC in January 2015. 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 previously authorized ROE incentive adders, but ATC's ROE incentive adder of 0.5% 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 previously authorized ROE incentive adders. However, ATC's 0.5% ROE incentive adder may be eliminated going forward, as discussed above.

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 November 19, 2020. As a result, ATC is expected to continue providing WE and WPS with net refunds related to the transmission costs they paid during the two refund periods through the end of February 2022. These refunds are being 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 collection of previously authorized ROE incentive adders, such as ATC's 0.5% 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 collection of previously authorized ROE incentive adders 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 petitions related to the November 2019 Order, May 2020 Order, and November 2020 Order, refunds could still be required for the second complaint period. Therefore, our financials continue to reflect a liability of $39.1 million, reducing 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.

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 2020 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, 2021. No impairments were recorded as a result of these tests.


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Our reporting units had the following goodwill balances at July 1, 2021:


(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 the 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 16, Goodwill and Intangibles, 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 2020 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 12, Fair Value Measurements, Note 13, Derivative Instruments, and Note 14, 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 2021 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 2020 Annual Report on Form 10-K. See Note 20, Commitments and Contingencies, and Note 22, 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 20, Commitments and Contingencies, Note 22, 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. A supplemental filing was sent to the IEPA in December 2019. In September 2020, the IEPA sent PGL a letter conditionally approving the GMZ application. During late 2020 and throughout 2021, PGL has taken steps to implement the requirements of the approved GMZ project.

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 pursues penalties in connection with a final order, 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

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2020 Annual Report on Form 10-K.


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

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended September 30, 2021:


Issuer Purchases of Equity Securities
2021	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	64	$	89.51	—	$	—
August 1 – August 31	—	—		—	—
September 1 – September 30	—	—		—	—
Total (1)	64	$	89.51	—

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


ITEM 6. EXHIBITS



Number	Exhibit
















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 4, 2021	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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