WEC ENERGY GROUP, INC. - Quarter Report: 2022 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, 2022


☐			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, 2022):

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

Table of Contents

WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2022

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Income Statements

Condensed Consolidated Statements of Comprehensive Income

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Equity

Notes to Condensed Consolidated Financial Statements

Page

Regulatory Assets and Liabilities

Note 7

Property, Plant, and Equipment

Note 8

Common Equity

Note 9

Short-Term Debt and Lines of Credit

Materials, Supplies, and Inventories

Note 13

Income Taxes

Note 14

Fair Value Measurements

Note 15

Derivative Instruments

Goodwill and Intangibles

Note 19

Investment in Transmission Affiliates

Note 20

Segment Information

Note 21

Variable Interest Entities

Note 22

Commitments and Contingencies

Note 23

Supplemental Cash Flow Information

Note 24

Regulatory Environment

Note 25

New Accounting Pronouncements

ITEM 2.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.

CONTROLS AND PROCEDURES

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
Thunderhead						Thunderhead Wind Energy 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

WEPCo Environmental Trust						WEPCo Environmental Trust Finance I, LLC
WG						Wisconsin Gas LLC
Wispark						Wispark LLC
WPS						Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
CBP						United States Customs and Border Protection Agency
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
IRS						United States Internal Revenue Service
MPSC						Michigan Public Service Commission
MPUC						Minnesota Public Utilities Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission
WDNR						Wisconsin Department of Natural Resources

Accounting Terms
AFUDC						Allowance for Funds Used During Construction


ASU						Accounting Standards Update
FASB						Financial Accounting Standards Board
GAAP						United States Generally Accepted Accounting Principles
LIFO						Last-In, First-Out
OPEB						Other Postretirement Employee Benefits
VIE						Variable Interest Entity

Environmental Terms
ACE						Affordable Clean Energy
BATW						Bottom Ash Transport Water

BTA						Best Technology Available


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CAA						Clean Air Act
CASAC						Clean Air Scientific Advisory Committee
CO2						Carbon Dioxide

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
WOTUS						Waters of the United States
WPDES						Wisconsin Pollutant Discharge Elimination System

Measurements
Dth						Dekatherm
MW						Megawatt
MWh						Megawatt-hour
µg/m3						Micrograms Per Cubic Meter

Other Terms and Abbreviations
2007 Junior Notes						WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067

AD/CVD						Antidumping and Countervailing Duties
AG						Attorney General
AMI						Advanced Metering Infrastructure
Badger Hollow I						Badger Hollow Solar Park I
Badger Hollow II						Badger Hollow Solar Park II

Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
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
Darien						Darien Solar-Battery Park
DER						Distributed Energy Resource
EGU						Electric Generating Unit
ERGS						Elm Road Generating Station
ESG Progress Plan						WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for 2023-2027
ETB						Environmental Trust Bond
EV						Electric Vehicle
Exchange Act						Securities Exchange Act of 1934, as amended
Executive Order 13990						Executive Order 13990 of January 20, 2021 – Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis
FTR						Financial Transmission Right
GCRM						Gas Cost Recovery Mechanism
GUIC						Gas Utility Infrastructure Cost
IRA						Inflation Reduction Act
ITC						Investment Tax Credit
LIBOR						London Interbank Offered Rate
LNG						Liquefied Natural Gas
Maple Flats						Maple Flats Solar Energy Center LLC
MISO						Midcontinent Independent System Operator, Inc.

OCPP						Oak Creek Power Plant


OC 7						Oak Creek Power Plant Unit 7
OC 8						Oak Creek Power Plant Unit 8

Paris						Paris Solar-Battery Park
PPA						Power Purchase Agreement


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PSB						Public Service Building
PTC						Production Tax Credit
PWGS						Port Washington Generation Station
QIP						Qualifying Infrastructure Plant
Red Barn						Red Barn Wind Park
RICE						Reciprocating Internal Combustion Engine
RNG						Renewable Natural Gas
ROE						Return on Equity
S&P						Standard & Poor's
Sapphire Sky						Sapphire Sky Wind Energy LLC
SIP						State Implementation Plan
SMP						Safety Modernization Program


SPP						Southwest Power Pool, Inc.

Supreme Court						United States Supreme Court
Tax Legislation						Tax Cuts and Jobs Act of 2017
TCR						Transmission Congestion Right
TPTFA						Third-Party Transaction Fee Adjustment

Two Creeks						Two Creeks Solar Park


UFLPA						Uyghur Forced Labor Prevention Act
West Riverside						West Riverside Energy Center
Whitewater						Whitewater Cogeneration Facility
WRO						Withhold Release Order


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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 2021 Annual Report on Form 10-K, and those identified below:

•Factors affecting utility and non-utility energy infrastructure 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, including those caused by climate change, 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 federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, the expiration and non-renewal of the QIP rider, 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, electrification initiatives and other efforts to reduce the use of natural gas, and tax laws, including those that affect our ability to use PTCs and ITCs;

•Federal, state, and local 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;

•The risk of delays and shortages, and increased costs of equipment, materials, or other resources that are critical to our business operations and corporate strategy, as a result of supply chain disruptions (including disruptions from rail congestion), inflation, and other factors;

•The impact of health pandemics, including any new developments relating to the COVID-19 pandemic, on our business functions, financial condition, liquidity, and results of operations;


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•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, the feasibility of competing generation projects, and our ability to execute our capital plan;

•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;

•Any impacts on the global economy, supply chains and fuel prices, generally, from the ongoing conflict between Russia and Ukraine and related sanctions;

•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, other intangible assets, long-lived assets, and equity method investments, and their possible impairment;


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•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 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)	2022		2021		2022		2021
Operating revenues	$	2,003.0	$	1,746.5	$	7,039.0	$	6,114.1

Operating expenses
Cost of sales	805.1		560.7		3,123.5		2,352.2
Other operation and maintenance	454.3		473.7		1,357.7		1,417.4
Depreciation and amortization	280.3		271.6		838.0		799.2
Property and revenue taxes	59.1		50.5		176.0		157.2
Total operating expenses	1,598.8		1,356.5		5,495.2		4,726.0

Operating income	404.2		390.0		1,543.8		1,388.1

Equity in earnings of transmission affiliates	63.7		42.3		148.4		126.2
Other income, net	34.7		25.2		94.1		97.7
Interest expense	127.5		118.0		364.9		357.5
Other expense	(29.1)		(50.5)		(122.4)		(133.6)

Income before income taxes	375.1		339.5		1,421.4		1,254.5
Income tax expense	73.4		50.8		263.9		179.8
Net income	301.7		288.7		1,157.5		1,074.7

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Net (income) loss attributed to noncontrolling interests	0.6		1.6		(1.2)		2.3
Net income attributed to common shareholders	$	302.0	$	290.0	$	1,155.4	$	1,076.1

Earnings per share
Basic	$	0.96	$	0.92	$	3.66	$	3.41
Diluted	$	0.96	$	0.92	$	3.65	$	3.40

Weighted average common shares outstanding
Basic	315.4		315.4		315.4		315.4
Diluted	316.2		316.3		316.2		316.3

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)	2022		2021		2022		2021
Net income	$	301.7	$	288.7	$	1,157.5	$	1,074.7

Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges

Reclassification of realized net derivative (gain) loss to net income, net of tax expense (benefit) of $(0.1), $0.5, $(0.2), and $1.2, respectively	—		0.9		(0.1)		2.9

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

Other comprehensive income, net of tax	—		1.0		—		3.2

Comprehensive income	301.7		289.7		1,157.5		1,077.9

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Comprehensive (income) loss attributed to noncontrolling interests	0.6		1.6		(1.2)		2.3
Comprehensive income attributed to common shareholders	$	302.0	$	291.0	$	1,155.4	$	1,079.3

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, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents	$	28.5	$	16.3
Accounts receivable and unbilled revenues, net of reserves of $168.5 and $198.3, respectively	1,321.8		1,505.7
Materials, supplies, and inventories	924.6		635.8

Prepaid taxes	124.3		182.1
Other prepayments	32.2		63.4

Derivative assets	191.0		107.0
Other	148.6		146.4
Current assets	2,771.0		2,656.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,348.8 and $9,889.3, respectively	28,575.3		26,982.4
Regulatory assets (September 30, 2022 and December 31, 2021 include $94.0 and $100.7, respectively, related to WEPCo Environmental Trust)	3,164.2		3,264.8
Equity investment in transmission affiliates	1,875.9		1,789.4
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	965.8		881.3
Other	356.0		361.1
Long-term assets	37,990.0		36,331.8
Total assets	$	40,761.0	$	38,988.5

Liabilities and Equity
Current liabilities
Short-term debt	$	1,259.5	$	1,897.0
Current portion of long-term debt (September 30, 2022 and December 31, 2021 each include $8.8, respectively, related to WEPCo Environmental Trust)	167.2		169.4
Accounts payable	1,158.0		1,005.7

Customer credit balances	170.9		140.4
Other	614.1		540.5
Current liabilities	3,369.7		3,753.0

Long-term liabilities
Long-term debt (September 30, 2022 and December 31, 2021 include $98.5 and $102.7, respectively, related to WEPCo Environmental Trust)	14,910.7		13,523.7
Deferred income taxes	4,524.9		4,308.5
Deferred revenue, net	374.2		389.2
Regulatory liabilities	3,947.0		3,946.0
Environmental remediation liabilities	497.7		532.6
Pension and OPEB obligations	217.7		219.0
Other	1,323.0		1,203.2
Long-term liabilities	25,795.2		24,122.2

Commitments and contingencies (Note 22)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding	3.2		3.2
Additional paid in capital	4,113.5		4,138.1
Retained earnings	7,242.0		6,775.1
Accumulated other comprehensive loss	(3.2)		(3.2)
Common shareholders' equity	11,355.5		10,913.2

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	210.2		169.7
Total liabilities and equity	$	40,761.0	$	38,988.5

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)	2022		2021
Operating activities
Net income	$	1,157.5	$	1,074.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	838.0		799.2
Deferred income taxes and ITCs, net	187.8		158.0
Contributions and payments related to pension and OPEB plans	(11.6)		(11.3)
Equity income in transmission affiliates, net of distributions	(47.1)		(27.0)
Change in –
Accounts receivable and unbilled revenues, net	150.9		162.4
Materials, supplies, and inventories	(288.8)		(117.1)
Prepaid taxes	57.8		37.7
Other prepayments	31.6		30.0
Amounts recoverable from customers	15.3		(119.4)
Other current assets	(1.5)		13.8
Accounts payable	82.2		(15.1)
Other current liabilities	68.5		107.5
Other, net	(181.1)		(86.7)
Net cash provided by operating activities	2,059.5		2,006.7

Investing activities
Capital expenditures	(1,700.7)		(1,627.9)
Acquisition of Thunderhead, net of cash acquired of $0.5	(362.9)		—
Acquisition of Jayhawk	—		(119.8)
Capital contributions to transmission affiliates	(39.4)		—
Proceeds from the sale of assets	69.0		21.6
Proceeds from the sale of investments held in rabbi trust	15.4		12.7
Insurance proceeds received for property damage	41.6		—
Payments for ATC's construction costs that will be reimbursed	(20.6)		(2.2)
Other, net	11.7		26.9
Net cash used in investing activities	(1,985.9)		(1,688.7)

Financing activities
Exercise of stock options	33.1		6.5
Purchase of common stock	(68.3)		(15.7)
Dividends paid on common stock	(688.5)		(641.2)
Issuance of long-term debt	1,400.0		1,018.8
Retirement of long-term debt	(64.9)		(356.2)
Repayment of short-term loan	—		(340.0)
Change in commercial paper	(640.2)		71.5
Other, net	(16.3)		(25.1)
Net cash used in financing activities	(45.1)		(281.4)

Net change in cash, cash equivalents, and restricted cash	28.5		36.6
Cash, cash equivalents, and restricted cash at beginning of period	87.5		72.6
Cash, cash equivalents, and restricted cash at end of period	$	116.0	$	109.2

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, 2021	$	3.2	$	4,138.1	$	6,775.1	$	(3.2)	$	10,913.2	$	30.4	$	169.7	$	11,113.3
Net income attributed to common shareholders	—		—		565.9		—		565.9		—		—		565.9
Net income attributed to noncontrolling interests	—		—		—		—		—		—		1.8		1.8
Common stock dividends of $0.7275 per share	—		—		(229.6)		—		(229.6)		—		—		(229.6)
Exercise of stock options	—		11.8		—		—		11.8		—		—		11.8
Purchase of common stock	—		(23.4)		—		—		(23.4)		—		—		(23.4)
Capital contributions from noncontrolling interest	—		—		—		—		—		—		0.4		0.4
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.0)		(1.0)
Stock-based compensation and other	—		5.3		—		—		5.3		—		—		5.3
Balance at March 31, 2022	$	3.2	$	4,131.8	$	7,111.4	$	(3.2)	$	11,243.2	$	30.4	$	170.9	$	11,444.5
Net income attributed to common shareholders	—		—		287.5		—		287.5		—		—		287.5
Common stock dividends of $0.7275 per share	—		—		(229.4)		—		(229.4)		—		—		(229.4)
Exercise of stock options	—		11.2		—		—		11.2		—		—		11.2
Purchase of common stock	—		(25.0)		—		—		(25.0)		—		—		(25.0)
Capital contributions from noncontrolling interest	—		—		—		—		—		—		0.1		0.1
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.2)		(1.2)
Stock-based compensation and other	—		3.1		—		—		3.1		—		(0.2)		2.9
Balance at June 30, 2022	$	3.2	$	4,121.1	$	7,169.5	$	(3.2)	$	11,290.6	$	30.4	$	169.6	$	11,490.6
Net income attributed to common shareholders	—		—		302.0		—		302.0		—		—		302.0
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.6)		(0.6)
Common stock dividends of $0.7275 per share	—		—		(229.5)		—		(229.5)		—		—		(229.5)
Exercise of stock options	—		10.1		—		—		10.1		—		—		10.1
Purchase of common stock	—		(19.9)		—		—		(19.9)		—		—		(19.9)
Acquisition of a noncontrolling interest	—		—		—		—		—		—		42.5		42.5
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.3)		(1.3)
Stock-based compensation and other	—		2.2		—		—		2.2		—		—		2.2
Balance at September 30, 2022	$	3.2	$	4,113.5	$	7,242.0	$	(3.2)	$	11,355.5	$	30.4	$	210.2	$	11,596.1


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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

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, 2022

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 segment.

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, Thunderhead, 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 19, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2021. 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, 2022, are not necessarily indicative of expected results for 2022 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions (or disposals) of assets or businesses, and transaction costs are capitalized in asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 18, Goodwill and Intangibles, for more information.

Acquisitions of Electric Generation Facilities in Illinois

In October 2022, WECI signed an agreement to acquire an 80% ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $360 million. The project has an offtake agreement for all of the energy to be produced by the operation facility for a period of 15 years. The transaction is subject to FERC approval and commercial operational is expected to begin during the first half of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

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. Sapphire Sky's PTC percentage is expected to increase to 100%, which will cause the purchase price to increase. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. The transaction is subject to FERC approval and commercial operation is expected to begin by early 2023, at which time the transaction is expected to close. Sapphire Sky will be included in the non-utility energy infrastructure segment.


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Acquisition of Wind Generation Facility in Nebraska

In September 2022, WECI completed the acquisition of a 90% ownership interest in Thunderhead, a 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska. The purchase price was $381.9 million, and included net cash payments of $362.9 million, which included transaction costs and is net of cash acquired. WECI also recorded a $19.0 million payable at closing, related to certain milestones that needed to be achieved. The first milestone payment in the amount of $9.5 million was paid in October 2022, with the remaining $9.5 million expected to be paid upon commercial operation. Thunderhead is expected to become commercially operational by the end of 2022. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment.

Acquisitions of Electric Generation Facilities in Wisconsin

In January 2022, WPS, along with an unaffiliated utility, received PSCW approval to acquire the Red Barn, 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. WPS's share of the cost of this project is estimated to be $160 million, with commercial operation expected to begin by early 2023, at which time the transaction is expected to close. Red Barn is expected to qualify for PTCs.

In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual-fueled (natural gas and low sulfur fuel oil) combined-cycle electrical generation facility in Whitewater, Wisconsin, for $72.7 million, which excludes working capital and transaction costs. In December 2021, an application was filed with the PSCW for approval of the acquisition. We expect a decision from the PSCW by the end of 2022, and for the transaction to close in early 2023.

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 in Bourbon and Crawford counties, Kansas, for $119.9 million, which included transaction costs. The project became commercially operational in December 2021. Subsequent to the acquisition, WECI incurred an additional $153.9 million of capital expenditures as of September 30, 2022 for the project for a current total investment of $273.8 million. The project has an offtake agreement for all of the energy produced by the facility for a period of 10 years. Jayhawk qualifies 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 it will be entitled to tax benefits equal to its ownership interest. Jayhawk is included in the non-utility energy infrastructure segment.

NOTE 3—DISPOSITION

Sale of Certain Real Estate by The Peoples Gas Light and Coke Company

In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $55.1 million. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $54.5 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.


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NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2021 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, 2022
Electric	$	1,436.9	$	—	$	—	$	1,436.9	$	—	$	—	$	—		$	1,436.9
Natural gas	234.9		224.0		63.9		522.8		12.1		—		(11.3)			523.6
Total regulated revenues	1,671.8		224.0		63.9		1,959.7		12.1		—		(11.3)			1,960.5
Other non-utility revenues	—		—		4.8		4.8		27.3		—		(1.5)			30.6
Total revenues from contracts with customers	1,671.8		224.0		68.7		1,964.5		39.4		—		(12.8)			1,991.1
Other operating revenues	5.0		6.3		0.5		11.8		100.5		0.1		(100.5)		(1)	11.9
Total operating revenues	$	1,676.8	$	230.3	$	69.2	$	1,976.3	$	139.9	$	0.1	$	(113.3)		$	2,003.0


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended September 30, 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
Nine Months Ended September 30, 2022
Electric	$	3,845.5	$	—	$	—	$	3,845.5	$	—	$	—	$	—		$	3,845.5
Natural gas	1,311.2		1,346.1		397.9		3,055.2		39.4		—		(37.1)			3,057.5
Total regulated revenues	5,156.7		1,346.1		397.9		6,900.7		39.4		—		(37.1)			6,903.0
Other non-utility revenues	—		—		13.9		13.9		102.1		—		(7.1)			108.9
Total revenues from contracts with customers	5,156.7		1,346.1		411.8		6,914.6		141.5		—		(44.2)			7,011.9
Other operating revenues	19.8		8.7		(1.8)		26.7		301.5		0.4		(301.5)		(1)	27.1
Total operating revenues	$	5,176.5	$	1,354.8	$	410.0	$	6,941.3	$	443.0	$	0.4	$	(345.7)		$	7,039.0


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(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
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

(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)	2022		2021		2022		2021
Residential	$	529.7	$	512.2	$	1,442.5	$	1,354.9
Small commercial and industrial	424.8		396.9		1,173.3		1,074.9
Large commercial and industrial	316.8		271.9		814.1		705.9
Other	7.1		7.0		22.1		21.7
Total retail revenues	1,278.4		1,188.0		3,452.0		3,157.4
Wholesale	39.7		41.1		122.9		119.4
Resale	102.7		45.0		220.2		145.1
Steam	3.0		2.7		19.8		21.7
Other utility revenues	13.1		7.8		30.6		19.2
Total electric utility operating revenues	$	1,436.9	$	1,284.6	$	3,845.5	$	3,462.8

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, 2022
Residential	$	122.1	$	177.0	$	31.5	$	330.6
Commercial and industrial	75.5		52.6		21.5		149.6
Total retail revenues	197.6		229.6		53.0		480.2
Transportation	15.9		46.1		5.3		67.3
Other utility revenues (1)	21.4		(51.7)		5.6		(24.7)
Total natural gas utility operating revenues	$	234.9	$	224.0	$	63.9	$	522.8


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(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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2022
Residential	$	823.1	$	911.1	$	256.3	$	1,990.5
Commercial and industrial	450.1		289.1		144.9		884.1
Total retail revenues	1,273.2		1,200.2		401.2		2,874.6
Transportation	59.4		181.5		25.2		266.1
Other utility revenues (2)	(21.4)		(35.6)		(28.5)		(85.5)
Total natural gas utility operating revenues	$	1,311.2	$	1,346.1	$	397.9	$	3,055.2


(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 (3)	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

(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. For the three months ended September 30, 2022 and 2021, we continued to incur higher natural gas costs at all of our utility segments. The negative amount in Illinois reflects the timing of the billing of these high natural gas costs to its customers. As these amounts are billed to its customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

(2)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. During the nine months ended September 30, 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to our customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

(3)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. For the nine months ended September 30, 2021, in addition to costs related to the extreme weather event experienced in February 2021, we incurred higher natural gas costs as a result of an increase in the price of natural gas.

See Note 24, Regulatory Environment, for more information.

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)	2022		2021		2022		2021
Wind generation revenues	$	20.0	$	12.2	$	77.5	$	42.5
We Power revenues (1)	5.8		5.9		17.5		17.5
Appliance service revenues	4.8		4.3		13.9		13.4


Total other non-utility operating revenues	$	30.6	$	22.4	$	108.9	$	73.4

(1)As part of the construction of the We Power EGUs, 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)	2022		2021		2022		2021
Late payment charges	$	13.6	$	11.9	$	43.5	$	44.2
Alternative revenues (1)	(2.4)		0.9		(19.7)		10.0
Other	0.7		0.7		3.3		3.6
Total other operating revenues	$	11.9	$	13.5	$	27.1	$	57.8

(1)Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges.

NOTE 5—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 defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being


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made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk.

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2022 and December 31, 2021, 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, 2022
Accounts receivable and unbilled revenues	$	970.2		$	429.7		$	67.1		$	1,467.0		$	18.5		$	4.8		$	1,490.3
Allowance for credit losses	72.4			89.7			6.4			168.5			—			—			168.5
Accounts receivable and unbilled revenues, net (1)	$	897.8		$	340.0		$	60.7		$	1,298.5		$	18.5		$	4.8		$	1,321.8

Total accounts receivable, net – past due greater than 90 days (1)	$	56.0		$	74.6		$	4.4		$	135.0		$	—		$	—		$	135.0
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	96.0		%	100.0		%	—		%	95.1		%	—		%	—		%	95.1		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2021
Accounts receivable and unbilled revenues	$	1,053.1		$	523.1		$	105.7		$	1,681.9		$	17.0		$	5.1		$	1,704.0
Allowance for credit losses	84.0			105.5			8.8			198.3			—			—			198.3
Accounts receivable and unbilled revenues, net (1)	$	969.1		$	417.6		$	96.9		$	1,483.6		$	17.0		$	5.1		$	1,505.7

Total accounts receivable, net – past due greater than 90 days (1)	$	46.5		$	36.6		$	3.4		$	86.5		$	—		$	—		$	86.5
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.6		%	100.0		%	—		%	94.8		%	—		%	—		%	94.8		%

(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, 2022, $754.7 million, or 57.1%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.


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A rollforward of the allowance for credit losses by reportable segment is included below:


Three Months Ended September 30, 2022 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at the beginning of the period	$	78.0	$	91.0	$	6.8	$	175.8
Provision for credit losses	10.0		5.2		0.6		15.8
Provision for credit losses deferred for future recovery or refund	10.2		2.6		—		12.8
Write-offs charged against the allowance	(34.6)		(13.5)		(1.3)		(49.4)
Recoveries of amounts previously written off	8.8		4.4		0.3		13.5
Balance at September 30, 2022	$	72.4	$	89.7	$	6.4	$	168.5

Nine Months Ended September 30, 2022 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at the beginning of the period	$	84.0	$	105.5	$	8.8	$	198.3
Provision for credit losses	33.6		23.6		0.7		57.9
Provision for credit losses deferred for future recovery or refund	13.6		3.5		—		17.1
Write-offs charged against the allowance	(85.5)		(58.7)		(3.9)		(148.1)
Recoveries of amounts previously written off	26.7		15.8		0.8		43.3
Balance at September 30, 2022	$	72.4	$	89.7	$	6.4	$	168.5

On a consolidated basis, there was a $29.8 million decrease in the allowance for credit losses at September 30, 2022, compared to December 31, 2021. The decrease was driven by customer write-offs related to collection practices returning to pre-pandemic levels in 2021, including the restoration of our ability to disconnect customers. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. Partially offsetting the decrease in the allowance for credit losses, we believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.


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


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


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NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2022 and December 31, 2021. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2021 Annual Report on Form 10-K.


(in millions)	September 30, 2022		December 31, 2021
Regulatory assets
Pension and OPEB costs	$	742.9	$	802.3
Plant retirement related items	698.0		722.3
Environmental remediation costs	616.3		630.9
Income tax related items	457.8		458.8
Asset retirement obligations	181.9		194.2
System support resource	125.5		129.5
Securitization	94.0		100.7
Energy costs recoverable through rate adjustments	73.5		85.4
Derivatives (1)	70.6		33.1
MERC extraordinary natural gas costs	44.9		59.7
Uncollectible expense	36.6		42.6
Energy efficiency programs	29.6		22.0
Other, net	79.6		85.6
Total regulatory assets	$	3,251.2	$	3,367.1

Balance sheet presentation
Other current assets	$	87.0	$	102.3
Regulatory assets	3,164.2		3,264.8
Total regulatory assets	$	3,251.2	$	3,367.1

(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 15, Derivative Instruments, for more information on our derivative asset and liability balances.


(in millions)	September 30, 2022		December 31, 2021
Regulatory liabilities
Income tax related items	$	1,959.0	$	1,998.5
Removal costs	1,255.5		1,248.0
Pension and OPEB benefits	384.0		397.3
Derivatives (1)	241.3		124.1
Energy costs refundable through rate adjustments (2)	45.3		13.7
Uncollectible expense	30.6		37.1
Electric transmission costs (3)	15.9		84.2
Earnings sharing mechanisms (3)	10.1		28.4
Other, net	53.2		29.0
Total regulatory liabilities	$	3,994.9	$	3,960.3

Balance sheet presentation
Other current liabilities	$	47.9	$	14.3
Regulatory liabilities	3,947.0		3,946.0
Total regulatory liabilities	$	3,994.9	$	3,960.3

(2) The increase in these regulatory liabilities was primarily related to lower natural gas costs incurred during 2022, compared to what was anticipated in rates.


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(3) The decrease in these regulatory liability balances was primarily related to the PSCW's approval of certain accounting treatments that allowed our Wisconsin utilities to forego applying for a 2022 base rate increase, and instead maintain base rates consistent with 2021 levels. Among the accounting treatments approved was the amortization of certain regulatory liability balances in 2022, to offset a portion of the forecasted revenue deficiency. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

NOTE 7—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 June 1, 2026. The retirement date for these plants was pushed back from the end of 2023 for unit 1 and the end of 2024 for unit 2. See Note 24, Regulatory Environment, for more information on the Columbia generating units' retirement. The net book value of WPS's ownership share of unit 1 and unit 2 was $85.2 million and $184.2 million, respectively, at September 30, 2022. These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheets. 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 and Steam Tunnel Assets

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 and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations. As of September 30, 2022, WE had incurred $95.3 million of costs related to these repairs and restorations. In 2020, WE received $20.0 million of insurance proceeds to cover a portion of these costs and wrote off $12.5 million of costs that we do not intend to seek recovery for through other operation and maintenance expense. In the first quarter of 2022, WE received $41.0 million of insurance proceeds as a result of a settlement that was reached in February 2022. The remaining $21.8 million of costs is expected to be recovered through rates.

In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, and in light of the agreement with insurers noted above, we do not currently expect a significant impact to our future results of operations.

NOTE 8—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2022, the Compensation Committee of our Board of Directors awarded the following stock-based compensation to our directors, officers, and certain other key employees:


Award Type						Number of Awards
Stock options (1)						437,269
Restricted shares (2)						72,211
Performance units						171,492

(1)Stock options awarded had a weighted-average exercise price of $96.04 and a weighted-average grant date fair value of $14.71 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $96.04 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; 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. Our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from


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loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2021 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Common Stock Dividends

On October 20, 2022, our Board of Directors declared a quarterly cash dividend of $0.7275 per share, payable on December 1, 2022, to shareholders of record on November 14, 2022.

NOTE 9—SHORT-TERM DEBT AND LINES OF CREDIT

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


(in millions, except percentages)	September 30, 2022			December 31, 2021
Commercial paper
Amount outstanding	$	1,255.9		$	1,896.1
Weighted-average interest rate on amounts outstanding	3.31		%	0.26		%
Operating expense loans
Amount outstanding (1)	$	3.6		$	0.9

(1)Coyote Ridge, Tatanka Ridge, and Jayhawk entered into operating expense loans. In accordance with their limited liability company operating agreements, they received loans from the holders of their noncontrolling interests 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, 2022 was $1,512.8 million with a weighted-average interest rate during the period of 1.35%.

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, 2022
WEC Energy Group	September 2026	$	1,500.0
WE	September 2026	500.0
WPS	September 2026	400.0
WG	September 2026	350.0
PGL	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		1,255.9
Available capacity under existing agreements		$	1,841.8

NOTE 10—LONG-TERM DEBT

WEC Energy Group, Inc.

In September 2022, we issued $500.0 million of 5.00% Senior Notes due September 27, 2025, and $400.0 million of 5.15% Senior Notes due October 1, 2027, and used the net proceeds to repay short-term debt and for other corporate purposes.


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Wisconsin Electric Power Company

In September 2022, WE issued $500.0 million of 4.75% Debentures due September 30, 2032, and intends to allocate an amount equal to the net proceeds for the construction and development of eligible green expenditures, which include existing and new expenditures for the acquisition, construction and development of wind and solar electric generating facilities and related energy storage assets.

NOTE 11—LEASES

WE and WPS have partnered with an unaffiliated utility to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system in Kenosha County, Wisconsin. WE and WPS own 75% and 15%, respectively, of Paris. Once fully constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this project. The PSCW has approved the acquisition and construction of Paris, and commercial operation for the solar portion of the project is targeted for 2023.

Related to their investment in Paris, WE and WPS, along with their unaffiliated utility partner, entered into several land leases in Kenosha County, Wisconsin that commenced in the second quarter of 2022. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments will be recovered through rates.

Our total obligation under the land-related finance leases for Paris was $56.8 million at September 30, 2022, and will decrease to zero over the remaining lives of the leases. Long-term lease liabilities related to our finance land leases for Paris were included in long-term debt on our balance sheet. Our finance lease right of use asset related to Paris was $55.7 million as of September 30, 2022, and was included in property, plant, and equipment on our balance sheet.

In accordance with Accounting Standards Codification Subtopic 980-842, Regulated Operations – Leases, the expense recognition pattern associated with the Paris leases resembles that of an operating lease. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset in accordance with Subtopic 980-842 on our balance sheet.

Our weighted-average discount rate for the Paris finance leases was 5.28%. We used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for Paris as of September 30, 2022, were as follows:


(in millions)
Three months ended December 31, 2022	$	0.8
2023	2.1
2024	2.4
2025	2.5
2026	2.5
2027	2.6
Thereafter	188.7
Total minimum lease payments	201.6
Less: Interest	(144.8)
Present value of minimum lease payments	56.8
Less: Short-term lease liabilities	—
Long-term lease liabilities	$	56.8


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NOTE 12—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:


(in millions)	September 30, 2022		December 31, 2021
Natural gas in storage	$	591.0	$	326.0
Materials and supplies	250.6		225.3
Fossil fuel	83.0		84.5
Total	$	924.6	$	635.8

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2022, we had a temporary LIFO liquidation credit of $0.5 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 13—INCOME TAXES

The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:


	Three Months Ended September 30, 2022				Three Months Ended September 30, 2021
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	78.9	21.0	%	$	71.8	21.0	%
State income taxes net of federal tax benefit	23.5		6.3	%	21.5		6.3	%
PTCs	(18.6)		(5.0)	%	(17.0)		(5.0)	%
Federal excess deferred tax amortization	(8.1)		(2.2)	%	(7.8)		(2.3)	%

Federal excess deferred tax amortization – Wisconsin unprotected	(0.1)		—	%	(16.3)		(4.8)	%


Other	(2.2)		(0.5)	%	(1.4)		(0.2)	%
Total income tax expense	$	73.4	19.6	%	$	50.8	15.0	%

	Nine Months Ended September 30, 2022				Nine Months Ended September 30, 2021
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	298.1	21.0	%	$	263.7	21.0	%
State income taxes net of federal tax benefit	89.3		6.3	%	79.2		6.3	%
PTCs	(86.3)		(6.1)	%	(64.5)		(5.1)	%
Federal excess deferred tax amortization	(32.3)		(2.3)	%	(30.3)		(2.4)	%

Federal excess deferred tax amortization – Wisconsin unprotected	(0.6)		—	%	(62.9)		(5.0)	%


Other	(4.3)		(0.3)	%	(5.4)		(0.5)	%
Total income tax expense	$	263.9	18.6	%	$	179.8	14.3	%

The effective tax rates of 19.6% and 18.6% for the three and nine months ended September 30, 2022, 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 impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. These items were partially offset by state income taxes.

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. Effective January 1, 2020, in accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities began amortizing the unprotected deferred tax benefits over periods ranging from two years to four


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years, to reduce near-term rate impacts to their customers. In addition, the impact of the protected deferred tax 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 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on unprotected tax benefits.

NOTE 14—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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 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. Our derivative instruments categorized as Level 3 consisted of both FTRs and TCRs at September 30, 2022 and of only FTRs at December 31, 2021. These derivative instruments are valued using auction prices from the applicable regional transmission organization.


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


	September 30, 2022
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	109.1	$	32.3	$	—	$	141.4
FTRs and TCRs	—		—		12.0		12.0
Coal contracts	—		65.8		—		65.8
Total derivative assets	$	109.1	$	98.1	$	12.0	$	219.2

Investments held in rabbi trust	$	47.4	$	—	$	—	$	47.4

Derivative liabilities
Natural gas contracts	$	24.3	$	25.3	$	—	$	49.6


	December 31, 2021
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	46.4	$	18.2	$	—	$	64.6
FTRs	—		—		2.4		2.4
Coal contracts	—		53.0		—		53.0
Total derivative assets	$	46.4	$	71.2	$	2.4	$	120.0

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

Derivative liabilities
Natural gas contracts	$	8.4	$	6.7	$	—	$	15.1

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. They also include FTRs and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets and the SPP Integrated Marketplace, respectively.

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, 2022 and 2021, the net unrealized losses included in earnings related to the investments held at the end of the period were $2.5 million and $0.1 million, respectively. For the nine months ended September 30, 2022, we recorded $15.9 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $9.7 million of net unrealized gains recorded during the same period in 2021.

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)	2022		2021		2022		2021
Balance at the beginning of the period	$	19.9	$	5.4	$	2.4	$	2.4
Purchases	0.2		—		22.1		6.1
Realized and unrealized gains (losses) included in earnings (1)	(0.3)		—		1.5		—
Settlements	(7.8)		(1.7)		(14.0)		(4.8)
Balance at the end of the period	$	12.0	$	3.7	$	12.0	$	3.7
Gains (losses) included in earnings attributable to the change in unrealized gains (losses) of Level 3 derivatives held at the end of the reporting period (1)	$	(0.2)	$	—	$	0.1	$	—


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(1)Amounts relate to FTRs and TCRs acquired by certain wind generating facilities included in our non-utility energy infrastructure segment. These realized and unrealized gains and losses are recorded in operating revenues on our income statements.

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, 2022				December 31, 2021
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	25.0	$	30.4	$	30.3
Long-term debt, including current portion (1)	14,894.9		13,190.6		13,563.4		14,819.4

(1)The carrying amount of long-term debt excludes finance lease obligations of $183.0 million and $129.7 million at September 30, 2022 and December 31, 2021, respectively.

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

NOTE 15—DERIVATIVE INSTRUMENTS

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

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

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. None of the derivatives shown below were designated as hedging instruments.


	September 30, 2022				December 31, 2021
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts (1)	$	135.0	$	46.7	$	60.6	$	14.0
FTRs and TCRs	12.0		—		2.4		—
Coal contracts	44.0		—		44.0		—
Total current	191.0		46.7		107.0		14.0

Long-term
Natural gas contracts (1)	6.4		2.9		4.0		1.1
Coal contracts	21.8		—		9.0		—
Total long-term	28.2		2.9		13.0		1.1
Total	$	219.2	$	49.6	$	120.0	$	15.1

(1)Our natural gas derivative assets increased from December 31, 2021 to September 30, 2022 primarily due to the significant increase in natural gas prices.


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Realized gains and losses on derivatives used in our regulatory utility operations are recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations are recorded in operating revenues on the income statements. Our estimated notional sales volumes and realized gains were as follows:


	Three Months Ended September 30, 2022			Three Months Ended September 30, 2021
(in millions)	Volumes	Gains		Volumes	Gains
Natural gas contracts	32.7 Dth	$	119.1	39.4 Dth	$	41.2
FTRs and TCRs	7.0 MWh	7.4		6.3 MWh	3.0
Total		$	126.5		$	44.2

	Nine Months Ended September 30, 2022			Nine Months Ended September 30, 2021
(in millions)	Volumes	Gains		Volumes	Gains
Natural gas contracts	133.3 Dth	$	259.6	147.1 Dth	$	38.5
FTRs and TCRs	21.0 MWh	12.7		22.1 MWh	15.3
Total		$	272.3		$	53.8

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, 2022 and December 31, 2021, we had posted cash collateral of $19.5 million and $13.9 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2022 and December 31, 2021, we had also received cash collateral of $16.4 million and $13.2 million, respectively. These amounts were recorded on our balance sheets in other current liabilities.

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


	September 30, 2022						December 31, 2021
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	219.2		$	49.6		$	120.0		$	15.1
Gross amount not offset on the balance sheet	(42.5)		(1)	(27.8)		(2)	(15.2)		(3)	(9.2)		(4)
Net amount	$	176.7		$	21.8		$	104.8		$	5.9

(1)Includes cash collateral received of $16.4 million.

(2)Includes cash collateral posted of $1.7 million.

(3)Includes cash collateral received of $6.4 million.

(4)Includes cash collateral posted of $0.4 million.

Cash Flow Hedges

Until their expiration on November 15, 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 provided a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes. As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses were deferred in accumulated other comprehensive loss and were amortized to interest expense as interest was 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.


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The table below shows the amounts related to these cash flow hedges that were reclassified to interest expense, along with our total interest expense on the income statements:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2022		2021		2022		2021

Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense	$	0.1	$	(1.4)	$	0.3	$	(4.1)
Total interest expense line item on the income statements	127.5		118.0		364.9		357.5

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

NOTE 16—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at September 30, 2022		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	83.8	$	10.5	$	0.2	$	73.1
Surety bonds (2)	12.0		11.9		0.1		—
Other guarantees (3)	9.5		—		—		9.5
Total guarantees	$	105.3	$	22.4	$	0.3	$	82.6

(1)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.

(2)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.

(3)Related to workers compensation coverage for which a liability was recorded on our balance sheets.

NOTE 17—EMPLOYEE BENEFITS

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


	Pension Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2022		2021		2022		2021
Service cost	$	12.3	$	13.3	$	38.9	$	40.8
Interest cost	23.2		22.2		68.4		65.8
Expected return on plan assets	(51.6)		(50.1)		(156.8)		(150.8)
Loss on plan settlement	1.1		0.9		3.3		2.9
Amortization of prior service cost	0.4		0.4		1.2		1.2
Amortization of net actuarial loss	19.0		26.4		57.2		82.0
Net periodic benefit cost	$	4.4	$	13.1	$	12.2	$	41.9


	OPEB Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2022		2021		2022		2021
Service cost	$	3.6	$	4.0	$	10.7	$	11.8
Interest cost	3.8		3.7		11.5		10.9
Expected return on plan assets	(17.2)		(16.5)		(51.7)		(49.5)

Amortization of prior service credit	(4.0)		(4.1)		(11.9)		(12.0)
Amortization of net actuarial gain	(6.2)		(5.9)		(18.5)		(18.1)
Net periodic benefit credit	$	(20.0)	$	(18.8)	$	(59.9)	$	(56.9)


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During the nine months ended September 30, 2022, we made contributions and payments of $8.4 million related to our pension plans and $3.2 million related to our OPEB plans. We expect to make contributions and payments of $2.8 million related to our pension plans during the remainder of 2022, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to make any contributions or payments related to our OPEB plans during the remainder of 2022.

NOTE 18—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, 2022. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2022.


(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, 2022.

During the third quarter of 2022, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2022. No impairments resulted from these tests.

Intangible Assets

At September 30, 2022 and December 31, 2021, we had $17.4 million and $5.7 million, respectively, of indefinite-lived intangible assets. During the third quarter of 2022, we purchased a radio spectrum for $11.7 million. The radio spectrum enables the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.7 million of other indefinite-lived intangible assets, primarily related to a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

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.


	September 30, 2022						December 31, 2021
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	212.9	$	(12.3)	$	200.6	$	87.9	$	(6.5)	$	81.4
Proxy revenue swap (2)	7.2		(2.6)		4.6		7.2		(2.1)		5.1
Interconnection agreements (3)	4.7		(0.7)		4.0		4.7		(0.5)		4.2
Total intangible liabilities	$	224.8	$	(15.6)	$	209.2	$	99.8	$	(9.1)	$	90.7

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, and Thunderhead expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is 10 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 useful life of the proxy revenue swap is six 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 useful life of the interconnection agreements is 18 years.


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Amortization related to these intangible liabilities for the three and nine months ended September 30, 2022, was $2.2 million and $6.5 million, respectively. Amortization for the three and nine months ended September 30, 2021, was $1.9 million and $5.6 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 2022, is estimated to be:


	For the Years Ending December 31
(in millions)	2022		2023		2024		2025		2026
Amortization to be recorded as an increase to operating revenues	$	10.6	$	20.9	$	20.9	$	20.9	$	20.9
Amortization to be recorded as a decrease to other operation and maintenance	0.2		0.2		0.2		0.2		0.2

NOTE 19—INVESTMENT IN TRANSMISSION AFFILIATES

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


	Three Months Ended September 30, 2022
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,813.6	$	23.6	$	1,837.2
Add: Earnings from equity method investment	63.2		0.5		63.7
Add: Capital contributions	9.1		—		9.1
Less: Distributions	34.1		—		34.1


Balance at end of period	$	1,851.8	$	24.1	$	1,875.9

	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

	Nine Months Ended September 30, 2022
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,766.9	$	22.5	$	1,789.4
Add: Earnings from equity method investment	146.8		1.6		148.4
Add: Capital contributions	39.4		—		39.4
Less: Distributions	101.3		—		101.3

Balance at end of period	$	1,851.8	$	24.1	$	1,875.9

	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

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.


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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2022		2021		2022		2021
Charges to ATC for services and construction	$	3.9	$	5.5	$	14.8	$	17.2
Charges from ATC for network transmission services	90.9		81.6		272.8		263.3

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


(in millions)	September 30, 2022		December 31, 2021
Accounts receivable for services provided to ATC	$	1.6	$	2.0

Accounts payable for services received from ATC	30.3		30.2
Amounts due from ATC for transmission infrastructure upgrades (1)	24.1		13.0

(1)These transmission infrastructure upgrades were primarily related to the construction of WE's and WPS's renewable energy projects.

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2022		2021		2022		2021
Income statement data
Operating revenues	$	169.8	$	186.8	$	552.4	$	561.4
Operating expenses	97.7		91.3		288.4		278.8
Other expense, net	34.5		28.6		91.3		85.2
Net income	$	37.6	$	66.9	$	172.7	$	197.4


(in millions)	September 30, 2022		December 31, 2021
Balance sheet data
Current assets	$	95.9	$	89.8
Noncurrent assets	5,901.8		5,628.1
Total assets	$	5,997.7	$	5,717.9

Current liabilities	$	498.4	$	436.9
Long-term debt	2,612.3		2,513.0
Other noncurrent liabilities	464.2		422.0
Members' equity	2,422.8		2,346.0
Total liabilities and members' equity	$	5,997.7	$	5,717.9

NOTE 20—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 2022, 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.


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•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,

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

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

▪90% ownership interest in Jayhawk, located in Bourbon and Crawford counties, Kansas, and

▪90% ownership interest in Thunderhead, located in Wheeler and Antelope counties, Nebraska.

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

•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, and WEC Business Services LLC.

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, 2022 and 2021:


	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, 2022
External revenues	$	1,676.8	$	230.3	$	69.2	$	1,976.3	$	—	$	26.6	$	0.1	$	—	$	2,003.0
Intersegment revenues	—		—		—		—		—		113.3		—		(113.3)		—
Other operation and maintenance	329.1		100.2		21.0		450.3		—		12.1		(6.5)		(1.6)		454.3
Depreciation and amortization	189.2		57.9		10.3		257.4		—		34.0		6.2		(17.3)		280.3
Equity in earnings of transmission affiliates	—		—		—		—		63.7		—		—		—		63.7
Interest expense	137.2		18.1		3.3		158.6		4.9		17.0		30.9		(83.9)		127.5
Income tax expense (benefit)	63.7		5.8		(1.9)		67.6		14.3		1.7		(10.2)		—		73.4
Net income (loss)	195.2		14.9		(6.1)		204.0		44.5		70.4		(17.2)		—		301.7
Net income (loss) attributed to common shareholders	194.9		14.9		(6.1)		203.7		44.5		71.0		(17.2)		—		302.0


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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, 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


	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, 2022
External revenues	$	5,176.5	$	1,354.8	$	410.0	$	6,941.3	$	—	$	97.3	$	0.4	$	—	$	7,039.0
Intersegment revenues	—		—		—		—		—		345.7		—		(345.7)		—
Other operation and maintenance	979.6		292.9		68.5		1,341.0		—		36.9		(13.1)		(7.1)		1,357.7
Depreciation and amortization	564.0		172.1		30.5		766.6		—		102.3		19.5		(50.4)		838.0
Equity in earnings of transmission affiliates	—		—		—		—		148.4		—		—		—		148.4
Interest expense	409.1		53.8		9.8		472.7		14.6		51.6		78.1		(252.1)		364.9
Income tax expense (benefit)	208.4		69.1		9.4		286.9		32.5		(10.5)		(45.0)		—		263.9
Net income (loss)	632.3		184.7		28.1		845.1		101.3		244.0		(32.9)		—		1,157.5
Net income (loss) attributed to common shareholders	631.4		184.7		28.1		844.2		101.3		242.8		(32.9)		—		1,155.4


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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, 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

NOTE 21—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 sources of funds to satisfy the debt obligation. The bondholders have no recourse to WE or any of WE's affiliates other than WEPCo Environmental Trust.

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, 2022		December 31, 2021
Assets
Other current assets (restricted cash)	$	6.0	$	2.4
Regulatory assets	94.0		100.7
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	8.8		8.8

Other current liabilities (accrued interest)	0.5		0.1
Long-term debt	98.5		102.7

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, 2022 and December 31, 2021, our equity investment in ATC was $1,851.8 million and $1,766.9 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, 2022 and December 31, 2021, our equity investment in ATC Holdco was $24.1 million and $22.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

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

Power Purchase Commitment

On May 31, 2022, WE's PPA with LSP-Whitewater Limited Partnership that represented a variable interest expired. This agreement was for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we accounted for it as a finance lease.

In November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022 upon the expiration of the PPA. Concurrent with the execution of the tolling agreement, WE and WPS also entered into an agreement to purchase the natural gas-fired cogeneration facility for $72.7 million. This purchase agreement is subject to regulatory approval by the PSCW, and a decision is expected by the end of 2022. The tolling agreement extends until the earlier of the closing of the asset purchase or December 31, 2022. The tolling agreement continues to represent a variable interest since its terms are substantially similar to the terms of the PPA. After examining the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we have determined 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 tolling agreement. Similar to the PPA, we account for the tolling agreement as a finance lease.

We have $0.9 million of required capacity payments over the remaining term of the tolling agreement. We believe the required capacity payments under the agreement will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.


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NOTE 22—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

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, 2022, including those of our subsidiaries, were approximately $10.6 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

Cross State Air Pollution Rule – Good Neighbor Plan

The EPA issued a proposed rule that would update and expand the Cross-State Air Pollution Rule's ozone-season NOx program to address the 2015 ozone NAAQS, resulting in more stringent regulation of ozone-season NOx emissions from EGUs in 26 states, relying on authorization through the CAA's “good neighbor provision." As part of the proposed rule, expected to take effect in May 2023, the EPA would establish a new trading program that would impose lower NOx emissions budgets on states, at levels that the EPA projected would be achievable through full operation of existing EGU emissions control equipment beginning during ozone season 2023, and through installation of additional control equipment at both EGU and non-EGU stationary sources by the start of the 2026 ozone season, as well as planned plant retirements.

Based on a review of our existing units' 2020 and 2021 actual ozone season emissions and projected future emissions versus proposed NOx ozone season allocations, we anticipate that we should be able to comply with the expanded rule requirements without procuring additional allowances on the open market.

Our RICE units in the Upper Peninsula of Michigan and planned RICE units in Wisconsin are not subject to this rule as proposed as each unit is expected to be less than 25 MW. We note that, to the extent we use RICE engines for natural gas distribution operations, those engines may be subject to the emission limits and operational requirements of the rule beginning in 2026. In June 2022, we submitted comments on this proposed rule seeking clarification of its applicability, as well as other items, and we will closely monitor the final rule for any changes from the proposed rule.

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


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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. In October 2021, the EPA announced that it will reconsider the December 2020 decision to retain the 2015 ozone standards with no changes and that it is targeting the end of 2023 to complete this reconsideration.

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. The area designations were 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 nonattainment area designations and/or 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 "Milwaukee" nonattainment area. Additionally, the Chicago, IL-IN-WI nonattainment area now includes an expanded portion of Kenosha County, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties were also expanded.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations adopted the standard and incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA in April 2022, which the EPA proposed to approve in August 2022.

In April 2022, the EPA proposed to find that the Milwaukee and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, and will be adjusted to "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR must submit a SIP revision to address the moderate nonattainment status. We also expect the moderate nonattainment designation to impact emission offset ratios for major construction permitting in these areas. 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 the associated state and federal rules.

Particulate Matter

In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine particulate matter. The EPA determined that no revisions were necessary to the current annual standard of 12 µg/m3 or the 24-hour standard of 35 µg/m3. 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 µg/m3, while retaining the 24-hour standard. In March 2022, the EPA’s CASAC sent a letter to the EPA finalizing its peer review of the particulate matter standards. Based on their review, the majority of the members of the CASAC found that lowering the annual standard to within a range of 8 to 10 µg/m3 was appropriate, while a minority of the members of the committee found that a range of 10 to 11 µg/m3 would be appropriate. Additionally, a majority of the CASAC members favored lowering the 24-hour standard, while a minority concurred with EPA’s preliminary conclusion to retain the 24-hour standard without revision. In May 2022, the EPA released its staff-written Policy Assessment for the reconsideration of the standard. Similar to the CASAC findings, the EPA staff found that conditions supported either an annual standard in the 10 to 12 µg/m3 range or in the 8 to 10 µg/m3 range.

In August 2022, the EPA sent a proposed rule regarding the review of the particulate matter standards to the Office of Management and Budget, which is expected to be released for public comment by the end of 2022. We anticipate the final rule to be released in spring 2023. All counties within our service territories are in attainment with the current 2012 standards. If the EPA lowers the annual standard to 10 or 11 µg/m3, our generating facilities within our service territories should remain in attainment. If the EPA lowers it to below 10 µg/m3, there could be some nonattainment areas that may affect permitting of some smaller ancillary equipment located at our facilities.

Climate Change

The ACE rule, which replaced the Clean Power Plan, was vacated by the D.C. Circuit Court of Appeals in January 2021. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling vacating the EPA's ACE rule and in June 2022, the Supreme Court issued its decision. The Supreme Court found that the EPA may regulate GHGs under section 111 of the CAA but cannot rely on


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generation shifting to lower carbon emitting sources to do so. Based on an updated EPA regulatory timeline, we expect a new GHG replacement rule to be proposed in March 2023.

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; however, it was vacated by the D.C. Circuit Court of Appeals in April 2021. Based on an updated EPA regulatory timeline, we expect a new rule to be proposed in March 2023. We continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

The EPA released proposed regulations for the Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022. The proposed revisions could impact the reporting required of our local natural gas distribution companies and underground natural gas storage facilities with updates to emission factors for equipment counts and increased disclosure for large release events. We expect the final rule in late 2022 or early 2023, pending the EPA's review and consideration of public comments.

Additionally, we continue to assess the potential impacts of the waste emissions charge included in the IRA pending updates to the regulations.

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. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirements in 2024-2025 of OCPP Units 5-8 and the planned retirement by June 2026 of jointly-owned Columbia Units 1-2. See Note 24, Regulatory Environment, for more information on the timing of the retirements. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% 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.

We also continue to reduce methane emissions by improving our natural gas distribution system, and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our utility systems.

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 and received a final BTA determination 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, NR 111, became effective in June 2020, and the WDNR will apply it when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for WE and WPS facilities.

We have received a final BTA determination for Valley power plant. We have received interim BTA determinations for PWGS, OCPP Units 5-8 and Weston Units 2, 3, and 4. We believe that existing technology at the PWGS satisfies the BTA requirements; however, a final determination will not be made until the WPDES permit is renewed for this facility, which is expected in the fourth quarter of 2022. We also believe that existing technology installed at the OCPP facility meets the BTA requirements; however, depending on the timing of the permit reissuance, all four generating units may be retired prior to the WDNR making a final BTA decision anticipated in 2025. In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance in 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.


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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 system at Weston Unit 3, which is expected to be completed by December 2023. Modifications to OC 7 and OC 8 BATW systems were completed and placed in-service in mid-2021. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require $100 million in capital investment. In December 2021, the PSCW Division of Energy Regulation and Analysis issued a Certificate of Authority approving the ERGS FGD wastewater treatment system modification. The BATW modifications do not require PSCW approval prior to construction. All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023.

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 fourth quarter of 2022.

Waters of the United States

In December 2021, the EPA and the United States Army Corps of Engineers together released a proposed rule to repeal the April 2020 Navigable Waters Protection Rule that defined WOTUS. The purpose of this proposed rule will be to restore regulations defining WOTUS that were in place prior to 2015 and to update certain provisions to be consistent with relevant Supreme Court decisions. 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.

In January 2022, the Supreme Court granted certiorari in a case, Sackett v. Environmental Protection Agency, to evaluate the proper test for determining whether wetlands are WOTUS. The parcel at issue was determined to be a WOTUS by the U.S. Court of Appeals for the Ninth Circuit based on the “significant nexus” test. In October 2022, the Supreme Court heard oral arguments in this case during which Sackett's lawyers argued that the Ninth Circuit wrongly applied the "significant nexus" test to the property. A decision by the Supreme Court is expected in spring 2023.

At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts. This case, once decided, should provide some clarity regarding the definition of WOTUS. We will continue to monitor this litigation and any subsequent agency action.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

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

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


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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, 2022		December 31, 2021
Regulatory assets	$	616.3	$	630.9
Reserves for future environmental remediation	497.7		532.6

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 and expect that process to be completed in 2023.

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 Company, 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 Company, 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 expects to start the process to close out this Consent Decree in early 2023.

NOTE 23—SUPPLEMENTAL CASH FLOW INFORMATION


	Nine Months Ended September 30
(in millions)	2022		2021
Cash paid for interest, net of amount capitalized	$	311.4	$	310.9
Cash paid for income taxes, net	52.3		33.8
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	170.9		144.0
Accounts payable related to Thunderhead acquisition milestone payments	19.0		—
Increase in receivable related to insurance proceeds	—		58.3
Liabilities accrued for software licensing agreement	7.4		—

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 WEC Infrastructure Wind Holding I LLC and WEPCo Environmental Trust. The restricted cash we received when WECI acquired ownership interests in certain wind


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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, 2022		December 31, 2021
Cash and cash equivalents	$	28.5	$	16.3
Restricted cash included in other current assets	35.7		19.6
Restricted cash included in other long term assets	51.8		51.6
Cash, cash equivalents, and restricted cash	$	116.0	$	87.5

NOTE 24—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.

In March 2021, WE and WG received 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 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 also 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 were recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs are being reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation. The ICC could order the refund of any costs determined to be imprudent as part of the reconciliation. A decision regarding this review is expected by the end of 2022.

In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs. In accordance with the order, MERC recovered $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million was to be recovered over a period of 27 months, both beginning in September 2021. Recovery of these costs and the issue of prudence was referred to a contested-case proceeding. In October 2022, the MPUC issued a written order approving a settlement agreement entered into by MERC and various parties related to the recovery of the extraordinary natural gas costs incurred in February 2021. Under the settlement agreement, MERC agreed to not seek recovery of $3 million of these costs. MERC will continue to recover the remaining $62 million of extraordinary natural gas costs over the previously approved 27-month recovery period.

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

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

2023 and 2024 Rates

In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2023. The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments have already been approved by the PSCW. The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.


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In July 2022, WE, WPS, and WG updated their rate requests to reflect recent developments that impacted, as applicable, the respective utility's original proposal for rate increases in 2023. These recent developments included:

•Delays in the in-service dates of Darien and the battery portion of Paris due to supply chain disruptions.

•WE's decision to extend the operating life of the OCPP due to tight energy supply conditions in MISO and the delay in the renewable energy projects discussed above. The expected retirement of the OCPP units 5 and 6 was delayed one year, until May 2024, and the retirement of units 7 and 8 was delayed approximately 18 months, until late 2025.

•Wisconsin Power & Light Company's decision to delay the retirements of the jointly-owned Columbia units. The retirements of the Columbia units, which were originally planned for the end of 2023 and 2024, were delayed until 2026. WPS holds a 27.5% ownership interest in these units.

•Increases in the cost of Badger Hollow II.

•The effect of anticipated increases in interest rates on borrowing costs.

•An industry-wide update to S&P's methodology for assessing the impact of PPAs on utility's credit ratings.

On September 29, 2022, WE, WPS, and WG entered into settlement agreements with certain intervenors to resolve most of the outstanding issues in each utility's respective rate case. The settlement agreements, which are subject to PSCW review and approval, reflect the following:


	WE					WPS					WG
2023 base rate increase
Electric	$	257.9	million	/	8.3%	$	104.3	million	/	8.7%	N/A
Gas	$	53.3	million	/	11.2%	$	31.3	million	/	8.6%	$	57.1	million	/	7.9%
Steam	$	3.4	million	/	15.6%	N/A					N/A
Common equity component average on a financial basis	53.0%					53.0%					53.0%

In addition to the above, the settlement agreements include the following terms:

•The utilities will keep their current earnings sharing mechanisms, under which, if a utility earns above its authorized ROE: (i) the utility will retain 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points will be required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings will be required to be refunded to ratepayers.

•WE will seek a financing order from the PSCW to securitize $100.0 million of the remaining book value of environmental controls installed on the older units at the OCPP by 2024, plus the costs associated with the securitization.

•Upon retirement of the older units at the OCPP, WE will request PSCW approval to extend and levelize the recovery of the remaining un-securitized book value of those units over a 25-year period.

•WE and WPS will not propose any changes to their real-time pricing rates for large commercial and industrial electric customers through the end of 2024.

•WE and WPS will lower monthly residential and small commercial electric customer fixed charges by $1.00 and $2.00, respectively, from currently authorized rates.

•WE and WPS agreed to propose an additional voluntary renewable energy pilot for commercial and industrial customers.

•WE and WPS made commitments related to certain low income assistance programs and agreed to collectively contribute $4.0 million to the Keep Wisconsin Warm Fund.

Each utility's authorized ROE will be decided by the PSCW. WE and WPS requested an authorized ROE of 10.0%, and WG requested an authorized ROE of 10.2%.

WE and WPS are seeking a limited rate case re-opener for 2024 to address additional revenue requirements associated with generation projects that are expected to be placed into service in 2023 and 2024. In addition, WE and WG are seeking a limited rate case re-opener for 2024 to address additional revenue requirements associated with LNG projects that are expected to be placed into service in 2023 and 2024, respectively.

We expect a decision from the PSCW in the fourth quarter of 2022, with rate adjustments expected to be effective January 1, 2023.


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The Peoples Gas Light and Coke Company

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 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending.

As of September 30, 2022, 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.

Minnesota Energy Resources Corporation

2023 Minnesota Rate Case

On November 1, 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates by $40.3 million (9.9%). MERC's request reflects a 10.3% ROE and a common equity component average of 53.0%. The proposed retail natural gas rate increase is primarily driven by increased capital investments as well as inflationary pressure on operating costs. MERC is seeking interim rates totaling $37.0 million, subject to refund, to be effective January 1, 2023.

NOTE 25—NEW ACCOUNTING PRONOUNCEMENTS

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.

Government Assistance

In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832). The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of: (i) the types of assistance received; (ii) an entity’s accounting for the assistance; and (iii) the effect of the assistance on the entity’s financial statements. The update is effective for annual periods beginning after December 15, 2021. We plan to adopt this pronouncement for our fiscal year ending on December 31, 2022, and 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 unaudited financial statements and related notes and our 2021 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 affordability, 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.

In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% 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.

As part of our path toward these goals, we are exploring co-firing with natural gas at our ERGS coal-fired units. By the end of 2030, we expect to use coal as a backup fuel only, and we believe we will be in a position to eliminate coal as an energy source by the end of 2035.

We already have 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. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirement in 2024-2025 of Oak Creek Power Plant Units 5-8 and the planned retirement in 2026 of jointly-owned Columbia Units 1-2. See Note 24, Regulatory Environment, for information on the delay of these planned retirements.


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In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $5.4 billion from 2023-2027 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:

•1,800 MW of utility-scale solar;

•700 MW of battery storage; and

•700 MW of wind.

In addition, we are investing in 300 MW of utility-scale solar within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) partnered with an unaffiliated utility to construct two solar projects now in service in Wisconsin: Two Creeks Solar Park (Two Creeks) and Badger Hollow Solar Park I (Badger Hollow I). WPS owns 100 MW of Two Creeks and 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, which is expected to enter commercial operation in the first half of 2023. Once constructed, WE will own 100 MW of this project.

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;

•the planned purchase of up to 200 MW of capacity in the West Riverside Energy Center — a combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin; and

•the planned purchase of the Whitewater Cogeneration Facility, a natural gas-fired combined-cycle electric generating facility with a capacity of 236.5 MW.

For more details on these projects, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

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 24 Solar Now projects and currently has another five under construction, together totaling more than 30 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. We set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of renewable natural gas (RNG) throughout our utility systems. In 2022, we received approval from the PSCW for our RNG pilots and we signed our first four contracts for RNG for our natural gas distribution business, which will be transporting the output of local dairy farms onto our gas distribution system. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. Our first four contracts should bring us to 90 percent of the RNG needed to achieve our 2030 goal. We expect to have RNG flowing to our distribution network by the end of 2022.

As part of our effort to look for new opportunities in sustainable energy, during 2022 we completed testing the effects of blending hydrogen, a clean generating fuel, with natural gas for one of our RICE generating units in the Upper Peninsula of Michigan. We partnered with the Electric Power Research Institute in this research that could help create another viable option for decarbonizing the economy. We are still evaluating the data; however, our initial findings indicate that all project measures exceeded our expectations. We look forward to sharing the full results with our industry and the public early next year.


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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 and Wisconsin Gas LLC (WG) have received approval to each construct their own liquefied natural gas (LNG) facility to meet anticipated peak demand. Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.

•The Peoples Gas Light and Coke Company continues to work on its Safety 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.

•Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability.

We expect to spend approximately $3.2 billion from 2023 to 2027 on reliability related projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash 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.

Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 3, Disposition, for information on a recent transaction.

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 and one solar park, with total available capacity of more than 1,800 MW. These renewable energy assets represent approximately $2.7 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 information on recent and pending transactions.

We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be approximately $18.1 billion from 2023 to 2027. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $2.0 billion. Specific projects included in the $20.1 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.


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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.

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, 2022

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2022 with the third quarter of 2021, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2022		2021		B (W)
Wisconsin	$	194.9	$	197.5	$	(2.6)
Illinois	14.9		19.1		(4.2)
Other states	(6.1)		(2.7)		(3.4)
Electric transmission	44.5		27.8		16.7
Non-utility energy infrastructure	71.0		64.4		6.6
Corporate and other	(17.2)		(16.1)		(1.1)
Net income attributed to common shareholders	$	302.0	$	290.0	$	12.0

Diluted earnings per share	$	0.96	$	0.92	$	0.04

Earnings increased $12.0 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the $12.0 million increase in earnings were:

•A $16.7 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For more information, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

•A $6.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December


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2021. A positive impact from a sharing arrangement with one of our Blooming Grove customers, resulting from strong energy prices, also contributed to the increase in earnings.

These increases in earnings were partially offset by:

•A $4.2 million decrease in net income attributed to common shareholders at the Illinois segment, driven by an increase in natural gas distribution and maintenance costs, along with higher depreciation and amortization. These negative impacts were partially offset by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider.

•A $3.4 million increase in net loss attributed to common shareholders at the other states segment, driven by increases in various operating expenses, including expenses related to property and revenue taxes, natural gas operations, and customer service. An increase in interest expense, primarily due to a deferral of interest expense during 2021 that is now being amortized over a four-year period, also contributed to the higher net loss.

•A $2.6 million decrease in net income attributed to common shareholders at the Wisconsin segment, driven by a decrease in electric margins related to our expected fuel recovery. This decrease was partially offset by the amortization of certain regulatory liabilities to reduce a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 Wisconsin base rates.

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 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 2022 and 2021:


	Three Months Ended September 30
(in millions)	2022		2021
Wisconsin	$	367.3	$	352.8
Illinois	36.2		40.7
Other states	(5.4)		(2.2)

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).

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $194.9 million during the third quarter of 2022, representing a $2.6 million, or 1.3%, decrease over the same quarter in 2021. The lower earnings were driven by a decrease in electric margins related to our expected fuel recovery. This decrease was partially offset by the amortization of certain regulatory liabilities to reduce a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to


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forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our 2022 Wisconsin base rates.


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Electric revenues	$	1,440.2	$	1,288.2	$	152.0
Fuel and purchased power	605.7		437.7		(168.0)
Total electric margins	834.5		850.5		(16.0)

Natural gas revenues	236.6		170.4		66.2
Cost of natural gas sold	144.0		87.3		(56.7)
Total natural gas margins	92.6		83.1		9.5

Total electric and natural gas margins	927.1		933.6		(6.5)

Other operation and maintenance	329.1		359.1		30.0
Depreciation and amortization	189.2		184.4		(4.8)
Property and revenue taxes	41.5		37.3		(4.2)
Operating income	367.3		352.8		14.5

Other income, net	28.8		16.5		12.3
Interest expense	137.2		137.9		0.7
Income before income taxes	258.9		231.4		27.5

Income tax expense	63.7		33.6		(30.1)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	194.9	$	197.5	$	(2.6)

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line items below	$	164.6	$	169.4	$	4.8
Transmission (1)	107.8		127.8		20.0
Regulatory amortizations and other pass through expenses (2)	35.6		34.4		(1.2)
We Power (3)	26.5		27.5		1.0
Earnings sharing mechanisms (4)	(5.4)		—		5.4
Total other operation and maintenance	$	329.1	$	359.1	$	30.0

(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 third quarter of 2022 and 2021, $134.9 million and $122.7 million, respectively, of costs were billed to our electric utilities by transmission providers.

During the third quarter of 2022, WE and WPS amortized $20.3 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. This amortization drove the decrease in transmission expense during the third quarter of 2022, compared with the same quarter in 2021. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

(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 third quarter of 2022 and 2021, $29.7 million and $20.4 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.


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(4)Represents amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

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	2022	2021	B (W)
Customer Class
Residential	3,225.6	3,374.1	(148.5)
Small commercial and industrial (1)	3,481.8	3,527.7	(45.9)
Large commercial and industrial (1)	3,268.3	3,239.2	29.1
Other	29.8	31.3	(1.5)
Total retail (1)	10,005.5	10,172.3	(166.8)
Wholesale	584.9	744.0	(159.1)
Resale	1,232.5	1,270.3	(37.8)
Total sales in MWh (1)	11,822.9	12,186.6	(363.7)

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


	Three Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	68.8	56.6	12.2
Commercial and industrial	62.8	52.4	10.4
Total retail	131.6	109.0	22.6
Transportation	287.2	280.5	6.7
Total sales in therms	418.8	389.5	29.3


	Three Months Ended September 30
	Degree Days
Weather	2022	2021	B (W)
WE and WG (1)
Heating (98 Normal)	89	22	304.5	%
Cooling (591 Normal)	677	715	(5.3)	%

WPS (2)
Heating (177 Normal)	129	114	13.2	%
Cooling (388 Normal)	468	389	20.3	%

UMERC (3)
Heating (304 Normal)	253	232	9.1	%
Cooling (260 Normal)	243	270	(10.0)	%

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

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

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

Electric Revenues

Electric revenues increased $152.0 million during the third quarter of 2022, compared with the same quarter in 2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in


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revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins at the Wisconsin segment decreased $16.0 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the lower electric utility margins were:

•A $34.4 million decrease in margins related to our expected fuel recovery, driven by higher fuel costs as well as our current fuel forecast and earnings assumptions. 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 generally deferred for future recovery or refund to customers. We will review our actual fuel costs and earnings results at the end of the year and will further adjust our expected fuel recovery accordingly.

•A $12.0 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the third quarter of 2022, compared with the same quarter in 2021. As measured by cooling degree days, the third quarter of 2022 was 5.3% cooler than the same quarter in 2021 in the Milwaukee area.

These decreases in margins were partially offset by a $31.3 million increase in margins related to the impact of unprotected excess deferred taxes during the third quarter of 2021, which we agreed to return to customers in our PSCW-approved rate orders. This increase in margins is offset in income taxes. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on our rate order.

Natural Gas Revenues

Natural gas revenues increased $66.2 million during the third quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 30% during the third quarter of 2022, compared with the same quarter in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $9.5 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the higher natural gas utility margins were:

•A $7.3 million increase in margins from higher sales volumes, driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the third quarter of 2022, compared with the same quarter in 2021. As measured by heating degree days, the third quarter of 2022 was 304.5% and 13.2% colder than the same quarter in 2021 in the Milwaukee area and Green Bay area, respectively.

•A $2.5 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage, LLC. In September 2021, the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K 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 Wisconsin segment decreased $21.0 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the decrease in operating expenses were:

•A $20.0 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

•A $5.4 million decrease in expense driven by the amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism, as discussed in the notes under the other operation and maintenance table above.

•A $4.8 million decrease in benefit costs, primarily driven by lower stock-based compensation and deferred compensation costs.

•A $4.0 million decrease in expense related to 2021 charitable projects supporting our customers and the communities within our service territories.

These decreases in other operating expenses were partially offset by:

•A $4.8 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases. These increases were partially offset by $2.6 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information.

•A $4.2 million increase in property and revenue taxes, driven by higher gross receipt taxes.

•A $3.2 million increase in other operating and maintenance expense related to our power plants, driven by a planned outage at OCPP and reductions in refined coal credits during the third quarter of 2022, compared with the same quarter in 2021.

Other Income, Net

Other income, net at the Wisconsin segment increased $12.3 million during the third quarter of 2022, compared with the same quarter in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our benefit costs. Higher AFUDC–Equity due to continued capital investment also contributed to the increase in other income, net.

Interest Expense

Interest expense at the Wisconsin segment decreased $0.7 million during the third quarter of 2022, compared with the same quarter in 2021, primarily due to the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information. Also contributing to the decrease was lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. These decreases were partially offset by long-term debt issuances in the fourth quarter of 2021 and third quarter of 2022, and higher average short-term debt balances along with higher interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $30.1 million during the third quarter of 2022, compared with the same quarter in 2021. The increase in income tax expense was due to an approximate $31 million negative impact related to the lower quarter-over-quarter 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


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unprotected excess deferred tax benefits in 2021 from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income. See Note 13, 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 $14.9 million during the third quarter of 2022, representing a $4.2 million, or 22.0%, decrease over the same quarter in 2021. The lower earnings were driven by an increase in natural gas distribution and maintenance costs, along with higher depreciation and amortization. These negative impacts were partially offset by higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider.

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)	2022		2021		B (W)
Natural gas revenues	$	230.3	$	216.2	$	14.1
Cost of natural gas sold	27.4		22.4		(5.0)
Total natural gas margins	202.9		193.8		9.1

Other operation and maintenance	100.2		91.2		(9.0)
Depreciation and amortization	57.9		55.4		(2.5)
Property and revenue taxes	8.6		6.5		(2.1)
Operating income	36.2		40.7		(4.5)

Other income, net	2.6		1.9		0.7
Interest expense	18.1		16.5		(1.6)
Income before income taxes	20.7		26.1		(5.4)

Income tax expense	5.8		7.0		1.2
Net income attributed to common shareholders	$	14.9	$	19.1	$	(4.2)

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in the line items below	$	84.9	$	76.2	$	(8.7)
Riders (1)	16.0		15.5		(0.5)
Regulatory amortizations (1)	(0.7)		(0.5)		0.2

Total other operation and maintenance	$	100.2	$	91.2	$	(9.0)

(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	2022	2021	B (W)
Customer Class
Residential	45.7	42.8	2.9
Commercial and industrial	23.5	24.1	(0.6)
Total retail	69.2	66.9	2.3
Transportation	93.3	87.6	5.7
Total sales in therms	162.5	154.5	8.0


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	Three Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
Heating (68 Normal)	86	18	377.8	%

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

Natural Gas Revenues

Natural gas revenues increased $14.1 million during the third quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 18% during the third quarter of 2022, compared with the same quarter in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $0.5 million impact of the riders referenced in the table above, increased $8.6 million during the third quarter of 2022, compared with the same quarter in 2021. 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. See Note 24, Regulatory Environment, for more information.

•A $2.4 million increase related to fixed customer charges during the third quarter of 2022, compared with the same quarter in 2021.

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

Other operating expenses at the Illinois segment increased $13.1 million, net of the $0.5 million impact of the riders referenced in the table above, during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the increase in operating expenses were:

•A $7.0 million increase in natural gas distribution and maintenance costs.

•A $2.5 million increase in depreciation and amortization expense, primarily driven by PGL's continued capital investment in the SMP project.

•A $1.9 million increase in customer service expense, primarily driven by higher call volumes.

Interest Expense

Interest expense at the Illinois segment increased $1.6 million during the third quarter of 2022, compared with the same quarter in 2021, primarily due to $225.0 million of long-term debt issuances in November 2021.

Income Tax Expense

Income tax expense at the Illinois segment decreased $1.2 million during the third quarter of 2022, compared with the same quarter in 2021, driven by a decrease in pre-tax income.


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Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $6.1 million during the third quarter of 2022, representing a $3.4 million, or 125.9%, increase in net loss over the same quarter in 2021. The higher net loss was driven by increases in various operating expenses, including expenses related to property and revenue taxes, natural gas operations, and customer service. An increase in interest expense, primarily due to a deferral of interest expense during 2021 that is now being amortized over a four-year period, also contributed to the higher net loss.

Since the majority of MERC and MGU 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)	2022		2021		B (W)
Natural gas revenues	$	69.2	$	52.8	$	16.4
Cost of natural gas sold	36.6		21.6		(15.0)
Total natural gas margins	32.6		31.2		1.4

Other operation and maintenance	21.0		19.6		(1.4)
Depreciation and amortization	10.3		9.6		(0.7)
Property and revenue taxes	6.7		4.2		(2.5)
Operating loss	(5.4)		(2.2)		(3.2)

Other income, net	0.7		0.1		0.6
Interest expense	3.3		1.6		(1.7)
Loss before income taxes	(8.0)		(3.7)		(4.3)

Income tax benefit	(1.9)		(1.0)		0.9
Net loss attributed to common shareholders	$	(6.1)	$	(2.7)	$	(3.4)

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line item below	$	18.3	$	16.3	$	(2.0)
Regulatory amortizations and other pass through expenses (1)	2.7		3.3		0.6

Total other operation and maintenance	$	21.0	$	19.6	$	(1.4)

(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	2022	2021	B (W)
Customer Class
Residential	15.9	16.0	(0.1)
Commercial and industrial	15.1	16.7	(1.6)
Total retail	31.0	32.7	(1.7)
Transportation	164.4	183.6	(19.2)
Total sales in therms	195.4	216.3	(20.9)


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	Three Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
MERC
Heating (204 Normal)	184	120	53.3	%

MGU
Heating (112 Normal)	112	54	107.4	%

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

Natural Gas Revenues

Natural gas revenues increased $16.4 million during the third quarter of 2022, compared with the same quarter in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 88% during the third quarter of 2022, compared with the same quarter in 2021. See the discussion of natural gas utility margins below for the remaining drivers of changes in natural gas revenues.

Natural Gas Utility Margins

Natural gas utility margins increased $1.4 million during the third quarter of 2022, compared with the same quarter in 2021, primarily driven by a $0.9 million increase 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.

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 $4.6 million during the third quarter of 2022, compared with the same quarter in 2021. The significant factors impacting the increase in operating expenses were:

•A $2.5 million increase in property and revenue taxes, driven by higher use tax at MGU.

•A $1.9 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case.

Interest Expense

Interest expense at the other states segment increased $1.7 million during the third quarter of 2022, compared with the same quarter in 2021, primarily due to the deferral of $1.2 million of interest expense in the third quarter of 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of MGU's 2021 rate case. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.


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Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Equity in earnings of transmission affiliates	$	63.7	$	42.3	$	21.4

Interest expense	4.9		4.8		(0.1)
Income before income taxes	58.8		37.5		21.3

Income tax expense	14.3		9.7		(4.6)
Net income attributed to common shareholders	$	44.5	$	27.8	$	16.7

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $21.4 million during the third quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on this D.C. Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

Income Tax Expense

Income tax expense at the electric transmission segment increased $4.6 million during the third quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to an increase in pre-tax income.

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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operating income	$	89.1	$	85.4	$	3.7

Interest expense	17.0		17.6		0.6
Income before income taxes	72.1		67.8		4.3

Income tax expense	1.7		5.0		3.3
Net loss attributed to noncontrolling interests	0.6		1.6		(1.0)
Net income attributed to common shareholders	$	71.0	$	64.4	$	6.6

Operating Income

Operating income at the non-utility energy infrastructure segment increased $3.7 million during the third quarter of 2022, compared with the same quarter in 2021. The increase was primarily due to a $2.7 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

Income Tax Expense

Income tax expense at the non-utility energy infrastructure segment decreased $3.3 million during the third quarter of 2022, compared with the same quarter in 2021. The decrease was primarily due to a $3.9 million increase in PTCs in 2022, driven by the Jayhawk wind park achieving commercial operation in December 2021. This favorable change in income tax expense was partially offset by higher pre-tax earnings during the third quarter of 2022, compared with same quarter in 2021.


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


	Three Months Ended September 30
(in millions)	2022		2021		B (W)
Operating income (loss)	$	0.3	$	(1.9)	$	2.2

Other income, net	3.2		7.0		(3.8)
Interest expense	30.9		24.7		(6.2)

Loss before income taxes	(27.4)		(19.6)		(7.8)

Income tax benefit	(10.2)		(3.5)		6.7
Net loss attributed to common shareholders	$	(17.2)	$	(16.1)	$	(1.1)

Operating Income (Loss)

The corporate and other segment had operating income of $0.3 million during the third quarter of 2022, compared with an operating loss of $1.9 million during the same quarter in 2021. The $2.2 million increase was driven by higher operating income at Wispark, primarily due to a payment on a note receivable that was previously written down due to uncertainty regarding its collectibility.

Other Income, Net

Other income, net at the corporate and other segment decreased $3.8 million during the third quarter of 2022, compared with the same quarter in 2021, driven by a $3.7 million decrease in earnings from our equity method investments in technology and energy-focused investment funds.

Interest Expense

Interest expense at the corporate and other segment increased $6.2 million during the third quarter of 2022, compared with the same quarter in 2021, due to higher average short-term debt balances at the parent company along with higher interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $6.7 million during the third quarter of 2022, compared with the same quarter in 2021, driven by a $4.5 million quarter-over-quarter increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate. Also contributing to the favorable change in the income tax benefit were a higher pre-tax loss and a $1.4 million increase in excess tax benefits recognized related to stock option exercises during the third quarter of 2022, compared with the same quarter in 2021.


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NINE MONTHS ENDED SEPTEMBER 30, 2022

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2022 with the nine months ended September 30, 2021, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2022		2021		B (W)
Wisconsin	$	631.4	$	600.3	$	31.1
Illinois	184.7		174.8		9.9
Other states	28.1		24.5		3.6
Electric transmission	101.3		82.8		18.5
Non-utility energy infrastructure	242.8		204.6		38.2
Corporate and other	(32.9)		(10.9)		(22.0)
Net income attributed to common shareholders	$	1,155.4	$	1,076.1	$	79.3

Diluted Earnings Per Share	$	3.65	$	3.40	$	0.25

Earnings increased $79.3 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the $79.3 million increase in earnings were:

•A $38.2 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs during 2022, primarily due to the Jayhawk wind park that achieved commercial operation in December 2021, an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS, and higher generation at our other wind parks. In addition, Upstream recognized revenue during 2022 related to market settlements it received from SPP in February 2021. Due to a complaint filed with the FERC, the revenue related to these settlements could not be recognized until the FERC issued an order denying the complaint in the first quarter of 2022. A positive impact from a sharing arrangement with one of our Blooming Grove customers, resulting from strong energy prices, also contributed to the increase in earnings.

•A $31.1 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings. These increases in earnings were partially offset by a decrease in electric margins related to our expected fuel recovery and higher depreciation and amortization.

•An $18.5 million increase in net income attributed to common shareholders at the electric transmission segment, primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE.

•A $9.9 million increase in net income attributed to common shareholders at the Illinois segment, driven by a gain on the sale of certain real estate in Chicago, as well as higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and NSG's rate increase, effective September 15, 2021. These positive impacts were partially offset by increases in various operating expenses, including expenses related to natural gas distribution and maintenance, the settlement of legal claims, charitable projects, and depreciation and amortization.

These increases in earnings were partially offset by a $22.0 million increase in net loss attributed to common shareholders at the corporate and other segment, driven by net losses from the investments held in the Integrys rabbi trust during the first nine months of 2022, compared with net gains during the same period in 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. A decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the higher net loss. These negative impacts were partially offset by an increase in certain income tax benefits.


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Expected 2022 Annual Effective Tax Rate

We expect our 2022 annual effective tax rate to be between 18.5% and 19.5%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

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, 2022 and 2021:


	Nine Months Ended September 30
(in millions)	2022		2021
Wisconsin	$	1,174.1	$	1,072.0
Illinois	296.3		283.8
Other states	45.5		36.7


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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 $631.4 million during the nine months ended September 30, 2022, representing a $31.1 million, or 5.2%, increase over the same period in 2021. The higher earnings were driven by lower operation and maintenance expense, largely due to the amortization of certain regulatory liabilities to offset a portion of our 2022 forecasted revenue deficiencies. The amortization was approved by the PSCW in order to forego filing for 2022 base rate increases. An increase in natural gas margins related to higher retail sales volumes, as well as higher net credits from the non-service components of our net periodic pension and OPEB costs, also contributed to the increase in earnings. These increases in earnings were partially offset by a decrease in electric margins related to our expected fuel recovery and higher depreciation and amortization.


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Electric revenues	$	3,858.7	$	3,482.0	$	376.7
Fuel and purchased power	1,485.5		1,133.2		(352.3)
Total electric margins	2,373.2		2,348.8		24.4

Natural gas revenues	1,317.8		1,015.8		302.0
Cost of natural gas sold	850.0		591.6		(258.4)
Total natural gas margins	467.8		424.2		43.6

Total electric and natural gas margins	2,841.0		2,773.0		68.0

Other operation and maintenance	979.6		1,047.1		67.5
Depreciation and amortization	564.0		540.4		(23.6)
Property and revenue taxes	123.3		113.5		(9.8)
Operating income	1,174.1		1,072.0		102.1

Other income, net	75.7		51.8		23.9
Interest expense	409.1		417.8		8.7
Income before income taxes	840.7		706.0		134.7

Income tax expense	208.4		104.8		(103.6)
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	631.4	$	600.3	$	31.1

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line items below	$	483.3	$	472.8	$	(10.5)
Transmission (1)	323.1		383.1		60.0
Regulatory amortizations and other pass through expenses (2)	108.0		104.9		(3.1)
We Power (3)	81.4		86.3		4.9


Earnings sharing mechanisms (4)	(16.2)		—		16.2
Total other operation and maintenance	$	979.6	$	1,047.1	$	67.5

(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, 2022 and 2021, $391.5 million and $378.1 million, respectively, of costs were billed to our electric utilities by transmission providers.

During the nine months ended September 30, 2022, WE and WPS amortized $60.8 million of the regulatory liabilities associated with their transmission escrows to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases. This amortization drove the decrease in transmission expense during the nine months ended September 30, 2022, compared with the same period in 2021.


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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, 2022 and 2021, $80.6 million and $72.0 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	2022	2021	B (W)
Customer Class
Residential	8,726.7	8,838.5	(111.8)
Small commercial and industrial (1)	9,793.9	9,699.6	94.3
Large commercial and industrial (1)	9,238.8	9,365.8	(127.0)
Other	98.9	104.9	(6.0)
Total retail (1)	27,858.3	28,008.8	(150.5)
Wholesale	1,942.8	2,181.4	(238.6)
Resale	3,326.7	4,552.5	(1,225.8)
Total sales in MWh (1)	33,127.8	34,742.7	(1,614.9)

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


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	810.0	715.0	95.0
Commercial and industrial	515.4	439.0	76.4
Total retail	1,325.4	1,154.0	171.4
Transportation	1,054.8	1,018.9	35.9
Total sales in therms	2,380.2	2,172.9	207.3


	Nine Months Ended September 30
	Degree Days
Weather	2022	2021	B (W)
WE and WG (1)
Heating (4,288 Normal)	4,254	3,880	9.6	%
Cooling (762 Normal)	936	1,018	(8.1)	%

WPS (2)
Heating (4,787 Normal)	4,880	4,450	9.7	%
Cooling (532 Normal)	717	631	13.6	%

UMERC (3)
Heating (5,461 Normal)	5,824	5,115	13.9	%
Cooling (342 Normal)	358	426	(16.0)	%

(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.


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

Electric Revenues

Electric revenues increased $376.7 million during the nine months ended September 30, 2022, compared with the same period in 2021. To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues. See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $24.4 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the higher electric utility margins were:

•An $85.4 million increase in margins related to the impact of unprotected excess deferred taxes during the nine months ended September 30, 2021, which we agreed to return to customers in our PSCW-approved rate orders. This increase in margins is offset in income taxes.

•A $9.4 million increase in other revenues, primarily related to third-party use of our assets.

These increases in margins were partially offset by:

•A $52.8 million decrease in margins related to our expected fuel recovery, driven by higher fuel costs as well as our current fuel forecast and earnings assumptions. 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 generally deferred for future recovery or refund to customers. We will review our actual fuel costs and earnings results at the end of the year and will further adjust our expected fuel recovery accordingly.

•Lower margins of $10.7 million driven by the expiration of certain wholesale contracts.

•A $7.5 million net decrease in margins related to lower sales volumes, driven by the impact of cooler weather during the nine months ended September 30, 2022, compared with the same period in 2021. As measured by cooling degree days, the nine months ended September 30, 2022 were 8.1% cooler than the same period in 2021 in the Milwaukee area.

Natural Gas Revenues

Natural gas revenues increased $302.0 million during the nine months ended September 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 26% during the nine months ended September 30, 2022, compared with the same period in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $43.6 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the higher natural gas utility margins were:

•A $37.1 million increase in margins from higher sales volumes, primarily driven by the continued economic recovery in Wisconsin from the COVID-19 pandemic, as well as colder weather during the nine months ended September 30, 2022, compared with the same period in 2021. As measured by heating degree days, the nine months ended September 30, 2022 were 9.6% and 9.7% colder than the same period in 2021 in the Milwaukee area and Green Bay area, respectively.

•A $7.4 million increase in margins related to the amortization of a certain portion of WG's regulatory liability consisting of credit balances associated with the escrow of natural gas storage service costs from Bluewater Gas Storage, LLC. In September 2021,


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the PSCW issued a written order for our Wisconsin utilities approving certain accounting treatments to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

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

Other operating expenses at the Wisconsin segment decreased $34.1 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the decrease in operating expenses were:

•A $60.0 million decrease in transmission expense driven by the amortization of a certain portion of WE's and WPS's regulatory liabilities associated with transmission escrow balances, as discussed in the notes under the other operation and maintenance table above.

•A $16.2 million decrease in expense driven by the amortization of a certain portion of WPS's regulatory liability associated with its 2020 earnings sharing mechanism, as discussed in the notes under the other operation and maintenance table above.

•A $4.9 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

•A $4.0 million decrease in expense related to 2021 charitable projects supporting our customers and the communities within our service territories.

•A $3.1 million decrease in expense related to a gain on land sales during the nine months ended September 30, 2022, compared with the same period in 2021.

•A $3.1 million decrease in benefit costs, primarily driven by lower deferred compensation costs.

These decreases in other operating expenses were partially offset by:

•A $23.6 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and an increase related to the We Power leases. These increases were partially offset by $7.7 million of deferred depreciation related to capital investments made by WG since it's last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

•A $21.9 million increase in electric and natural gas distribution expenses, primarily driven by higher costs to maintain system reliability and for storm restoration expense during the nine months ended September 30, 2022, compared with the same period in 2021.

•A $9.8 million increase in property and revenue taxes, driven by higher gross receipt taxes.

•A $4.5 million increase in other operating and maintenance expense related to our power plants, driven by a planned outage at the Weston power plant and reductions in refined coal credits during the nine months ended September 30, 2022, compared with the same period in 2021.

Other Income, Net

Other income, net at the Wisconsin segment increased $23.9 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs.

Interest Expense

Interest expense at the Wisconsin segment decreased $8.7 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to the deferral of interest expense related to capital investments made by WG since its last rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases. Also contributing to the decrease was lower interest expense on finance lease


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liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. These decreases were partially offset by long-term debt issuances in the fourth quarter of 2021, and higher average short-term debt balances along with higher interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $103.6 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase was primarily due to an approximate $85 million negative impact related to the lower period-over-period 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 in 2021 from the Tax Legislation did not impact earnings as there was an offsetting impact in operating income. Also contributing to the increase was higher pre-tax income in 2022.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $184.7 million during the nine months ended September 30, 2022, representing a $9.9 million, or 5.7%, increase over the same period in 2021. The increase was driven by a gain on the sale of certain real estate in Chicago, as well as higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider and NSG's rate increase, effective September 15, 2021. These positive impacts were partially offset by increases in various operating expenses, including expenses related to natural gas distribution and maintenance, the settlement of legal claims, charitable projects, and depreciation and amortization.


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Natural gas revenues	$	1,354.8	$	1,195.1	$	159.7
Cost of natural gas sold	564.0		435.0		(129.0)
Total natural gas margins	790.8		760.1		30.7

Other operation and maintenance	292.9		291.3		(1.6)
Depreciation and amortization	172.1		162.1		(10.0)
Property and revenue taxes	29.5		22.9		(6.6)
Operating income	296.3		283.8		12.5

Other income, net	11.3		5.0		6.3
Interest expense	53.8		49.6		(4.2)
Income before income taxes	253.8		239.2		14.6

Income tax expense	69.1		64.4		(4.7)
Net income attributed to common shareholders	$	184.7	$	174.8	$	9.9

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in the line items below	$	208.7	$	211.7	$	3.0
Riders (1)	85.9		81.3		(4.6)
Regulatory amortizations (1)	(1.7)		(1.7)		—

Total other operation and maintenance	$	292.9	$	291.3	$	(1.6)

(1)These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.


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


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	620.7	572.4	48.3
Commercial and industrial	248.9	226.1	22.8
Total retail	869.6	798.5	71.1
Transportation	585.9	544.1	41.8
Total sales in therms	1,455.5	1,342.6	112.9


	Nine Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
Heating (3,887 Normal)	4,017	3,673	9.4	%

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

Natural Gas Revenues

Natural gas revenues increased $159.7 million during the nine months ended September 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. The average per-unit cost of natural gas increased 19% during the nine months ended September 30, 2022, compared with the same period in 2021. The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $4.6 million impact of the riders referenced in the table above, increased $26.1 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase in margins was primarily driven by:

•An $18.7 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 $7.4 million increase related to the impact of the NSG rate order approved by the ICC, effective September 15, 2021, which includes the Variable Income Tax Adjustment Rider in base rates. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on the 2021 rate order.

•A $3.5 million increase in the invested capital tax adjustment rider, which did not impact net income as it was offset in property and revenue taxes. The invested capital tax adjustment rider is a mechanism that allows PGL and NSG to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

These increases in natural gas utility margins were partially offset by a $3.2 million decrease related to fixed customer charges.

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

Other operating expenses at the Illinois segment increased $13.6 million, net of the $4.6 million impact of the riders referenced in the table above, during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the increase in operating expenses were:

•An $11.9 million increase in natural gas distribution and maintenance costs.


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•An $11.2 million increase in expenses associated with the settlement of legal claims.

•A $10.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories.

•A $10.0 million increase in depreciation and amortization expense, primarily driven by PGL's continued capital investment in the SMP project.

•A $7.5 million increase in benefit costs, primarily due to higher pension and stock-based compensation costs.

•A $6.6 million increase in property and revenue taxes, primarily driven by an increase in the invested capital tax related to continued capital investment. This increase was offset in natural gas utility margins.

•A $5.0 million increase in costs associated with maintenance at the Manlove Gas Storage Field.

•A $2.6 million increase in customer service expense, primarily driven by higher call volumes.

These increases in operating expenses were partially offset by a $54.5 million pre-tax gain on the sale of certain real estate in Chicago. See Note 3, Disposition, for more information.

Other Income, Net

Other income, net at the Illinois segment increased $6.3 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $4.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to $225.0 million of long-term debt issuances in November 2021.

Income Tax Expense

Income tax expense at the Illinois segment increased $4.7 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by an increase in pre-tax income.

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 $28.1 million during the nine months ended September 30, 2022, representing a $3.6 million, or 14.7%, increase over the same period in 2021. The increase was driven by higher natural gas margins due to a rate increase at MGU, effective January 1, 2022, and higher sales volumes during the nine months ended September 30, 2022, compared with the same period in 2021. These positive impacts were partially offset by increases in operating expenses, as well as interest expense, as discussed below.


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Since the majority of MERC and MGU 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)	2022		2021		B (W)
Natural gas revenues	$	410.0	$	358.2	$	51.8
Cost of natural gas sold	249.3		215.7		(33.6)
Total natural gas margins	160.7		142.5		18.2

Other operation and maintenance	68.5		64.0		(4.5)
Depreciation and amortization	30.5		28.2		(2.3)
Property and revenue taxes	16.2		13.6		(2.6)
Operating income	45.5		36.7		8.8

Other income, net	1.8		0.6		1.2
Interest expense	9.8		4.6		(5.2)
Income before income taxes	37.5		32.7		4.8

Income tax expense	9.4		8.2		(1.2)
Net income attributed to common shareholders	$	28.1	$	24.5	$	3.6

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operation and maintenance not included in line item below	$	54.6	$	48.9	$	(5.7)
Regulatory amortizations and other pass through expenses (1)	13.9		15.1		1.2

Total other operation and maintenance	$	68.5	$	64.0	$	(4.5)

(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 delivered sales volumes by customer class and weather statistics:


	Nine Months Ended September 30
	Therms (in millions)
Natural Gas Sales Volumes	2022	2021	B (W)
Customer Class
Residential	240.5	208.5	32.0
Commercial and industrial	155.9	127.5	28.4
Total retail	396.4	336.0	60.4
Transportation	590.3	588.6	1.7
Total sales in therms	986.7	924.6	62.1


	Nine Months Ended September 30
	Degree Days
Weather (1)	2022	2021	B (W)
MERC
Heating (5,118 Normal)	5,608	4,816	16.4	%

MGU
Heating (4,046 Normal)	4,142	3,878	6.8	%


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Natural Gas Revenues

Natural gas revenues increased $51.8 million during the nine months ended September 30, 2022, compared with the same period in 2021. Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues. See the discussion of natural gas utility margins below for the remaining drivers of changes in natural gas revenues.

Natural Gas Utility Margins

Natural gas utility margins increased $18.2 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase in margins was primarily driven by:

•A $9.0 million increase related to the new rates at MGU that went into effect in 2022. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on the 2021 rate order.

•A $6.0 million increase related to higher sales volumes due to both continued economic recovery and colder weather during the nine months ended September 30, 2022, compared with the same period in 2021.

•A $1.4 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.

•A $1.4 million increase related to MERC's GUIC rider.

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 $9.4 million during the nine months ended September 30, 2022, compared with the same period in 2021. The significant factors impacting the increase in operating expenses were:

•A $4.2 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects approved in MGU's rate case.

•A $2.6 million increase in property and revenue taxes, driven by higher use tax at MGU.

•A $2.3 million increase in depreciation and amortization related to continued capital investment.

•A $1.4 million increase in operation and maintenance expense related to MERC's CIP, which has an offsetting increase in margins.

These increases in operating expenses were partially offset by a $2.5 million decrease in bad debt expense.

Other Income, Net

Other income, net at the other states segment increased $1.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 17, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the other states segment increased $5.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to the deferral of $3.7 million of interest expense during the first nine months of 2021, as approved by the MPSC to mitigate the impacts from delaying the filing of MGU's 2021 rate case. This deferred interest expense is now being amortized over a four-year period as a result of MGU's approved rate increase.


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Income Tax Expense

Income tax expense at the other states segment increased $1.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by an increase in pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Equity in earnings of transmission affiliates	$	148.4	$	126.2	$	22.2

Interest expense	14.6		14.5		(0.1)
Income before income taxes	133.8		111.7		22.1

Income tax expense	32.5		28.9		(3.6)
Net income attributed to common shareholders	$	101.3	$	82.8	$	18.5

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $22.2 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase was primarily due to the impact of the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on this D.C. Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

Income Tax Expense

Income tax expense at the electric transmission segment increased $3.6 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to an increase in pre-tax income.

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operating income	$	285.1	$	261.6	$	23.5

Interest expense	51.6		53.5		1.9
Income before income taxes	233.5		208.1		25.4

Income tax expense (benefit)	(10.5)		5.8		16.3
Net (income) loss attributed to noncontrolling interests	(1.2)		2.3		(3.5)
Net income attributed to common shareholders	$	242.8	$	204.6	$	38.2

Operating Income

Operating income at the non-utility energy infrastructure segment increased $23.5 million during the nine months ended September 30, 2022, compared with the same period in 2021. The increase was primarily due to the recognition of $15.2 million in revenue related to our Upstream wind park in the first quarter of 2022 that was associated with market settlements received from SPP in February 2021. These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until the FERC issued an order denying that complaint in the first quarter of 2022. In addition, there was an $8.8 million positive impact from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.


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Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $1.9 million during the nine months ended September 30, 2022, compared with the same period in 2021, primarily due to a lower principal balance as a result of the semi-annual principal payments on long-term debt.

Income Tax Expense (Benefit)

At the non-utility energy infrastructure segment, $10.5 million of income tax benefit was recorded during the nine months ended September 30, 2022, compared with $5.8 million of income tax expense recorded during the same period in 2021. The change was primarily due to a $22.4 million increase in PTCs in 2022, driven by the Jayhawk wind park that achieved commercial operation in December 2021, an increase in the PTC rate related to the PTC inflation adjustment issued by the IRS, and higher generation at our other wind parks. This favorable change in the income tax benefit was partially offset by higher pre-tax earnings during the nine months ended September 30, 2022.

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


	Nine Months Ended September 30
(in millions)	2022		2021		B (W)
Operating loss	$	(6.0)	$	(10.4)	$	4.4

Other income, net	6.2		40.7		(34.5)
Interest expense	78.1		73.5		(4.6)

Loss before income taxes	(77.9)		(43.2)		(34.7)

Income tax benefit	(45.0)		(32.3)		12.7
Net loss attributed to common shareholders	$	(32.9)	$	(10.9)	$	(22.0)

Operating Loss

The operating loss at the corporate and other segment decreased $4.4 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by higher operating income at Wispark, primarily due to a payment on a note receivable that was previously written down due to uncertainty regarding its collectibility. Higher gains on land sales also contributed to the increase in operating income at Wispark.

Other Income, Net

Other income, net at the corporate and other segment decreased $34.5 million during the nine months ended September 30, 2022, compared with the same period in 2021. The decrease was driven by a $16.5 million net loss from the investments held in the Integrys rabbi trust during the first nine months of 2022, compared with a $10.8 million net gain during the same period in 2021. The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are included in other operation and maintenance expense in our operating segments. See Note 14, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust. An $11.8 million decrease in earnings from our equity method investments in technology and energy-focused investment funds also contributed to the lower other income, net.

Interest Expense

Interest expense at the corporate and other segment increased $4.6 million during the nine months ended September 30, 2022, compared with the same period in 2021, due to higher average short-term debt balances at the parent company and higher interest rates. This increase was partially offset by lower interest rates related to long-term debt obligations that were refinanced during the fourth quarter of 2021 in order to take advantage of lower interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $12.7 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by a higher pre-tax loss. Also contributing to the increase in the income tax


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benefit was a $6.0 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate and a $5.7 million increase in excess tax benefits recognized related to stock option exercises, during the nine months ended September 30, 2022, compared with the same period in 2021. These increases in income tax benefits were partially offset by $7.5 million of uncertain tax positions primarily recorded in the first quarter of 2021.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We expect to maintain adequate liquidity to meet our cash requirements for the operation of our businesses and implementation of our corporate strategy through the internal generation of cash from operations and access to the capital markets.

Cash Flows

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


(in millions)	2022		2021		Change in 2022 Over 2021
Cash provided by (used in):
Operating activities	$	2,059.5	$	2,006.7	$	52.8
Investing activities	(1,985.9)		(1,688.7)		(297.2)
Financing activities	(45.1)		(281.4)		236.3

Operating Activities

Net cash provided by operating activities increased $52.8 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by:

•A $573.0 million increase in cash from higher overall collections from customers as a result of an increase in natural gas sales volumes during the nine months ended September 30, 2022, compared with the same period in 2021, driven by the continued economic recovery from the COVID-19 pandemic and colder weather. In addition, we continued to recover on the natural gas costs we under-collected from our Illinois and Minnesota customers related to the extreme weather conditions that occurred in February 2021. See Note 24, Regulatory Environment, for more information on the recovery of these natural gas costs.

•A $54.7 million increase in cash due to realized gains on derivative instruments during the nine months ended September 30, 2022.

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

•A $315.6 million decrease in cash from higher payments for fuel and purchased power at our plants during the nine months ended September 30, 2022, compared with the same period in 2021. Our plants incurred higher fuel costs during the nine months ended September 30, 2022, as a result of an increase in the price of natural gas.

•A $198.6 million decrease in cash from higher payments for other operation and maintenance expenses. During the nine months ended September 30, 2022, our payments were higher for reliability and storm restoration, transmission, natural gas distribution and maintenance costs, benefit costs, and natural gas storage maintenance costs.

•A $26.9 million decrease in cash related to higher payments for environmental remediation from work completed on former manufactured gas plant sites during the nine months ended September 30, 2022, compared with the same period in 2021.

•An $18.5 million decrease in cash related to higher cash paid for income taxes, driven by higher taxable income during the nine months ended September 30, 2022, compared with the same period in 2021.

•An $18.4 million decrease in cash related to higher cash paid for property and revenue taxes, driven by higher gross receipt taxes as well as an increase in the Illinois invested capital tax related to continued capital investment during the nine months ended September 30, 2022, compared with the same period in 2021.


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Investing Activities

Net cash used in investing activities increased $297.2 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by:

•The acquisition of a 90% ownership interest in Thunderhead in September 2022 for $362.9 million. See Note 2, Acquisitions, for more information.

•A $72.8 million increase in cash paid for capital expenditures during the nine months ended September 30, 2022, compared with the same period in 2021, which is discussed in more detail below.

•Capital contributions paid to transmission affiliates of $39.4 million during the nine months ended September 30, 2022. See Note 19, Investment in Transmission Affiliates, for more information. There were no payments to transmission affiliates during the same period in 2021.

•An $18.4 million increase in cash paid for ATC's construction costs during the nine months ended September 30, 2022, which will be reimbursed in the future.

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

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

•A $47.4 million increase in proceeds from the sale of assets during the nine months ended September 30, 2022, compared with the same period in 2021, primarily related to the sale of real estate owned by PGL. See Note 3, Disposition, for more information.

•Insurance proceeds of $41.6 million received during the nine months ended September 30, 2022 for property damage, primarily related to the PSB water damage claim. See Note 7, Property, Plant, and Equipment, for more information.

Capital Expenditures

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


Reportable Segment (in millions)	2022		2021		Change in 2022 Over 2021
Wisconsin	$	1,189.0	$	1,028.5	$	160.5
Illinois	364.7		387.9		(23.2)
Other states	69.3		64.5		4.8
Non-utility energy infrastructure	63.3		136.7		(73.4)
Corporate and other	14.4		10.3		4.1
Total capital expenditures	$	1,700.7	$	1,627.9	$	72.8

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2022, compared with the same period in 2021, was primarily driven by higher payments for capital expenditures related to Paris and other renewable energy projects, the new natural gas-fired generation being constructed at WPS's existing Weston power plant site, and WG's LNG facility. These increases were partially offset by lower capital expenditures related to upgrades to WE's and WPS's natural gas and electric distribution systems, the restoration of WE's PSB, and WPS's Crane Creek. See Note 7, Property, Plant, and Equipment, for more information on the PSB.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2022, compared with the same period in 2021, was primarily driven by lower capital expenditures related to upgrades at the Manlove Gas Storage Field, partially offset by increased capital expenditures for upgrades to PGL's natural gas distribution system.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2022, compared with the same period in 2021, was primarily driven by lower capital expenditures related to the construction of Jayhawk, which went into commercial operation in December 2021. See Note 2, Acquisitions, for more information


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about Jayhawk. This decrease in cash paid for capital expenditures was partially offset by an increase in capital expenditures for wastewater treatment system modifications for We Power's ERGS units. See Note 22, Commitments and Contingencies, for more information on the wastewater treatment system modifications.

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

Financing Activities

Net cash used in financing activities decreased $236.3 million during the nine months ended September 30, 2022, compared with the same period in 2021, driven by:

•A $381.2 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2022, compared with the same period in 2021.

•A $340.0 million increase in cash due to a repayment of a 364-day term loan during the nine months ended September 30, 2021.

•A $291.3 million increase in cash due to a decrease in retirements of long-term debt during the nine months ended September 30, 2022, compared with the same period in 2021.

•A $26.6 million increase in cash proceeds related to stock options exercised during the nine months ended September 30, 2022, compared with the same period in 2021.

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

•A $711.7 million decrease in cash due to $640.2 million of net repayments of commercial paper during the nine months ended September 30, 2022, compared with $71.5 million of net borrowings of commercial paper during the same period in 2021.

•A $52.6 million decrease in cash due to an increase in common stock purchased during the nine months ended September 30, 2022, compared with the same period in 2021, to satisfy requirements of our stock-based compensation plans.

•A $47.3 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2022, compared with the same period in 2021. In January 2022, our Board of Directors increased our quarterly dividend by $0.05 per share (7.4%) effective with the March 2022 dividend payment.

Significant Financing Activities

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

Cash Requirements

We require funds to support and grow our businesses. Our significant cash requirements primarily consist of capital and investment expenditures, payments to retire and pay interest on long-term debt, the payment of common stock dividends to our shareholders, and the funding of our ongoing operations. See the discussion below and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements in our 2021 Annual Report on Form 10-K for additional information regarding our significant cash requirements.


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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, supply chain disruptions, inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 22, Commitments and Contingencies.


(in millions)	2022 (1)		2023		2024
Wisconsin	$	1,910.3	$	2,530.7	$	2,432.8
Illinois	512.7		557.1		659.5
Other states	100.9		111.8		115.0
Non-utility energy infrastructure	481.5		487.0		683.8
Corporate and other	25.3		28.1		17.0
Total	$	3,030.7	$	3,714.7	$	3,908.1

(1)This includes actual capital expenditures incurred through September 30, 2022, as well as estimated capital expenditures for the remainder of the year.

Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability. These upgrades include addressing our aging infrastructure and system hardening and 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.

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 100 MW of utility-scale solar within our Wisconsin segment. 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 $151 million. Commercial operation of Badger Hollow II is targeted for the first half of 2023.

•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, 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 fully constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $390 million, with construction of the solar portion expected to be completed in 2023.

•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 Darien, 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 fully 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 of the solar portion expected to be completed in 2024.

•WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, 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. WPS's share of the cost of this project is estimated to be approximately $160 million, with construction expected to be completed in early 2023.

•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 fully constructed, WE and WPS will collectively own 270 MW of solar


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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 of the solar portion expected to be completed in 2025.

•WE and WPS received PSCW 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 RICE units. We estimate the cost of this project to be approximately $170 million, with construction expected to be completed in 2023.

•In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual-fueled (natural gas and low sulfur fuel oil) combined-cycle electrical generation facility in Whitewater, Wisconsin. In December 2021, WE and WPS filed an application with the PSCW for approval to acquire Whitewater. If approved, the cost of this facility will be approximately $75 million, with the transaction expected to close in early 2023.

•In January 2022, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire a portion of West Riverside's nameplate capacity. WPS is also requesting approval to assign the option to purchase part of West Riverside to WE. If approved, WPS or WE would acquire 100 MW of capacity, in the first of two potential option exercises. West Riverside is a combined-cycle natural gas plant recently completed by an unaffiliated utility in Rock County, Wisconsin. If approved, our share of the cost of this ownership interest is approximately $91 million, with the transaction expected to close in the second quarter of 2023. In addition, WPS could exercise a second option to acquire an additional 100 MW of capacity. If approved, our share of the cost of this ownership interest is approximately $90 million, with the transaction expected to close in 2024.

In March 2022, the DOC opened an investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC investigation and CBP actions related to solar panels, respectively. The expected in-service dates identified above already reflect some of these impacts.

WE and WG have received PSCW approval to each construct its own LNG facility. Each facility would provide approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility. Commercial operation of the WE and WG LNG facilities is targeted for the end of 2023 and 2024, respectively.

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 2024 is between $280 million and $300 million.

The non-utility energy infrastructure line item in the table above includes WECI's investment in Thunderhead and its planned investments in Sapphire Sky and Maple Flats. See Note 2, Acquisitions, for more information on these projects.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $181 million from 2022 through 2024. We do not expect to make any contributions to ATC Holdco during that period.

Long-Term Debt

See Note 10, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2022.

Common Stock Dividends

Our current quarterly dividend rate is $0.7275 per share, which equates to an annual dividend of $2.91 per share. For information related to our most recent common stock dividend declared, see Note 8, Common Equity.


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Other Significant Cash Requirements

See Note 22, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the nine months ended September 30, 2022.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 9, Short-Term Debt and Lines of Credit, Note 16, Guarantees, and Note 21, Variable Interest Entities.

Sources of Cash

Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our businesses and implement our corporate strategy through internal generation of cash from operations and access to the capital markets, which allows us to obtain external short-term borrowings, including commercial paper and term loans, and intermediate or long-term debt securities. Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events.

WEC Energy Group, WE, WPS, WG, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations.

The amount, type, and timing of any financings for the remainder of 2022, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators. For more information on our utilities approved capital structures, see Item 1. Business – E. Regulation in our 2021 Annual Report on Form 10-K.

The issuance of securities by our utility companies is subject to the approval of the applicable state commissions or FERC. Additionally, with respect to the public offering of securities, WEC Energy Group, WE, and WPS file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

At September 30, 2022, our current liabilities exceeded our current assets by $598.7 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity of $1,841.8 million under existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

See Note 9, Short-Term Debt and Lines of Credit, for more information about our credit facilities and commercial paper.

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts had investments consisting of fixed income and equity securities that are subject to the volatility of the stock market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis


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of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2021 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of September 30, 2022, 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	$	11,355.5		$	11,605.5
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	15,077.9			14,827.9
Short-term debt	1,259.5			1,259.5
Total capitalization	$	27,723.3		$	27,723.3

Total debt	$	16,337.4		$	16,087.4

Ratio of debt to total capitalization	58.9		%	58.0		%

Included in long-term debt on our balance sheet as of September 30, 2022, 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.

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At September 30, 2022, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, Note 14, Long-Term Debt, and Note 11, Common Equity, in our 2021 Annual Report on Form 10-K, for more information regarding our debt covenants.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of September 30, 2022. From time to time, we may enter into commodity contracts 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. If WE had a sub-investment grade credit rating at September 30, 2022, it could have been required to post $100 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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


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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 2021 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.

COVID-19 Pandemic

We have taken steps to mitigate the impact of the global COVID-19 pandemic. However, the extent to which the COVID-19 pandemic could continue to impact our results of operations and liquidity is largely dependent upon the ability of our customers to resume or maintain normal operations. Adverse impacts to us and our subsidiaries from a prolonged COVID-19 pandemic environment could include a decrease in revenues, increased bad debt expense, increases in past due accounts receivable balances, and access to the capital markets at unfavorable terms or rates.

We will continue to monitor COVID-19 pandemic-related developments affecting our workforce, customers, and suppliers and will implement additional actions that we determine to be necessary in order to mitigate any additional impacts. We cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, its duration through new variants, the rate and the effectiveness of both vaccinations and treatments, future regulatory and governmental actions, and the ability to maintain normal business activity.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB Accounting Standard 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. As of September 30, 2022, our regulatory assets were $3,251.2 million, and our regulatory liabilities were $3,994.9 million.

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 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of September 30, 2022, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

See Note 24, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

In May 2022, two petitions were filed with the PSCW requesting a declaratory ruling that the owner of a third-party financed DER is not a “public utility” as defined under Wisconsin law and, therefore, is not subject to the PSCW’s jurisdiction under any statute or rule regulating public utilities. In July 2022, the PSCW granted the petitions, finding that the specific facts and circumstances merited the opening of a docket to consider whether to grant all or part of the requested declaratory ruling. The PSCW has indicated that it expects to make a decision no later than December 1, 2022.

The parties that filed the petitions provide financing to their customers for installation of DERs (including solar panels and energy storage) on the customer’s property. A DER is connected to the host customer’s utility meter and is used for the customer’s energy needs. It may also be connected to the grid for distribution. At this time we are unable to predict the outcome of these proceedings;


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however, management is currently assessing the potential for any impact to our financial condition or results of operations from a finding in favor of the petitioners.

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 September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card. Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism. In December 2021, the ICC approved the use of a TPTFA rider for PGL. The TPTFA rider allows PGL to recover the costs incurred for these third-party transaction fees. NSG recovers costs related to these third-party transaction fees through its base rates, effective September 15, 2021.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities will also no longer be allowed to charge late payment fees to low-income residential customers. We are currently evaluating the impact this legislation may have on our future results of operations.

Uyghur Forced Labor Prevention Act

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China (Xinjiang), such as polysilicon, included in the manufacturing of solar panels. In June 2022, the WRO was superseded by the implementation of the UFLPA, which was signed into law by President Biden in December 2021. The UFLPA establishes a rebuttable presumption that any imports wholly or partially manufactured in Xinjiang are prohibited from entering the United States. While our suppliers were able to provide the CBP sufficient documentation to meet WRO compliance requirements, and we expect the same will be true for UFLPA purposes, we cannot currently predict what, if any, impact the UFLPA will have on the overall supply of solar panels into the United States and the related timing and cost of solar projects included in our capital plan.

United States Department of Commerce Complaints

In August 2021, a group of anonymous domestic solar manufacturers filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In November 2021, the DOC rejected this petition. In denying the petition, the DOC cited the anonymous group’s refusal of the DOC’s request to provide more detail and identify its members due to concerns about retribution from the dominant Chinese solar industry.

In February 2022, a California based company filed a petition (AD/CVD) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. While the petition is similar to the one rejected by the DOC in November 2021, there are notable differences. The group added Cambodia to the petition and is requesting that the DOC conduct a country-wide inquiry into each of the four countries. In March 2022, the DOC decided to act on the February petition and investigate the claim. A DOC decision is expected by January 2023. If the DOC determines that the petition has merit, it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs are expected to further disrupt the supply of solar modules to the United States, and could impact the cost and timing of our solar projects.

In June 2022, the Biden Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam. The moratorium comes as a direct response to concerns raised about the adverse impact from the ongoing DOC complaint on the U.S. solar industry. As the DOC will continue its investigation discussed above, companies may still be subject to tariffs after the moratorium ends; however, U.S. companies will reportedly be exempt from any retroactive tariffs that previously could have applied. The Biden Administration also announced that it plans to invoke the Defense Production Act to accelerate the production of solar panels in the U.S. The Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.


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Infrastructure Investment and Jobs Act

In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. We expect funding from this Act will support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid. Funding in the Act should also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future. We believe the Infrastructure Investment and Jobs Act will accelerate investment in projects that will help us meet our net zero emission goals to the benefit of our customers, the communities we serve, and our company.

Inflation Reduction Act

In August 2022, President Biden signed into law the IRA, which provides for $258 billion in energy-related provisions over a 10-year period. The provisions of the IRA are intended to, among other things, lower gasoline and electricity prices, incentivize domestic clean energy investment, manufacturing, and production, and promote reductions in carbon emissions. We believe that we and our customers can benefit from the IRA’s provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us. Overall, we believe the IRA will help reduce our cost of investing in projects that will support our commitment to reduce emissions and provide customers affordable, reliable, and clean energy over the longer term.

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, we estimate that this proposal, if adopted, would reduce our future after-tax equity earnings from ATC by approximately $7 million annually on a prospective basis. The transmission costs WE, WPS, and UMERC are required to pay ATC after the effective date would also be reduced by this proposal.

American Transmission Company Allowed Return on Equity Complaints

The ROE allowed by the FERC helps determine how much transmission owners, such as ATC, earn on their transmission assets as well as how much consumers pay for those assets. When two complaints were filed arguing the base ROE for MISO transmission owners, including ATC, was too high, the FERC started analyzing the base ROE for these transmission owners.

The base ROEs listed in the two ROE complaint sections below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization. See the Return on Equity Incentive for Membership in a Transmission Organization section above for more information on this incentive.

First Return on Equity Complaint

In November 2013, a group of MISO industrial customers filed a complaint with the FERC asking that the FERC order a reduction to the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. Due to this complaint, the FERC and the D.C. Circuit Court of Appeals issued the following orders and opinion. The refunds resulting from these orders and opinion are also described below.


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•Orders Issued by the FERC

◦September 2016 Order – On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by the first complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.

◦November 2019 Order – On November 21, 2019, the FERC issued another 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. In 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 also rejected the use of the risk premium model as part of its base ROE methodology in this order. The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the first complaint. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

◦May 2020 Order – On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order. In this May 2020 Order, the FERC made additional revisions to its base ROE methodology, including reinstating the use of the risk premium model. The additional revisions made by the FERC increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02% for the period covered by the first complaint. Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.

◦November 2020 Order – In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.

◦Refunds – Due to the base ROE changes resulting from these FERC orders, ATC was 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. In January 2022, ATC completed providing WE, WPS, and UMERC with the net refunds related to the transmission costs they paid during the period covered by the first complaint. The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

•Opinion Issued by the D.C. Circuit Court of Appeals

◦August 2022 Decision – Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022 addressing these petitions. In its August 2022 Decision, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings. As of September 30, 2022, the FERC had not provided a ruling in response to the August 2022 Decision issued by the D.C. Circuit Court of Appeals.

◦Refunds – Since the FERC is required to conduct more proceedings, additional refunds could still be required for the 15-month period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 until the date of any future order. Therefore, ATC recorded a liability on its financials for these potential refunds, which reduced our equity earnings from ATC by $18.6 million during the third quarter of 2022. The liability recorded by ATC is based on a 9.88% base ROE for the first complaint period. If it is ultimately determined a refund is required for the first 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, WPS, and UMERC would be entitled to receive a portion of the refund from ATC for the benefit of their customers.

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. To resolve this complaint, the following orders and opinion were issued by the FERC and the D.C. Circuit Court of Appeals. The orders and opinion discussed below are the same orders and opinion described above in the first complaint section.


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•Orders Issued by the FERC

◦November 2019 Order – Similar to the first complaint, the November 2019 Order stated the newly calculated base ROE of 9.88% was also 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 refunds were not allowed for this period.

◦May 2020 Order – In its May 2020 Order, the FERC stated the newly calculated base ROE of 10.02% was also 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 to determine refunds were not allowed for this period. In addition, the FERC denied in its May 2020 Order the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.

•Opinion Issued by the D.C. Circuit Court of Appeals

◦August 2022 Decision - The August 2022 Decision issued by the D.C. Circuit Court of Appeals affirmed both the FERC’s dismissal of the second complaint and the FERC’s finding that no refunds are allowed for the second complaint period. Therefore, during the third quarter of 2022, we reduced the liability previously recorded for the potential refunds related to the second complaint period by $39.1 million, which increased our equity earnings from ATC.

Environmental Matters

See Note 22, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

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 inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing conflict between Russia and Ukraine will have on the global economy, supply chains, and fuel prices. 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 2021 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the two risk factors below that are disclosed in Part I of our 2021 Annual Report on Form 10-K.

•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report.


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Critical Accounting Policies and Estimates

We have reviewed our critical accounting policies and considered whether any new critical accounting estimates or other significant changes to our accounting policies require additional disclosures. We have found that the disclosures made in our 2021 Annual Report on Form 10-K are still current and that there have been no significant changes, except as follows:

Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2022. No impairments were recorded as a result of these tests. 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 calculated fair value of a reporting unit. Since all of our reporting units are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.

Key assumptions used in the income approach include ROEs, the long-term growth rates used to determine terminal values at the end of the discrete forecast period, and the discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.

For the market approach, we used a higher weighting for the guideline public company method than the guideline merged and acquired company method due to a low number of mergers and acquisitions in recent years. 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 that carried a goodwill balance at July 1, 2022, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

See Note 18, Goodwill and Intangibles, for more information.

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 2021 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 – COVID-19 Pandemic and Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 14, Fair Value Measurements, Note 15, Derivative Instruments, and Note 16, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i)


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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 2022 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 2021 Annual Report on Form 10-K. See Note 22, Commitments and Contingencies, and Note 24, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed in Note 22, Commitments and Contingencies, Note 24, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material impact on our financial statements.

Employee Retirement Savings Plan Matter

In May 2022, a putative class action, Munt, et al. v. WEC Energy Group, Inc., et al., was filed in the United States District Court for the Eastern District of Wisconsin - Milwaukee Division. The plaintiffs allege that WEC Energy Group, members of its Board of Directors, and others breached their fiduciary duties with respect to the operation and oversight of the Employee Retirement Saving Plan (the “Plan”) in violation of the Employee Retirement Income Security Act of 1974, as amended. The class is alleged to be participants in the Plan from May 10, 2016 through the date of judgment. The complaint seeks injunctive relief, damages, interest, costs, and attorneys' fees. The Company intends to vigorously defend against the allegations made in this lawsuit. Management is currently not in a position to assess the probability of an adverse outcome or reasonably estimate the amount of any potential loss at this time with respect to this lawsuit.

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. 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.

PGL and the AG agreed to the terms of a final consent order, which was entered by the court in June 2022. In accordance with this order, PGL paid an aggregate of $575,000, including a civil penalty of $175,000. The consent order also requires PGL to complete the GMZ and to continue to provide methane detection devices, bottled water and gas/water separators to affected homeowners, as defined in the final consent order, until certain conditions are satisfied.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2021 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, 2022:


Issuer Purchases of Equity Securities
2022	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	711	$	101.67	—	$	—
August 1 – August 31	—	—		—	—
September 1 – September 30	—	—		—	—
Total (1)	711	$	101.67	—

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


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ITEM 6. EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to WEC Energy Group, Inc. (File No. 001-09057). An asterisk () indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified below by two asterisks (*) following the description of the exhibit.

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

	4.1*	Securities Resolution No. 20 of WE, effective as of September 14, 2022, under the Indenture for Debt Securities, dated as of December 1, 1995, between WE and U.S. Bank Trust Company, National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to WE's Form 8-K filed September 22, 2022.)

	4.2*	Securities Resolution No. 13 of WEC Energy Group, Inc., effective as of September 22, 2022, under the Indenture for Debt Securities, dated as of March 15, 1999, between WEC Energy Group, Inc. and The Bank of New York Mellon Trust Company, N.A. (as successor to The First National Bank of Chicago), as Trustee. (Exhibit 4.1 to WEC Energy Group, Inc.'s Form 8-K filed September 27, 2022.)
















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 3, 2022	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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