wec-20230930

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, 2023


☐			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, 2023):

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

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2023

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

Jointly Owned Utility Facilities

Note 9

Common Equity

Note 10

Short-Term Debt and Lines of Credit

Materials, Supplies, and Inventories

Note 14

Income Taxes

Note 15

Fair Value Measurements

Note 16

Derivative Instruments

Goodwill and Intangibles

Note 20

Investment in Transmission Affiliates

Note 21

Segment Information

Note 22

Variable Interest Entities

Note 23

Commitments and Contingencies

Note 24

Supplemental Cash Flow Information

Note 25

Regulatory Environment

Note 26

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


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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



Bluewater						Bluewater Natural Gas Holding, 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
Samson I						Samson I Solar Energy Center LLC
Sapphire Sky						Sapphire Sky Wind Energy LLC
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

WECI Wind Holding II						WEC Infrastructure Wind Holding II 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
Army Corps						United States Army Corps of Engineers
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
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
ASC						Accounting Standards Codification
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

BATW						Bottom Ash Transport Water
BTA						Best Technology Available
CAA						Clean Air Act


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CASAC						Clean Air Scientific Advisory Committee
CCR						Coal Combustion Residuals
CO2						Carbon Dioxide
CWA						Clean Water Act
ELG						Steam Electric Effluent Limitation Guidelines
FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
LDC						Local Distribution Company
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
NOV						Notice of Violation
NOx						Nitrogen Oxide
PM						Particulate Matter
WOTUS						Waters of the United States
WPDES						Wisconsin Pollutant Discharge Elimination System
ZLD						Zero Liquid Discharge

Measurements
Bcf						Billion Cubic Feet
Dth						Dekatherm
lb/MMBtu						Pound Per Million British Thermal Unit
MW						Megawatt
MWh						Megawatt-hours
µg/m3						Micrograms Per Cubic Meter

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

AMI						Advanced Metering Infrastructure
Badger Hollow II						Badger Hollow Solar Park II
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
Darien						Darien Solar Park
DER						Distributed Energy Resource
DRER						Dedicated Renewable Energy Resource
EPRI						Electric Power Research Institute
ERGS						Elm Road Generating Station
ESG Progress Plan						WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth for 2024-2028
ETB						Environmental Trust Bond
EV						Electric Vehicle
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
IRA						Inflation Reduction Act
ITC						Investment Tax Credit
Koshkonong						Koshkonong Solar Park
LIBOR						London Interbank Offered Rate
LNG						Liquefied Natural Gas
Maple Flats						Maple Flats Solar Energy Center LLC
MISO						Midcontinent Independent System Operator, Inc.
MRP						Main Replacement Program
OCPP						Oak Creek Power Plant
OC 7						Oak Creek Power Plant Unit 7
OC 8						Oak Creek Power Plant Unit 8


PPA						Power Purchase Agreement

PTC						Production Tax Credit
PWGS						Port Washington Generation Station
QIP						Qualifying Infrastructure Plant


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Red Barn						Red Barn Wind Park
RICE						Reciprocating Internal Combustion Engine
RNG						Renewable Natural Gas
ROE						Return on Equity
S&P						Standard & Poor's
SIP						State Implementation Plan
SMP						Safety Modernization Program
SOFR						Secured Overnight Financing Rate
SPP						Southwest Power Pool, Inc.
Supreme Court						United States Supreme Court
Tax Legislation						Tax Cuts and Jobs Act of 2017
TCR						Transmission Congestion Right
UEA						Uncollectible Expense Adjustment
UFLPA						Uyghur Forced Labor Prevention Act
West Riverside						West Riverside Energy Center
Whitewater						Whitewater Cogeneration Facility
WRO						Withhold Release Order
WUA						Wisconsin Utilities Association


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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 2022 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, 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, as well as changes in the interpretation and/or enforcement of any laws or regulations by regulatory agencies;

•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 impact of changing expectations and demands of our customers, regulators, investors, and other stakeholders, including heightened emphasis on environmental, social, and governance concerns;

•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;


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•The impact of public health crises, including epidemics and pandemics, on our business functions, financial condition, liquidity, and results of operations;

•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 ongoing global conflicts, including 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;

•Any impacts associated with switching from LIBOR to SOFR as the reference rate for our variable rate debt;

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

•The direct or indirect effect on our business resulting from terrorist or other physical 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, changes in the financial performance and/or creditworthiness of counterparties to the off-take agreements, the ability to replace expiring PPAs under acceptable terms, the availability of reliable interconnection and electricity grids, and exposure to the rules and procedures of the power markets in which these facilities are located;


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•The risk associated with the values of goodwill and other long-lived assets, including intangible assets, and equity method investments, and their possible impairment;

•Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;

•The timing and outcome of any audits, disputes, and other proceedings related to taxes;

•The 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)	2023		2022		2023		2022
Operating revenues	$	1,957.4	$	2,003.0	$	6,675.5	$	7,039.0

Operating expenses
Cost of sales	587.4		805.1		2,430.1		3,123.5
Other operation and maintenance	516.6		454.3		1,546.6		1,357.7
Depreciation and amortization	320.3		280.3		939.7		838.0
Property and revenue taxes	61.1		59.1		192.5		176.0
Total operating expenses	1,485.4		1,598.8		5,108.9		5,495.2

Operating income	472.0		404.2		1,566.6		1,543.8

Equity in earnings of transmission affiliates	44.7		63.7		132.1		148.4
Other income, net	41.8		34.7		130.9		94.1
Interest expense	182.5		127.5		533.4		364.9
Other expense	(96.0)		(29.1)		(270.4)		(122.4)

Income before income taxes	376.0		375.1		1,296.2		1,421.4
Income tax expense	60.4		73.4		183.0		263.9
Net income	315.6		301.7		1,113.2		1,157.5

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Net loss (income) attributed to noncontrolling interests	0.7		0.6		0.9		(1.2)
Net income attributed to common shareholders	$	316.0	$	302.0	$	1,113.2	$	1,155.4

Earnings per share
Basic	$	1.00	$	0.96	$	3.53	$	3.66
Diluted	$	1.00	$	0.96	$	3.52	$	3.65

Weighted average common shares outstanding
Basic	315.4		315.4		315.4		315.4
Diluted	315.8		316.2		315.9		316.2

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 COMPREHENSIVE INCOME (Unaudited)	Three Months Ended				Nine Months Ended
	September 30				September 30
(in millions)	2023		2022		2023		2022
Net income	$	315.6	$	301.7	$	1,113.2	$	1,157.5

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

Reclassification of realized derivative gains to net income, net of tax	(0.1)		—		(0.2)		(0.1)

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

Other comprehensive loss, net of tax	(0.1)		—		(0.2)		—

Comprehensive income	315.5		301.7		1,113.0		1,157.5

Preferred stock dividends of subsidiary	0.3		0.3		0.9		0.9
Comprehensive loss (income) attributed to noncontrolling interests	0.7		0.6		0.9		(1.2)
Comprehensive income attributed to common shareholders	$	315.9	$	302.0	$	1,113.0	$	1,155.4

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	September 30, 2023		December 31, 2022
Assets
Current assets
Cash and cash equivalents	$	45.9	$	28.9
Accounts receivable and unbilled revenues, net of reserves of $176.8 and $199.3, respectively	1,243.2		1,818.4
Materials, supplies, and inventories	749.9		807.1
Prepaid taxes	157.8		201.8
Other prepayments	40.6		69.8
Collateral on deposit	118.4		122.4
Other	87.8		139.3
Current assets	2,443.6		3,187.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,914.6 and $10,383.8, respectively	31,467.5		29,113.8
Regulatory assets (September 30, 2023 and December 31, 2022 include $87.5 and $92.4, respectively, related to WEPCo Environmental Trust)	3,197.1		3,264.6
Equity investment in transmission affiliates	1,983.8		1,909.2
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	918.7		916.7
Other	378.2		427.3
Long-term assets	40,998.1		38,684.4
Total assets	$	43,441.7	$	41,872.1

Liabilities and Equity
Current liabilities
Short-term debt	$	1,549.3	$	1,647.1
Current portion of long-term debt (September 30, 2023 and December 31, 2022 include $9.0 and $8.9, respectively, related to WEPCo Environmental Trust)	712.9		881.2
Accounts payable	867.7		1,198.1
Other	943.8		884.6
Current liabilities	4,073.7		4,611.0

Long-term liabilities
Long-term debt (September 30, 2023 and December 31, 2022 include $89.8 and $94.1, respectively, related to WEPCo Environmental Trust)	15,956.5		14,766.2
Deferred income taxes	4,832.2		4,625.6
Deferred revenue, net	360.4		370.7
Regulatory liabilities	3,720.0		3,735.5
Intangible liabilities	608.2		335.4
Asset retirement obligations	505.5		479.3
Environmental remediation liabilities	456.6		499.6
Other	828.3		832.2
Long-term liabilities	27,267.7		25,644.5

Commitments and contingencies (Note 23)

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	4,116.4		4,115.2
Retained earnings	7,640.4		7,265.3
Accumulated other comprehensive loss	(7.0)		(6.8)
Common shareholders' equity	11,753.0		11,376.9

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	316.9		209.3
Total liabilities and equity	$	43,441.7	$	41,872.1

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(in millions)	2023		2022
Operating activities
Net income	$	1,113.2	$	1,157.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	939.7		838.0
Deferred income taxes and ITCs, net	155.9		187.8
Contributions and payments related to pension and OPEB plans	(13.0)		(11.6)
Equity income in transmission affiliates, net of distributions	(23.1)		(47.1)
Change in –
Accounts receivable and unbilled revenues, net	600.7		150.9
Materials, supplies, and inventories	67.2		(288.8)
Prepaid taxes	43.6		57.8
Other current assets	64.7		45.4
Accounts payable	(350.6)		82.2
Other current liabilities	52.3		68.5
Other, net	(112.2)		(181.1)
Net cash provided by operating activities	2,538.4		2,059.5

Investing activities
Capital expenditures	(1,729.5)		(1,700.7)
Acquisition of Whitewater	(76.0)		—
Acquisition of Sapphire Sky, net of cash acquired of $0.3	(442.6)		—
Acquisition of Samson I, net of cash acquired of $5.2	(249.4)		—
Acquisition of Red Barn	(143.8)		—
Acquisition of West Riverside	(95.3)		—
Acquisition of Thunderhead, net of cash acquired of $0.5	—		(362.9)
Capital contributions to transmission affiliates	(51.5)		(39.4)
Proceeds from the sale of assets	30.4		69.0
Proceeds from the sale of investments held in rabbi trust	10.4		15.4
Payments for ATC's construction costs that will be reimbursed	(19.5)		(20.6)
Insurance proceeds received for property damage	0.5		41.6
Other, net	(5.4)		11.7
Net cash used in investing activities	(2,771.7)		(1,985.9)

Financing activities
Exercise of stock options	3.0		33.1
Purchase of common stock	(10.7)		(68.3)
Dividends paid on common stock	(738.1)		(688.5)
Issuance of long-term debt	2,050.0		1,400.0
Retirement of long-term debt	(996.0)		(64.9)
Change in commercial paper	(98.2)		(640.2)
Payments for debt issuance costs	(13.0)		(9.1)
Other, net	(4.5)		(7.2)
Net cash provided by (used in) financing activities	192.5		(45.1)

Net change in cash, cash equivalents, and restricted cash	(40.8)		28.5
Cash, cash equivalents, and restricted cash at beginning of period	182.2		87.5
Cash, cash equivalents, and restricted cash at end of period	$	141.4	$	116.0

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, 2022	$	3.2	$	4,115.2	$	7,265.3	$	(6.8)	$	11,376.9	$	30.4	$	209.3	$	11,616.6
Net income attributed to common shareholders	—		—		507.5		—		507.5		—		—		507.5
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.2)		(0.2)
Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Common stock dividends of $0.7800 per share	—		—		(246.1)		—		(246.1)		—		—		(246.1)
Exercise of stock options	—		0.9		—		—		0.9		—		—		0.9
Purchase of common stock	—		(6.9)		—		—		(6.9)		—		—		(6.9)
Acquisition of noncontrolling interests	—		—		—		—		—		—		112.9		112.9
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.3)		(1.3)
Stock-based compensation and other	—		4.4		—		—		4.4		—		—		4.4
Balance at March 31, 2023	$	3.2	$	4,113.6	$	7,526.7	$	(6.9)	$	11,636.6	$	30.4	$	320.7	$	11,987.7
Net income attributed to common shareholders	—		—		289.7		—		289.7		—		—		289.7
Common stock dividends of $0.7800 per share	—		—		(246.0)		—		(246.0)		—		—		(246.0)
Exercise of stock options	—		1.4		—		—		1.4		—		—		1.4
Purchase of common stock	—		(2.6)		—		—		(2.6)		—		—		(2.6)
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.0)		(1.0)
Stock-based compensation and other	—		2.3		—		—		2.3		—		(0.1)		2.2
Balance at June 30, 2023	$	3.2	$	4,114.7	$	7,570.4	$	(6.9)	$	11,681.4	$	30.4	$	319.6	$	12,031.4
Net income attributed to common shareholders	—		—		316.0		—		316.0		—		—		316.0
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.7)		(0.7)
Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Common stock dividends of $0.7800 per share	—		—		(246.0)		—		(246.0)		—		—		(246.0)
Exercise of stock options	—		0.7		—		—		0.7		—		—		0.7
Purchase of common stock	—		(1.2)		—		—		(1.2)		—		—		(1.2)
Distributions to noncontrolling interests	—		—		—		—		—		—		(2.0)		(2.0)
Stock-based compensation and other	—		2.2		—		—		2.2		—		—		2.2
Balance at September 30, 2023	$	3.2	$	4,116.4	$	7,640.4	$	(7.0)	$	11,753.0	$	30.4	$	316.9	$	12,100.3


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	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

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, 2023

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.7 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable 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 held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

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 20, 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, 2022. 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, 2023, are not necessarily indicative of expected results for 2023 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 of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 19, Goodwill and Intangibles, for more information.

Acquisitions of Electric Generation Facilities in Wisconsin

In June 2023, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to acquisition, WPS received approval to transfer its ownership interest rights to WE. WE's investment was $95.3 million. In addition, WPS filed an application with the PSCW in September 2023 to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity. As it did with the first option, WPS is also seeking approval to assign its ownership interest pursuant to this second option to WE. If these approvals are obtained, WE's incremental share of this investment is expected to be approximately $100 million, with the transaction expected to close in 2024.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $143.8 million. Red Barn qualifies for PTCs.


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In January 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electric generation facility in Whitewater, Wisconsin, for $76.0 million.

Acquisition of a Solar Generation Facility in Texas

In February 2023, WECI completed the acquisition of an 80% ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar County, Texas, for $249.4 million, which includes transaction costs and is net of cash acquired. The allocation of purchase price to the assets acquired and liabilities assumed was primarily to property, plant, and equipment and an intangible liability related to the PPA. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment.

Acquisition of Electric Generation Facility in Illinois

In February 2023, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of $442.6 million, which includes transaction costs and is net of cash acquired. The allocation of purchase price to the assets acquired and liabilities assumed was primarily to property, plant, and equipment and an intangible liability related to the PPA. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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 facility for a period of 15 years. The transaction is subject to FERC approval and commercial operation is expected to begin during 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.

NOTE 3—DISPOSITIONS

Sale of Certain Real Estate by Wisconsin Electric Power Company

In June 2023, we sold approximately 192 acres of real estate at WE's former Pleasant Prairie power plant site that was no longer being utilized in its operations, for $23.0 million, which is net of closing costs. As a result of the sale, a pre-tax gain in the amount of $22.2 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.

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, which is net of closing costs. 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 2022 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 has 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, 2023
Electric	$	1,457.8	$	—	$	—	$	1,457.8	$	—	$	—	$	—		$	1,457.8
Natural gas	159.5		234.8		42.5		436.8		12.9		—		(12.3)			437.4
Total regulated revenues	1,617.3		234.8		42.5		1,894.6		12.9		—		(12.3)			1,895.2
Other non-utility revenues	—		—		4.9		4.9		45.6		—		(1.7)			48.8
Total revenues from contracts with customers	1,617.3		234.8		47.4		1,899.5		58.5		—		(14.0)			1,944.0
Other operating revenues	4.7		8.5		0.2		13.4		101.3		—		(101.3)		(1)	13.4
Total operating revenues	$	1,622.0	$	243.3	$	47.6	$	1,912.9	$	159.8	$	—	$	(115.3)		$	1,957.4


(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
Nine Months Ended September 30, 2023
Electric	$	3,840.1	$	—	$	—	$	3,840.1	$	—	$	—	$	—		$	3,840.1
Natural gas	1,183.8		1,072.5		364.4		2,620.7		48.3		—		(47.0)			2,622.0
Total regulated revenues	5,023.9		1,072.5		364.4		6,460.8		48.3		—		(47.0)			6,462.1
Other non-utility revenues	—		—		14.8		14.8		142.4		—		(7.1)			150.1
Total revenues from contracts with customers	5,023.9		1,072.5		379.2		6,475.6		190.7		—		(54.1)			6,612.2
Other operating revenues	18.9		44.0		0.3		63.2		304.3		0.1		(304.3)		(1)	63.3
Total operating revenues	$	5,042.8	$	1,116.5	$	379.5	$	6,538.8	$	495.0	$	0.1	$	(358.4)		$	6,675.5


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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, 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

(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 by customer class:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2023		2022		2023		2022
Residential	$	584.9	$	529.7	$	1,530.5	$	1,442.5
Small commercial and industrial	462.2		424.8		1,257.3		1,173.3
Large commercial and industrial	289.9		316.8		759.6		814.1
Other	7.2		7.1		22.4		22.1
Total retail revenues	1,344.2		1,278.4		3,569.8		3,452.0
Wholesale	31.9		39.7		96.5		122.9
Resale	75.3		102.7		147.8		220.2
Steam	2.6		3.0		18.2		19.8
Other utility revenues	3.8		13.1		7.8		30.6
Total electric utility operating revenues	$	1,457.8	$	1,436.9	$	3,840.1	$	3,845.5

Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues by customer class:


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2023
Residential	$	81.7	$	148.3	$	27.5	$	257.5
Commercial and industrial	34.0		30.8		12.1		76.9
Total retail revenues	115.7		179.1		39.6		334.4
Transportation	18.2		41.9		6.3		66.4
Other utility revenues (1)	25.6		13.8		(3.4)		36.0
Total natural gas utility operating revenues	$	159.5	$	234.8	$	42.5	$	436.8


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(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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2023
Residential	$	756.6	$	697.2	$	245.6	$	1,699.4
Commercial and industrial	379.8		191.1		129.8		700.7
Total retail revenues	1,136.4		888.3		375.4		2,400.1
Transportation	67.5		167.3		23.4		258.2
Other utility revenues (1)	(20.1)		16.9		(34.4)		(37.6)
Total natural gas utility operating revenues	$	1,183.8	$	1,072.5	$	364.4	$	2,620.7


(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 (1)	(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

(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities, which fluctuate by segment based on actual natural gas costs incurred at our utilities, compared with the recovery of natural gas costs that were anticipated in rates.

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.

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)	2023		2022		2023		2022
Wind generation revenues	$	38.2	$	20.0	$	117.8	$	77.5
We Power revenues (1)	5.7		5.8		17.5		17.5
Appliance service revenues	4.9		4.8		14.8		13.9


Total other non-utility operating revenues	$	48.8	$	30.6	$	150.1	$	108.9

(1)As part of the construction of the We Power electric utility generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction.


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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)	2023		2022		2023		2022
Late payment charges	$	12.4	$	13.6	$	45.8	$	43.5
Alternative revenues (1)	—		(2.4)		13.9		(19.7)
Other	1.0		0.7		3.6		3.3
Total other operating revenues	$	13.4	$	11.9	$	63.3	$	27.1

(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, and conservation improvement rider true-ups.

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


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We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2023 and December 31, 2022, 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, 2023
Accounts receivable and unbilled revenues	$	956.7		$	355.8		$	60.6		$	1,373.1		$	40.2		$	6.7		$	1,420.0
Allowance for credit losses	72.0			100.0			4.8			176.8			—			—			176.8
Accounts receivable and unbilled revenues, net (1)	$	884.7		$	255.8		$	55.8		$	1,196.3		$	40.2		$	6.7		$	1,243.2

Total accounts receivable, net – past due greater than 90 days (1)	$	54.0		$	69.7		$	4.2		$	127.9		$	—		$	—		$	127.9
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	94.0		%	100.0		%	—		%	94.2		%	—		%	—		%	94.2		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2022
Accounts receivable and unbilled revenues	$	1,199.4		$	624.2		$	164.4		$	1,988.0		$	25.4		$	4.3		$	2,017.7
Allowance for credit losses	82.0			111.0			6.3			199.3			—			—			199.3
Accounts receivable and unbilled revenues, net (1)	$	1,117.4		$	513.2		$	158.1		$	1,788.7		$	25.4		$	4.3		$	1,818.4

Total accounts receivable, net – past due greater than 90 days (1)	$	51.9		$	52.9		$	1.9		$	106.7		$	—		$	—		$	106.7
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.0		%	100.0		%	—		%	96.8		%	—		%	—		%	96.8		%

(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, 2023, $634.7 million, or 51.1%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

A roll-forward of the allowance for credit losses by reportable segment is included below:


Three Months Ended September 30, 2023 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at July 1, 2023	$	76.4	$	97.0	$	5.3	$	178.7
Provision for credit losses	10.2		4.0		0.6		14.8
Provision for credit losses deferred for future recovery or refund	9.8		7.1		—		16.9
Write-offs charged against the allowance	(31.8)		(14.4)		(1.5)		(47.7)
Recoveries of amounts previously written off	7.4		6.3		0.4		14.1
Balance at September 30, 2023	$	72.0	$	100.0	$	4.8	$	176.8


Nine Months Ended September 30, 2023 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2023	$	82.0	$	111.0	$	6.3	$	199.3
Provision for credit losses	28.1		17.3		1.5		46.9
Provision for credit losses deferred for future recovery or refund	26.3		13.8		—		40.1
Write-offs charged against the allowance	(89.8)		(58.7)		(4.2)		(152.7)
Recoveries of amounts previously written off	25.4		16.6		1.2		43.2
Balance at September 30, 2023	$	72.0	$	100.0	$	4.8	$	176.8


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On a consolidated basis, there was a $22.5 million decrease in the allowance for credit losses at September 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the end of the winter moratorium. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. In addition, lower energy costs driven by lower natural gas prices contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.


Three Months Ended September 30, 2022 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at July 1, 2022	$	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 January 1, 2022	$	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 January 1, 2022. 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. Partially offsetting the decrease in the allowance for credit losses, we believe that the high energy costs that customers experienced during this time, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.


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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, 2023 and December 31, 2022. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2022 Annual Report on Form 10-K.


(in millions)	September 30, 2023		December 31, 2022
Regulatory assets
Pension and OPEB costs	$	691.2	$	714.3
Plant retirement related items	657.0		688.6
Environmental remediation costs	577.7		610.7
Income tax related items	450.4		461.9
Asset retirement obligations	170.1		169.7
Derivatives	126.2		133.8
System support resource	115.9		123.5
Uncollectible expense	95.5		69.3
Securitization	87.5		92.4
Bluewater (1)	39.9		20.9
Energy costs recoverable through rate adjustments	35.5		26.9
Energy efficiency programs	25.3		33.9
MERC extraordinary natural gas costs	9.3		35.1
Other, net	131.4		125.9
Total regulatory assets	$	3,212.9	$	3,306.9

Balance sheet presentation
Other current assets	$	15.8	$	42.3
Regulatory assets	3,197.1		3,264.6
Total regulatory assets	$	3,212.9	$	3,306.9

(1)Primarily related to costs associated with the long-term service agreements our Wisconsin utilities have with Bluewater for natural gas storage services. The PSCW has approved escrow accounting for these costs. As a result, our Wisconsin utilities defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding.


(in millions)	September 30, 2023		December 31, 2022
Regulatory liabilities
Income tax related items	$	1,916.8	$	1,956.6
Removal costs	1,308.2		1,260.9
Pension and OPEB benefits	327.2		340.5
Energy costs refundable through rate adjustments	84.3		53.4
Derivatives	33.9		76.7
Uncollectible expense	26.9		24.0
Electric transmission costs	21.0		0.4
Decoupling	14.9		20.2
Energy efficiency programs	8.1		10.4
Other, net	48.3		48.8
Total regulatory liabilities	$	3,789.6	$	3,791.9

Balance sheet presentation
Other current liabilities	$	69.6	$	56.4
Regulatory liabilities	3,720.0		3,735.5
Total regulatory liabilities	$	3,789.6	$	3,791.9


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NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 5-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 5-8 became probable. In early 2023, we received additional approvals for electric generation facilities, including Koshkonong and 100 MWs of West Riverside. See Note 2, Acquisitions, for more information on the acquisition of West Riverside, which was completed in June 2023. OCPP Units 5 and 6 are expected to be retired by May 2024, while OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 5-8 was $798.9 million at September 30, 2023, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. Columbia Units 1 and 2 are expected to be retired by June 2026. The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $261.8 million at September 30, 2023, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson I Solar Energy Center LLC – Storm Damage

During a wind storm in March 2023, certain sections across approximately 40% of our Samson I solar facility incurred some amount of damage. As of September 30, 2023, we recognized an impairment of $1.6 million related to damage from this storm, which was offset by a $1.6 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from this event.

NOTE 8—JOINTLY OWNED UTILITY FACILITIES

We hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We pay our ownership share of additional construction costs and have supplied our own financing for all jointly owned projects. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

In June 2023, WE completed the acquisition of a 13.8% ownership interest, or 100 MWs, of West Riverside, a commercially operational dual fueled combined cycle generation facility.

See Note 2, Acquisitions, for more information.


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NOTE 9—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2023, 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)						257,780
Restricted shares (2)						75,453
Performance units						157,035

(1)Stock options awarded had a weighted-average exercise price of $93.69 and a weighted-average grant date fair value of $19.58 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $93.69 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 loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2022 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 19, 2023, our Board of Directors declared a quarterly cash dividend of $0.78 per share, payable on December 1, 2023, to shareholders of record on November 14, 2023.

NOTE 10—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, 2023			December 31, 2022
Commercial paper
Amount outstanding	$	1,545.3		$	1,643.5
Weighted-average interest rate on amounts outstanding	5.46		%	4.64		%
Operating expense loans
Amount outstanding (1)	$	4.0		$	3.6

(1)Coyote Ridge Wind, LLC, 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, 2023 was $1,053.3 million with a weighted-average interest rate during the period of 5.17%.


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


(in millions)	Maturity	September 30, 2023
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		1,545.3
Available capacity under existing agreements		$	1,552.4

In October 2023, WEC Energy Group entered into a new $200.0 million credit facility that expires October 2024.

NOTE 11—LONG-TERM DEBT

In March 2022, President Biden signed into law the Adjustable Interest Rate (LIBOR) Act. This Act established a uniform process, on a nationwide basis, for replacing LIBOR in certain contracts that did not provide a clearly defined or practicable replacement benchmark rate. Under the LIBOR Act, the Federal Reserve Board was required to determine an appropriate benchmark replacement based on SOFR, with applicable credit spread adjustments. In December 2022, the Federal Reserve Board adopted the final rule to implement the LIBOR Act and established the SOFR-based benchmark replacements. No contract modifications were required for qualifying contracts under the LIBOR Act as the benchmark replacement automatically overrode the existing contract language and became the applicable benchmark after June 30, 2023.

For our $500.0 million of 2007 Junior Notes, starting August 15, 2023, the benchmark replacement rate is the applicable tenor of three-month CME Term SOFR, as administered by the CME Group Benchmark Administration, and includes a credit spread adjustment of 0.26161% per annum. In accordance with the LIBOR Act, no contract modifications were required for our 2007 Junior Notes as the references to LIBOR were replaced by operation of law.

WEC Energy Group, Inc.

In January 2023, we issued $650.0 million of 4.75% Senior Notes due January 9, 2026, and $450.0 million of 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other corporate purposes.

In April 2023, we issued an additional $350.0 million of our 4.75% Senior Notes due January 9, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes.

In September 2023, we issued $600.0 million of 5.60% Senior Notes due September 12, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes. Subsequently, we repaid the outstanding principal and accrued interest on our $700.0 million of 0.55% Senior Notes that matured on September 15, 2023.

Integrys Holding, Inc.

In March 2023, Integrys repurchased $18.9 million of the $221.4 million outstanding of its 6.00% 2013 Junior Notes, prior to maturity for $18.6 million. Integrys recognized an insignificant gain on the early extinguishment of debt due to the debt being repurchased at a discount.

On August 1, 2023, Integrys redeemed the remaining $202.5 million outstanding of its 6.00% 2013 Junior Notes, prior to maturity at par value.


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NOTE 12—LEASES

Obligations Under Finance Leases

Land Leases – Utility Solar Generation

WE and WPS partnered with an unaffiliated utility to acquire and construct Darien, a utility-scale solar-powered electric generating facility in Rock and Walworth counties, Wisconsin. WE and WPS own 75% and 15%, respectively, of Darien. Commercial operation of the project is targeted in 2024. Related to their investment in Darien, WE and WPS, along with their unaffiliated utility partner, entered into several land leases that commenced in the second quarter of 2023. 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. Once Darien achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased. The lease payments will be recovered through rates.

Our total obligation under the land-related finance leases for Darien was $40.3 million at September 30, 2023, and was included in long-term debt on our balance sheet. Our finance lease right of use asset related to Darien was $39.2 million as of September 30, 2023, and was included in property, plant, and equipment on our balance sheet.

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the expense recognition pattern associated with the Darien 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 on our balance sheet in accordance with Subtopic 980-842.

At September 30, 2023, our weighted-average discount rate for the Darien finance leases was 5.96%. 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 Darien as of September 30, 2023, were as follows:


(in millions)
Three Months Ended December 31, 2023	$	—
2024	0.7
2025	1.9
2026	2.0
2027	2.0
2028	2.1
Thereafter	157.7
Total minimum lease payments	166.4
Less: Interest	(126.1)
Present value of minimum lease payments	40.3
Less: Short-term lease liabilities	—
Long-term lease liabilities	$	40.3

NOTE 13—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	September 30, 2023		December 31, 2022
Natural gas in storage	$	353.2	$	446.3
Materials and supplies	301.7		257.0
Fossil fuel	95.0		103.8
Total	$	749.9	$	807.1


09/30/2023 Form 10-Q			22			WEC Energy Group, Inc.

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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, 2023, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

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

NOTE 14—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, 2023				Three Months Ended September 30, 2022
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	79.0	21.0	%	$	78.9	21.0	%
State income taxes net of federal tax benefit	23.2		6.2	%	23.5		6.3	%
PTCs, net	(30.2)		(8.0)	%	(18.6)		(5.0)	%
Federal excess deferred tax amortization	(8.5)		(2.3)	%	(8.1)		(2.2)	%



Other, net	(3.1)		(0.8)	%	(2.3)		(0.5)	%
Total income tax expense	$	60.4	16.1	%	$	73.4	19.6	%

	Nine Months Ended September 30, 2023				Nine Months Ended September 30, 2022
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	272.2	21.0	%	$	298.1	21.0	%
State income taxes net of federal tax benefit	80.0		6.2	%	89.3		6.3	%
PTCs, net	(130.3)		(10.1)	%	(86.3)		(6.1)	%
Federal excess deferred tax amortization	(28.9)		(2.2)	%	(32.3)		(2.3)	%



Other, net	(10.0)		(0.8)	%	(4.9)		(0.3)	%
Total income tax expense	$	183.0	14.1	%	$	263.9	18.6	%

The effective tax rates for the three and nine months ended September 30, 2023, and 2022, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in renewable generation facilities in our non-utility energy infrastructure and Wisconsin segments 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 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 lines above). See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information about the impact of the Tax Legislation.

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023, under this transferability provision, we entered into an agreement to sell substantially all of our 2023 PTCs to a third party. We elect to account for net proceeds received from the sale of PTCs as a reduction to income taxes payable under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We will also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits will be presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

NOTE 15—FAIR VALUE MEASUREMENTS

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


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

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

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

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

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

When possible, we base the valuations of our 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, such as FTRs and TCRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. FTRs and TCRs are valued using auction prices from the applicable regional transmission organization.

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, 2023
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.4	$	10.3	$	—	$	12.7
FTRs and TCRs	—		—		11.3		11.3
Coal contracts	—		0.8		—		0.8
Total derivative assets	$	2.4	$	11.1	$	11.3	$	24.8

Investments held in rabbi trust	$	46.2	$	—	$	—	$	46.2

Derivative liabilities
Natural gas contracts	$	70.7	$	12.7	$	—	$	83.4
Coal contracts	—		25.1		—		25.1
Total derivative liabilities	$	70.7	$	37.8	$	—	$	108.5


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	December 31, 2022
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	16.3	$	16.2	$	—	$	32.5
FTRs	—		—		7.8		7.8
Coal contracts	—		34.5		—		34.5
Total derivative assets	$	16.3	$	50.7	$	7.8	$	74.8

Investments held in rabbi trust	$	50.9	$	—	$	—	$	50.9

Derivative liabilities
Natural gas contracts	$	81.4	$	15.2	$	—	$	96.6

The derivative assets and liabilities listed in the tables above include options, 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, 2023 and 2022, the net unrealized losses included in earnings related to the investments held at the end of the period were $1.7 million and $2.5 million, respectively. For the nine months ended September 30, 2023, we recorded $4.7 million of net unrealized gains in earnings related to the investments held at the end of the period, compared with $15.9 million of net unrealized losses recorded during the same period in 2022.

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)	2023		2022		2023		2022
Balance at the beginning of the period	$	16.8	$	19.9	$	7.8	$	2.4
Purchases	0.4		0.2		19.9		22.1
Realized and unrealized net gains (losses) included in earnings (1)	0.1		(0.3)		(0.4)		1.5
Settlements	(6.0)		(7.8)		(16.0)		(14.0)
Balance at the end of the period	$	11.3	$	12.0	$	11.3	$	12.0
Unrealized net gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)	$	0.1	$	(0.2)	$	0.1	$	0.1

(1)Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These realized and unrealized net 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, 2023				December 31, 2022
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	21.5	$	30.4	$	22.7
Long-term debt, including current portion (1)	16,517.2		14,645.0		15,464.2		13,921.3

(1)The carrying amount of long-term debt excludes finance lease obligations of $152.2 million and $183.2 million at September 30, 2023 and December 31, 2022, respectively.

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


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NOTE 16—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 are included in the other current and other long-term line items on our balance sheets. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments.


	September 30, 2023				December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	12.5	$	81.1	$	32.5	$	88.2
FTRs and TCRs	11.3		—		7.8		—
Coal contracts	0.6		13.8		18.9		—
Total current	24.4		94.9		59.2		88.2

Long-term
Natural gas contracts	0.2		2.3		—		8.4
Coal contracts	0.2		11.3		15.6		—
Total long-term	0.4		13.6		15.6		8.4
Total	$	24.8	$	108.5	$	74.8	$	96.6

Realized gains and losses on derivatives used in our regulated 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 and losses were as follows:


	Three Months Ended September 30, 2023			Three Months Ended September 30, 2022
(in millions)	Volumes	Gains (Losses)		Volumes	Gains
Natural gas contracts	37.8 Dth	$	(56.3)	32.7 Dth	$	119.1
FTRs and TCRs	8.1 MWh	21.9		7.0 MWh	7.4
Total		$	(34.4)		$	126.5

	Nine Months Ended September 30, 2023			Nine Months Ended September 30, 2022
(in millions)	Volumes	Gains (Losses)		Volumes	Gains
Natural gas contracts	144.2 Dth	$	(200.7)	133.3 Dth	$	259.6
FTRs and TCRs	22.9 MWh	26.4		21.0 MWh	12.7
Total		$	(174.3)		$	272.3

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2023 and December 31, 2022, we had posted cash collateral of $118.4 million and $122.4 million, respectively. These amounts were recorded on our balance sheets as collateral on deposit.


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


	September 30, 2023					December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	24.8	$	108.5		$	74.8	$	96.6
Gross amount not offset on the balance sheet	(3.4)		(71.7)		(1)	(17.5)		(82.5)		(2)
Net amount	$	21.4	$	36.8		$	57.3	$	14.1

(1)Includes cash collateral posted of $68.3 million.

(2)Includes cash collateral posted of $65.0 million.

Cash Flow Hedges

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the three and nine months ended September 30, 2023 and 2022 were not significant. At September 30, 2023, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 17—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at September 30, 2023		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	124.4	$	26.5	$	0.2	$	97.7
Surety bonds (2)	33.6		33.6		—		—
Other guarantees (3)	11.1		—		—		11.1
Total guarantees	$	169.1	$	60.1	$	0.2	$	108.8

(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 environmental remediation, 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.


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NOTE 18—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans:


	Pension Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2023		2022		2023		2022
Service cost	$	6.0	$	12.3	$	18.0	$	38.9
Interest cost	30.5		23.2		91.7		68.4
Expected return on plan assets	(46.8)		(51.6)		(140.6)		(156.8)
Loss on plan settlement	—		1.1		—		3.3
Amortization of prior service cost	—		0.4		0.1		1.2
Amortization of net actuarial loss	8.1		19.0		24.8		57.2
Net periodic benefit cost (credit)	$	(2.2)	$	4.4	$	(6.0)	$	12.2


	OPEB Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2023		2022		2023		2022
Service cost	$	2.4	$	3.6	$	7.3	$	10.7
Interest cost	5.4		3.8		16.2		11.5
Expected return on plan assets	(13.3)		(17.2)		(39.8)		(51.7)

Amortization of prior service credit	(3.7)		(4.0)		(11.1)		(11.9)
Amortization of net actuarial gain	(3.0)		(6.2)		(9.2)		(18.5)
Net periodic benefit credit	$	(12.2)	$	(20.0)	$	(36.6)	$	(59.9)

During the nine months ended September 30, 2023, we made contributions and payments of $11.4 million related to our pension plans and $1.6 million related to our OPEB plans. We expect to make contributions and payments of $3.2 million related to our pension plans and $0.3 million related to our OPEB plans during the remainder of 2023, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of September 30, 2023, we recorded an $8.0 million regulatory asset for pension costs and an $11.1 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

NOTE 19—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, 2023. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2023.


(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, 2023.

During the third quarter of 2023, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2023. No impairments resulted from these tests.


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Intangible Assets

At September 30, 2023 and December 31, 2022, we had $29.3 million and $24.9 million, respectively, of indefinite-lived intangible assets, largely consisting of spectrum frequencies. During the nine months ended September 30, 2023, we purchased additional spectrum frequencies for $4.4 million. The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of 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.


	September 30, 2023						December 31, 2022
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	653.9	$	(53.4)	$	600.5	$	343.9	$	(16.9)	$	327.0
Proxy revenue swap (2)	7.2		(3.3)		3.9		7.2		(2.8)		4.4
Interconnection agreements (3)	4.7		(0.9)		3.8		4.7		(0.7)		4.0
Total intangible liabilities	$	665.8	$	(57.6)	$	608.2	$	355.8	$	(20.4)	$	335.4

(1) Represents PPAs related to the acquisition of Blooming Grove Wind Energy Center LLC , Tatanka Ridge, Jayhawk, Thunderhead, Samson I, and Sapphire Sky expiring between 2030 and 2037. The weighted-average remaining useful life of the PPAs is 12 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 five years.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, 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 17 years.

Amortization related to these intangible liabilities for the three and nine months ended September 30, 2023, was $13.4 million and $37.2 million, respectively. Amortization for the three and nine months ended September 30, 2022, was $2.2 million and $6.5 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 2023, is estimated to be:


	For the Years Ending December 31
(in millions)	2023		2024		2025		2026		2027
Amortization to be recorded as an increase to operating revenues	$	50.4	$	53.4	$	53.4	$	53.4	$	53.4
Amortization to be recorded as a decrease to other operation and maintenance	0.2		0.2		0.2		0.2		0.2


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NOTE 20—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, 2023
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,931.8	$	24.1	$	1,955.9
Add: Earnings from equity method investment	44.2		0.5		44.7
Add: Capital contributions	18.2		—		18.2
Less: Distributions	35.0		—		35.0


Balance at end of period	$	1,959.2	$	24.6	$	1,983.8

	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

	Nine Months Ended September 30, 2023
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,884.6	$	24.6	$	1,909.2
Add: Earnings from equity method investment	130.2		1.9		132.1
Add: Capital contributions	51.5		—		51.5
Less: Distributions	107.1		1.9		109.0

Balance at end of period	$	1,959.2	$	24.6	$	1,983.8

	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

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

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2023		2022		2023		2022
Charges to ATC for services and construction	$	4.5	$	3.9	$	12.3	$	14.8
Charges from ATC for network transmission services	94.3		90.9		283.1		272.8


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


(in millions)	September 30, 2023		December 31, 2022
Accounts receivable for services provided to ATC	$	1.8	$	1.2

Accounts payable for services received from ATC	31.6		30.4
Amounts due from ATC for transmission infrastructure upgrades (1)	46.1		26.6

(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)	2023		2022		2023		2022
Income statement data
Operating revenues	$	206.2	$	169.8	$	610.4	$	552.4
Operating expenses	102.8		97.7		303.4		288.4
Other expense, net	32.9		34.5		98.3		91.3
Net income	$	70.5	$	37.6	$	208.7	$	172.7


(in millions)	September 30, 2023		December 31, 2022
Balance sheet data
Current assets	$	98.7	$	89.6
Noncurrent assets	6,234.6		5,997.8
Total assets	$	6,333.3	$	6,087.4

Current liabilities	$	333.0	$	511.9
Long-term debt	2,810.7		2,613.0
Other noncurrent liabilities	589.1		485.8
Members' equity	2,600.5		2,476.7
Total liabilities and members' equity	$	6,333.3	$	6,087.4

NOTE 21—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 2023, we reported six segments, which are described below.

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

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

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

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

•The non-utility energy infrastructure segment includes:

◦We Power, which owns and leases generating facilities to WE,

◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and

◦WECI, which holds majority interests in multiple renewable generating facilities.

See Note 2, Acquisitions, for more information on recent WECI acquisitions.


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•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, 2023 and 2022:


	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, 2023
External revenues	$	1,622.0	$	243.3	$	47.6	$	1,912.9	$	—	$	44.5	$	—	$	—	$	1,957.4
Intersegment revenues	—		—		—		—		—		115.3		—		(115.3)		—
Other operation and maintenance	387.1		86.5		21.7		495.3		—		21.5		1.3		(1.5)		516.6
Depreciation and amortization	215.3		59.3		11.2		285.8		—		48.8		5.3		(19.6)		320.3
Equity in earnings of transmission affiliates	—		—		—		—		44.7		—		—		—		44.7
Interest expense	148.7		22.0		3.7		174.4		5.0		24.8		66.3		(88.0)		182.5
Income tax expense (benefit)	69.3		8.9		(2.0)		76.2		10.0		(6.7)		(19.1)		—		60.4
Net income (loss)	243.4		24.7		(6.0)		262.1		29.7		66.7		(42.9)		—		315.6
Net income (loss) attributed to common shareholders	243.1		24.7		(6.0)		261.8		29.7		67.4		(42.9)		—		316.0


	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
Three Months Ended September 30, 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
Nine Months Ended September 30, 2023
External revenues	$	5,042.8	$	1,116.5	$	379.5	$	6,538.8	$	—	$	136.6	$	0.1	$	—	$	6,675.5
Intersegment revenues	—		—		—		—		—		358.4		—		(358.4)		—
Other operation and maintenance	1,119.7		305.5		68.2		1,493.4		—		59.6		0.6		(7.0)		1,546.6
Depreciation and amortization	632.9		176.3		32.2		841.4		—		139.9		15.6		(57.2)		939.7
Equity in earnings of transmission affiliates	—		—		—		—		132.1		—		—		—		132.1
Interest expense	449.4		65.0		12.0		526.4		14.6		69.8		183.9		(261.3)		533.4
Income tax expense (benefit)	188.8		61.8		10.5		261.1		29.4		(44.2)		(63.3)		—		183.0
Net income (loss)	686.8		167.9		30.9		885.6		88.1		240.9		(101.4)		—		1,113.2
Net income (loss) attributed to common shareholders	685.9		167.9		30.9		884.7		88.1		241.8		(101.4)		—		1,113.2


	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

NOTE 22—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.


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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.

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 WEPCo Environmental Trust's indenture trustee.

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 sheets:


(in millions)	September 30, 2023		December 31, 2022
Assets
Other current assets (restricted cash)	$	3.9	$	3.0
Regulatory assets	87.5		92.4
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.0		8.9

Other current liabilities (accrued interest)	0.5		0.1
Long-term debt	89.8		94.1

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, 2023 and December 31, 2022, our equity investment in ATC was $1,959.2 million and $1,884.6 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 both September 30, 2023 and December 31, 2022, our equity investment in ATC Holdco was $24.6 million, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 20, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.


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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. This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023. See Note 2, Acquisitions, for more information on the acquisition of this facility. The tolling agreement represented a variable interest until the facility was acquired since its terms were substantially similar to the terms of the PPA. Based on the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we were not the primary beneficiary of the entity. We did not hold an equity or debt interest in the entity, and there was no residual guarantee associated with the tolling agreement. Similar to the PPA, we accounted for the tolling agreement as a finance lease.

NOTE 23—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 renewable 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 generating facilities.

Our minimum future commitments related to these purchase obligations as of September 30, 2023, including those of our subsidiaries, were approximately $9.9 billion.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, 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

In March 2023, the EPA issued its final Good Neighbor Plan, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. After review of the final rule, we believe that we are well positioned to meet the requirements.

Our RICE units in the Upper Peninsula of Michigan and Wisconsin are not currently subject to the final rule as each unit is less than 25 MWs. To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule.


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Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu. Adoption of either of these lower limits could have an adverse effect on our utilities.

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 November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting the reconsideration of the 2015 standard. The EPA staff issued a draft Policy Assessment in March 2023 that also supported the reconsideration. Although initially targeting the end of 2023 for completing its reconsideration, the EPA announced in August 2023 that it is instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. This new review is anticipated to take 3 to 5 years to complete.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations 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, which the EPA approved in February 2023.

In April 2022, the EPA proposed to find that the Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and should 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 submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

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 PM and determined that no revisions were necessary to the current annual standard of 12 µg/m3 or the 24-hour standard of 35 µg/m3. 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 PM NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard. In January 2023, the EPA announced its proposed decision to revise the primary (health-based) annual PM2.5 standard from its current level of 12 µg/m3 to within the range of 9 to 10 µg/m3. The EPA also proposed not to change the current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards. The EPA did, however, take comments on the full range (between 8 and 11 µg/m3) included in the CASAC's latest report. 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. After finalization of the rule, the WDNR will need to draft and submit a SIP for the EPA's approval. A final rule is anticipated in late 2023 or early 2024.

Climate Change

In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which replaced the Clean Power Plan. For coal plants, there are no applicable standards until 2032, and after 2032 the applicable standard is dependent on the unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the rule is highly dependent on hydrogen as an alternative fuel, or carbon capture. For simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our RICE units in Michigan and the new Weston RICE project are not affected under the rule because each RICE unit is less than 25 MWs. We are evaluating the proposed rule to understand the impacts to our operations.


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In May 2023, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units. New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load. Our RICE units are not affected by this rule since each unit is below 25 MWs. Our ESG Progress Plan is heavily focused on reducing GHG emissions. The EPA has indicated that it anticipates a final rule in the second quarter of 2024.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, in June 2022. In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The proposed revisions could impact the reporting required for our electric generation facilities, local natural gas distribution companies, and underground natural gas storage facilities. In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024. We are currently evaluating the potential impact of the proposed rule, if any, on our operations.

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 1,900 MWs of fossil-fueled generation since the beginning of 2018. Through our ESG Progress Plan, we expect to retire approximately 1,500 MWs 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 and 2. See Note 7, Property, Plant, and Equipment, 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 systems, 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

The EPA issued a final regulation under Section 316(b) of the CWA that became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule 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.

Pursuant to a WDNR rule, which became effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule 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 OCPP Units 5-8 and Weston Units 3 and 4. We 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 at the OCPP 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 expected in January 2024.

The WDNR reissued the WPDES permit for PWGS effective October 2023. This reissued permit includes a conditional BTA determination with conditions for the existing PWGS porous dike (rock breakwater) cooling water intake structure. We do not anticipate compliance with these conditions will result in a material impact on our financial condition or results of operations.


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Steam Electric Effluent Limitation Guidelines

The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater. Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications are necessary to meet the ELG rule requirements. Through 2023, we expect that compliance costs associated with the ELG rule will require $105 million in capital investment. An $8 million BATW modification to OC 7 and OC 8 was completed and placed in-service in mid-2021, and in December 2021, the PSCW issued a Certificate of Authority approving the $89 million ERGS FGD wastewater treatment system modification. The BATW modifications, including $8 million of modifications at Weston Unit 3 completed in June 2023, did 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 deadlines in December 2023.

In March 2023, the EPA issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on: 1) BATW; 2) FGD wastewater; 3) CCR leachate; and 4) legacy wastewaters. The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater. Under the proposed rule, this new ZLD requirement must be met by a date determined by the permitting authority (the WDNR for WE) that is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029.

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule. Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032. Although the $89 million biological treatment system at ERGS is 99% complete and on track for completion before year-end to meet the WPDES permit deadline, the timing of the project's completion would not comply with the deadline proposed by the EPA to qualify for the early adopter status. In addition, we do not believe that, upon its completion, the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed. In May 2023, we submitted written comments to the EPA articulating these concerns, including the cost impact to our customers. The EPA has indicated that it is anticipating the rule to be final in the second quarter of 2024.

If the supplemental ELG rule is finalized as proposed, we anticipate that our coal-fueled facilities, including ERGS Units 1 and 2 that were built with ELG-compliant dry BA transport systems, will meet the BATW rule provisions.

The EPA also proposed requirements for legacy wastewaters and landfill leachate. We are reviewing those proposed requirements to determine potential costs and actions required for our facilities.

Waters of the United States

In January 2023, the EPA and the Army Corps (the agencies) together released a final rule effective in March 2023, that based the definition of WOTUS on its pre-2015 definition. The pre-2015 approach involved applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

In May 2023, in Sackett v. EPA, the Supreme Court issued a decision significantly narrowing federal jurisdiction over wetlands to "traditional navigable waters" and wetlands or other waters that have a "continuous surface connection" with a traditional navigable water.

In August 2023, the agencies revised the final rule to conform the definition of WOTUS to the Supreme Court's May 2023 Sackett decision. The conforming rule became effective upon publication in the Federal Register on September 8, 2023.

We anticipate this final rule revision caused by the Sackett decision will cause a decrease in the number of projects that require Army Corps federal wetland permits. This decision also may affect the administration of some state programs. At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts.


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Land Quality

Manufactured Gas Plant Remediation

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

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

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

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


(in millions)	September 30, 2023		December 31, 2022
Regulatory assets	$	577.7	$	610.7
Reserves for future environmental remediation	456.6		499.6

Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to all landfills, historic fill sites, and projects where CCR was placed. As proposed, the rule would regulate previously exempt closed landfills and would include sites we own as well as several third party owned properties.

We are actively engaged with the Utility Solid Waste Activities Group and the EEI and provided them information to include in their comments to the EPA. The EPA has indicated that it is anticipating the rule to be final in the second quarter of 2024. The proposed rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs.

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 begin later in 2023.


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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 started the process in early 2023 to close out this Consent Decree.

NOTE 24—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Nine Months Ended September 30
(in millions)	2023		2022
Cash paid for interest, net of amount capitalized	$	432.9	$	311.4
Cash paid for income taxes, net	15.8		52.3
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	236.5		170.9
Accounts payable related to Thunderhead acquisition milestone payments	—		19.0
Increase in receivables related to insurance proceeds	6.2		—

Liabilities accrued for software licensing agreement	—		7.4

Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. 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, 2023		December 31, 2022
Cash and cash equivalents	$	45.9	$	28.9
Restricted cash included in other current assets	43.6		25.6
Restricted cash included in other long-term assets	51.9		127.7
Cash, cash equivalents, and restricted cash	$	141.4	$	182.2

Our restricted cash consisted of the following:

•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.

•Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEC Infrastructure Wind Holding I LLC, WECI Wind Holding II, and WEPCo Environmental Trust.

•Cash we received when WECI acquired ownership interests in certain renewable generation projects. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the renewable generation facilities.

•Cash used by WE and WPS during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets at December 31, 2022. See Note 2, Acquisitions, for more information on the purchase of this facility.


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NOTE 25—REGULATORY ENVIRONMENT

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

2024 Limited Rate Case Re-Opener

In accordance with their rate orders approved by the PSCW in December 2022, WE, WPS, and WG filed requests for limited electric and natural gas rate case re-openers, as applicable, with the PSCW in May 2023. The limited electric rate case re-openers filed by WE and WPS include updated revenue requirements for the generation projects that were previously approved by the PSCW and are expected to be placed into service in 2023 and 2024. WE's limited electric re-opener also includes the projected savings from the retirement of the OCPP Units 5 and 6, which are expected to be retired in May 2024. WE and WG also filed a request for a limited natural gas rate case re-opener to reflect the additional revenue requirements associated with their previously approved LNG projects that are expected to be placed into service in 2023 and 2024, respectively.

The requested increases in 2024 base rates are as follows:


	WE					WPS					WG
Requested 2024 base rate increases
Electric	$	45.0	million	/	1.3%	$	8.6	million	/	0.5%	N/A
Gas	$	23.9	million	/	4.5%	N/A					$	22.2	million	/	2.9%

The utilities' ROE and common equity component averages will not be addressed in the limited rate case re-openers. A PSCW decision is expected in the fourth quarter of 2023, with new rates expected to be effective January 1, 2024.

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

2023 Rate Case

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas rates. They are requesting incremental rate increases of $194.7 million (13.0%) and $18.7 million (7.8%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL is also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service.

Both companies are requesting an ROE of 9.90% and a common equity component average of 54.0%. PGL is not seeking an extension of the QIP rider. Instead, PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements. See the Qualifying Infrastructure Plant Rider section below for more information on the QIP rider.

An ICC decision is anticipated in the fourth quarter of 2023, with any rate adjustments expected to be effective January 1, 2024.

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 will not seek an extension of the rider beyond 2023.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending.

As of September 30, 2023, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2022, will be deemed recoverable by the ICC.


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Minnesota Energy Resources Corporation

2023 Rate Case

In November 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 reflected a 10.3% ROE and a common equity component average of 53.0%. The proposed retail natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023.

On October 26, 2023, the MPUC verbally approved a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers. A final written order is expected by the end of 2023, with final rates expected to be implemented in the first quarter of 2024. MERC’s customers will be entitled to a refund to the extent the interim rate increase exceeds the final approved rate increase. These refunds are also expected to occur during the first quarter of 2024.

Michigan Gas Utilities Corporation

2023 Rate Order

In March 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates. On August 30, 2023, the MPSC issued a written order approving a comprehensive settlement that resolved all issues in MGU's rate case. The key terms of the settlement agreement include:

•a natural gas base rate increase of $9.9 million (4.7%);

•an ROE of 9.8%;

•a common equity component average of 51%; and,

•a continuation of the existing MRP rider, effective January 1, 2025 through 2027, including forecasted increased costs for those projects. MRP costs will be recovered in base rates in 2024.

The rate increase was primarily driven by capital investments made to strengthen the safety and reliability of MGU's natural gas distribution system and to provide service to additional customers. Inflationary pressure on operating costs also contributed to the rate increase. The new rates will be effective January 1, 2024.

NOTE 26—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 and in January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other interbank offered rates to alternative reference rates. These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic. Our $500.0 million 2007 Junior Notes, which were previously subject to a variable rate based on U.S. dollar LIBOR, became subject to a variable rate based on SOFR beginning July 1, 2023. No contract modifications were required as the references to LIBOR were replaced by operation of law. See Note 11, Long-Term Debt, for more information. We do not anticipate this guidance having a significant impact 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 2022 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 that it leases to Wisconsin Electric Power Company (WE)), 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 renewable 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.

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.

We have 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 Elm Road Generating Station (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 2032.

We already have retired more than 1,900 MWs of fossil-fueled 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 1,500 MWs 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 by June 2026 of jointly-owned Columbia Units 1 and 2.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $6.8 billion from 2024-2028 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:

•2,700 MWs of utility-scale solar;

•880 MWs of wind; and


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•250 MWs of battery storage.

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

•1,125 MW of combustion turbines;

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

•the purchase of 100 MWs of additional capacity in the West Riverside Energy Center.

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

In December 2018, WE received approval from the Public Service Commission of Wisconsin (PSCW) for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MWs 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 27 Solar Now projects and currently has another two under construction, together totaling more than 30 MWs. The second program, the Dedicated Renewable Energy Resource (DRER) pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, and could add up to 35 MWs of renewables to WE's portfolio. The DRER pilot would help these larger customers meet their sustainability and renewable energy goals. In July 2023, WE and Wisconsin Public Service Corporation (WPS) received approval from the PSCW for the Renewable Pathway Pilot, the third renewable energy program. This program allows commercial and industrial customers to subscribe to a portion of a utility-scale, Wisconsin-based renewable energy generating facility. The Renewable Pathway Pilot will utilize generation from Paris Solar-Battery Park, Darien Solar Park, and Red Barn Wind Park and will have a participation cap of 125 MW at WE and 40 MW at WPS.

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 natural gas utility systems. In 2022, we received approval from the PSCW for our RNG pilots. We have since signed eight contracts for RNG for our natural gas distribution business, which will be transporting the output of local dairy farms onto our gas distribution systems. The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes. These eight contracts bring us to 1.5 Bcf of RNG planned to enter our systems, and we expect to have RNG flowing in 2023, supporting our goal to reduce methane emissions.

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 (EPRI) in this research that could help create another viable option for decarbonizing the economy. The results of this testing were shared earlier this year by EPRI.

We are planning for the start of a pilot program in the fourth-quarter of 2023 with EPRI and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S. electric grid. The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today.

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.


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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 and storm hardening.

We expect to spend approximately $3.7 billion from 2024 to 2028 on reliability related projects with continued investment anticipated 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, Dispositions, for information on recent transactions.

Our investment focus from 2024 to 2028 will be primarily in our regulated utilities and also our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $20 billion from 2024 to 2028. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3 billion. We expect to invest approximately $0.4 billion in our non-utility energy infrastructure business over the same period, which relates to the previously announced Maple Flats project. Specific projects included in the $23.4 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects. Also, see Note 2, Acquisitions, for information on recent and pending transactions.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

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


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Safety

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

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

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

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2023

Consolidated Earnings

The following table compares our consolidated results for the third quarter of 2023 with the third quarter of 2022, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended September 30
(in millions, except per share data)	2023		2022		B (W)
Wisconsin	$	243.1	$	194.9	$	48.2
Illinois	24.7		14.9		9.8
Other states	(6.0)		(6.1)		0.1
Electric transmission	29.7		44.5		(14.8)
Non-utility energy infrastructure	67.4		71.0		(3.6)
Corporate and other	(42.9)		(17.2)		(25.7)
Net income attributed to common shareholders	$	316.0	$	302.0	$	14.0

Diluted earnings per share	$	1.00	$	0.96	$	0.04

Earnings increased $14.0 million during the third quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the $14.0 million increase in earnings were:

•A $48.2 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive quarter-over-quarter impact from collections of fuel and purchased power costs. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders. These positive impacts were partially offset by higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, benefits, and regulatory amortizations.

•A $9.8 million increase in net income attributed to common shareholders at the Illinois segment, driven by lower operation and maintenance expense, primarily due to a decrease in natural gas distribution and maintenance expenses. Higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider also contributed to the increase in earnings. These positive impacts were partially offset by higher interest expense.

These increases in earnings were partially offset by:

•A $25.7 million increase in net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense, primarily due to long-term debt issuances in September 2022, January 2023, and April 2023. Higher average short-term debt balances and increased short-term debt interest rates also contributed to the increase in interest expense.


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•A $14.8 million decrease in net income attributed to common shareholders at the electric transmission segment, driven by the positive impact in the third quarter of 2022 related to the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on the 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 in our 2022 Annual Report on Form 10-K. Partially offsetting this negative impact was continued capital investment by ATC.

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 2023 and 2022:


	Three Months Ended September 30
(in millions)	2023		2022
Wisconsin	$	426.1	$	367.3
Illinois	54.1		36.2
Other states	(4.7)		(5.4)

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


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Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $243.1 million during the third quarter of 2023, representing a $48.2 million, or 24.7%, increase over the same quarter in 2022. The higher earnings were driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive quarter-over-quarter impact from collections of fuel and purchased power costs. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders. These positive impacts were partially offset by higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, benefits, and regulatory amortizations.


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Electric revenues	$	1,460.8	$	1,440.2	$	20.6
Fuel and purchased power	487.6		605.7		118.1
Total electric margins	973.2		834.5		138.7

Natural gas revenues	161.2		236.6		(75.4)
Cost of natural gas sold	61.5		144.0		82.5
Total natural gas margins	99.7		92.6		7.1

Total electric and natural gas margins	1,072.9		927.1		145.8

Other operation and maintenance	387.1		329.1		(58.0)
Depreciation and amortization	215.3		189.2		(26.1)
Property and revenue taxes	44.4		41.5		(2.9)
Operating income	426.1		367.3		58.8

Other income, net	35.3		28.8		6.5
Interest expense	148.7		137.2		(11.5)
Income before income taxes	312.7		258.9		53.8

Income tax expense	69.3		63.7		(5.6)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	243.1	$	194.9	$	48.2

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


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in line items below	167.7		$	164.6	$	(3.1)
Transmission (1)	135.3		107.8		(27.5)
Regulatory amortizations and other pass through expenses (2)	49.2		35.6		(13.6)
We Power (3)	35.8		26.5		(9.3)
Earnings sharing mechanisms (4)	(0.9)		(5.4)		(4.5)
Total other operation and maintenance	$	387.1	$	329.1	$	(58.0)

(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 2023 and 2022, $136.4 million and $134.9 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 lower transmission expense during the third quarter of 2022.

(2)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income. Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs as well as certain costs associated


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with our jointly-owned Columbia plant. As a result, our Wisconsin utilities defer as a regulatory asset or liability, the difference between these actual costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the third quarter of 2023 and 2022, $26.7 million and $29.7 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(4)For the third quarter of 2022, this amount represented 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 2022 Annual Report on Form 10-K for more information.

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	2023	2022	B (W)
Customer Class
Residential	3,228.3	3,225.6	2.7
Small commercial and industrial (1)	3,481.7	3,481.8	(0.1)
Large commercial and industrial (1)	3,171.8	3,268.3	(96.5)
Other	27.3	29.8	(2.5)
Total retail (1)	9,909.1	10,005.5	(96.4)
Wholesale	475.5	584.9	(109.4)
Resale	2,262.7	1,232.5	1,030.2
Total sales in MWh (1)	12,647.3	11,822.9	824.4

(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	2023	2022	B (W)
Customer Class
Residential	58.8	68.8	(10.0)
Commercial and industrial	51.4	62.8	(11.4)
Total retail	110.2	131.6	(21.4)
Transportation	263.0	287.2	(24.2)
Total sales in therms	373.2	418.8	(45.6)


	Three Months Ended September 30
	Degree Days
Weather	2023	2022	B (W)
WE and WG (1)
Heating (99 Normal)	32	89	(64.0)	%
Cooling (591 Normal)	676	677	(0.1)	%

WPS (2)
Heating (177 Normal)	108	129	(16.3)	%
Cooling (390 Normal)	391	468	(16.5)	%

UMERC (3)
Heating (304 Normal)	242	253	(4.3)	%
Cooling (257 Normal)	188	243	(22.6)	%

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

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


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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 $20.6 million during the third quarter of 2023, compared with the same quarter in 2022. 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 $138.7 million during the third quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the higher electric utility margins were:

•A $97.5 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.

•A $55.5 million quarter-over-quarter positive impact from collections of fuel and purchased power costs. 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. In 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

These increases in margins were partially offset by:

•A $9.8 million decrease in other revenues, primarily related to a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including our electric utilities, as well as lower revenues from third-party use of our assets.

•A $5.9 million decrease in margins related to lower retail sales volumes, driven by the impact of unfavorable weather during the third quarter of 2023, compared with the same quarter in 2022. As measured by cooling degree days, the third quarter of 2023 was 16.5% cooler than the same quarter in 2022 in the Green Bay area.

Natural Gas Revenues

Natural gas revenues decreased $75.4 million during the third quarter of 2023, compared with the same quarter in 2022. 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 decreased approximately 51% during the third quarter of 2023, compared with the same quarter in 2022. 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 $7.1 million during the third quarter of 2023, compared with the same quarter in 2022. The most significant factor impacting the higher natural gas utility margins was a $9.4 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. This increase in margins was partially offset by a $2.2 million decrease in margins from lower sales volumes, due in part to the impact of unfavorable weather during the third quarter of 2023, compared with the same quarter in 2022. As measured by heating degree days, the third quarter of 2023 was 64.0% and 16.3% warmer than the same quarter in 2022 in the Milwaukee area and Green Bay area, respectively. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.


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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 increased $87.0 million during the third quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in other operating expenses were:

•A $27.5 million increase in transmission expense as approved in the PSCW's 2023 rate orders, effective January 1, 2023. See the notes under the other operation and maintenance table above for more information. This amount is net of a deferral of $2.7 million approved by the PSCW in June 2023, retroactive to December 1, 2022, in response to a FERC order eliminating reactive power compensation to our utilities, as discussed in electric margins above.

•A $26.1 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

•A $13.8 million increase in benefit costs, primarily driven by higher stock-based compensation expense related to plan performance.

•A $13.6 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $9.3 million increase 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.

Other Income, Net

Other income, net at the Wisconsin segment increased $6.5 million during the third quarter of 2023, compared with the same quarter in 2022, driven by higher AFUDC–Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $11.5 million during the third quarter of 2023, compared with the same quarter in 2022, primarily due to the impact of WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively, and higher short-term debt interest rates. Also contributing to the increase was the deferral in the third quarter of 2022 of $2.0 million of interest expense related to capital investments made by WG since its 2020 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. This deferred interest expense is now being amortized over a two-year period. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information. These increases were partially offset by higher AFUDC–Debt due to continued capital investment and 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.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $5.6 million during the third quarter of 2023, compared with the same quarter in 2022. The increase in income tax expense was due to higher pre-tax income, partially offset by a $5.4 million increase in PTCs.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $24.7 million during the third quarter of 2023, representing a $9.8 million, or 65.8%, increase over the same quarter in 2022. The increase was driven by lower operation and maintenance expense, primarily due to a decrease in natural gas distribution and maintenance expenses. Higher natural gas margins due to PGL's continued capital investment in the SMP project under its QIP rider also contributed to the increase in earnings. These positive impacts were partially offset by higher interest expense.


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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)	2023		2022		B (W)
Natural gas revenues	$	243.3	$	230.3	$	13.0
Cost of natural gas sold	36.7		27.4		(9.3)
Total natural gas margins	206.6		202.9		3.7

Other operation and maintenance	86.5		100.2		13.7
Depreciation and amortization	59.3		57.9		(1.4)
Property and revenue taxes	6.7		8.6		1.9
Operating income	54.1		36.2		17.9

Other income, net	1.5		2.6		(1.1)
Interest expense	22.0		18.1		(3.9)
Income before income taxes	33.6		20.7		12.9

Income tax expense	8.9		5.8		(3.1)
Net income attributed to common shareholders	$	24.7	$	14.9	$	9.8

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


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in the line items below	$	72.8	$	84.9	$	12.1
Riders (1)	13.7		16.0		2.3
Regulatory amortizations (1)	—		(0.7)		(0.7)

Total other operation and maintenance	$	86.5	$	100.2	$	13.7

(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	2023	2022	B (W)
Customer Class
Residential	47.4	45.7	1.7
Commercial and industrial	21.6	23.5	(1.9)
Total retail	69.0	69.2	(0.2)
Transportation	90.0	93.3	(3.3)
Total sales in therms	159.0	162.5	(3.5)


	Three Months Ended September 30
	Degree Days
Weather (1)	2023	2022	B (W)
Heating (69 Normal)	19	86	(77.9)	%

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

Natural Gas Revenues

Natural gas revenues increased $13.0 million during the third quarter of 2023, compared with the same quarter in 2022. 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 approximately 33% during the third quarter of 2023,


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compared with the same quarter in 2022. 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 $2.3 million impact of the riders referenced in the table above, increased $6.0 million during the third quarter of 2023, compared with the same quarter in 2022. The increase in margins was primarily driven by a $5.8 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 the end of 2023. See Note 25, Regulatory Environment, for more information.

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

Other operating expenses at the Illinois segment decreased $11.9 million, net of the $2.3 million impact of the riders referenced in the table above, during the third quarter of 2023, compared with the same quarter in 2022. The significant factor impacting the decrease in other operating expenses was a $10.1 million decrease in natural gas distribution and maintenance costs, primarily related to work on the natural gas infrastructure.

Other Income, Net

Other income, net at the Illinois segment decreased $1.1 million during the third quarter of 2023, compared with the same quarter in 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs. See Note 18, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the Illinois segment increased $3.9 million during the third quarter of 2023, compared with the same quarter in 2022, primarily due to higher average short-term debt balances, increased short-term interest rates, and PGL issuing long-term debt in December 2022.

Income Tax Expense

Income tax expense at the Illinois segment increased $3.1 million during the third quarter of 2023, compared with the same quarter in 2022, driven by an increase in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's net loss attributed to common shareholders was $6.0 million during the third quarter of 2023, representing a $0.1 million, or 1.6%, reduction in net loss over the same quarter in 2022. The reduction in net loss was driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023, partially offset by higher operating expenses driven by increases in benefit costs and depreciation and amortization.


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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)	2023		2022		B (W)
Natural gas revenues	$	47.6	$	69.2	$	(21.6)
Cost of natural gas sold	13.1		36.6		23.5
Total natural gas margins	34.5		32.6		1.9

Other operation and maintenance	21.7		21.0		(0.7)
Depreciation and amortization	11.2		10.3		(0.9)
Property and revenue taxes	6.3		6.7		0.4
Operating loss	(4.7)		(5.4)		0.7

Other income, net	0.4		0.7		(0.3)
Interest expense	3.7		3.3		(0.4)
Loss before income taxes	(8.0)		(8.0)		—

Income tax benefit	(2.0)		(1.9)		0.1
Net loss attributed to common shareholders	$	(6.0)	$	(6.1)	$	0.1

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


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in line item below	$	18.6	$	18.3	$	(0.3)
Regulatory amortizations and other pass through expenses (1)	3.1		2.7		(0.4)

Total other operation and maintenance	$	21.7	$	21.0	$	(0.7)

(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	2023	2022	B (W)
Customer Class
Residential	15.2	15.9	(0.7)
Commercial and industrial	11.6	15.1	(3.5)
Total retail	26.8	31.0	(4.2)
Transportation	189.4	164.4	25.0
Total sales in therms	216.2	195.4	20.8


	Three Months Ended September 30
	Degree Days
Weather (1)	2023	2022	B (W)
MERC
Heating (204 Normal)	123	184	(33.2)	%

MGU
Heating (108 Normal)	93	112	(17.0)	%

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


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Natural Gas Revenues

Natural gas revenues decreased $21.6 million during the third quarter of 2023, compared with the same quarter in 2022. 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 decreased approximately 65% during the third quarter of 2023, compared with the same quarter in 2022. 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 $1.9 million during the third quarter of 2023, compared with the same quarter in 2022. The primary factor impacting the increase in natural gas utility margins was a $1.6 million increase related to an interim rate increase at MERC that was effective January 1, 2023. See Note 25, Regulatory Environment, for more information.

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 $1.2 million during the third quarter of 2023, compared with the same quarter in 2022. The primary factors impacting the increase in operating expenses were a $0.9 million increase in benefit costs, primarily due to higher stock-based compensation expense related to plan performance, and a $0.9 million increase in depreciation and amortization related to continued capital investment.

Interest Expense

Interest expense at the other states segment increased $0.4 million during the third quarter of 2023, compared with the same quarter in 2022, primarily due to higher short-term debt interest rates.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Equity in earnings of transmission affiliates	$	44.7	$	63.7	$	(19.0)
Interest expense	5.0		4.9		(0.1)
Income before income taxes	39.7		58.8		(19.1)

Income tax expense	10.0		14.3		4.3
Net income attributed to common shareholders	$	29.7	$	44.5	$	(14.8)

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates decreased $19.0 million during the third quarter of 2023, compared with the same quarter in 2022. The decrease was primarily driven by the $20.5 million positive impact in the third quarter of 2022 related to the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. For information on the 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 in our 2022 Annual Report on Form 10-K. Partially offsetting this negative impact was continued capital investment by ATC.

Income Tax Expense

Income tax expense at the electric transmission segment decreased $4.3 million during the third quarter of 2023, compared with the same quarter in 2022, primarily due to a decrease in pre-tax income.


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


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Operating income	$	84.8	$	89.1	$	(4.3)

Interest expense	24.8		17.0		(7.8)
Income before income taxes	60.0		72.1		(12.1)

Income tax expense (benefit)	(6.7)		1.7		8.4
Net loss attributed to noncontrolling interests	0.7		0.6		0.1
Net income attributed to common shareholders	$	67.4	$	71.0	$	(3.6)

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $4.3 million during the third quarter of 2023, compared with the same quarter in 2022. The decrease was primarily due to unfavorable production at our renewable generation facilities resulting from lower wind speeds.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $7.8 million during the third quarter of 2023, compared with the same quarter in 2022, primarily due to a $5.4 million increase in intercompany interest expense due to WECI’s issuance of a $430.0 million long-term intercompany note payable to WEC Energy Group in April 2023. This intercompany interest expense is offset by higher intercompany interest income at the corporate and other segment. Also driving the increase was WECI Wind Holding II's issuance of long-term debt in December 2022.

Income Tax Expense (Benefit)

At the non-utility energy infrastructure segment, $6.7 million of income tax benefit was recorded during the third quarter of 2023, compared with $1.7 million of income tax expense recorded during the same quarter in 2022. The change was primarily due to a $4.2 million increase in PTCs in 2023, driven by the acquisition of three additional renewable generation facilities in the second half of 2022 and the first quarter of 2023. Also contributing to this favorable change in the income tax benefit was lower pre-tax income in 2023.

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


	Three Months Ended September 30
(in millions)	2023		2022		B (W)
Operating income (loss)	$	(6.6)	$	0.3	$	(6.9)

Other income, net	10.9		3.2		7.7
Interest expense	66.3		30.9		(35.4)

Loss before income taxes	(62.0)		(27.4)		(34.6)

Income tax benefit	(19.1)		(10.2)		8.9
Net loss attributed to common shareholders	$	(42.9)	$	(17.2)	$	(25.7)

Operating Income (Loss)

The corporate and other segment had an operating loss of $6.6 million during the third quarter of 2023, compared with operating income of $0.3 million during the same quarter in 2022. The change was driven by a $5.2 million decrease in operating income at Wispark, primarily due to the positive impact from a payment on a note receivable during the third quarter of 2022 that was previously written off due to uncertainty regarding its collectability. The quarter-over-quarter negative impact from gains on the sale of land during the third quarter of 2022 also contributed to the lower operating income at Wispark.


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Other Income, Net

Other income, net at the corporate and other segment increased $7.7 million during the third quarter of 2023, compared with the same quarter in 2022. The significant factors impacting the increase in other income, net were:

•A $5.7 million increase in intercompany interest income, driven by WECI's issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023 and higher interest rates on short-term borrowings to subsidiaries in our operating segments. This intercompany interest income is offset by higher intercompany interest expense in our operating segments.

•A $1.2 million decrease in the net losses from the investments held in the Integrys rabbi trust during the third quarter of 2023, compared with the same quarter in 2022. The losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments. See Note 15, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Interest Expense

Interest expense at the corporate and other segment increased $35.4 million during the third quarter of 2023, compared with the same quarter in 2022, due to long-term debt issuances by WEC Energy Group in September 2022, January 2023, and April 2023. Also driving the increase in interest expense were higher average short-term debt balances and increased short-term debt interest rates.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $8.9 million during the third quarter of 2023, compared with the same quarter in 2022. This increase was driven by a higher pre-tax loss.

NINE MONTHS ENDED SEPTEMBER 30, 2023

Consolidated Earnings

The following table compares our consolidated results for the nine months ended September 30, 2023 with the nine months ended September 30, 2022, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Nine Months Ended September 30
(in millions, except per share data)	2023		2022		B (W)
Wisconsin	$	685.9	$	631.4	$	54.5
Illinois	167.9		184.7		(16.8)
Other states	30.9		28.1		2.8
Electric transmission	88.1		101.3		(13.2)
Non-utility energy infrastructure	241.8		242.8		(1.0)
Corporate and other	(101.4)		(32.9)		(68.5)
Net income attributed to common shareholders	$	1,113.2	$	1,155.4	$	(42.2)

Diluted Earnings Per Share	$	3.52	$	3.65	$	(0.13)

Earnings decreased $42.2 million during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the $42.2 million decrease in earnings were:

•A $68.5 million increase in net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense on both long-term and short-term debt. This negative impact was partially offset by net gains from the investments held in the Integrys rabbi trust during the nine months ended September 30, 2023, compared with net losses during the same period in 2022. 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 primarily included in other operation and maintenance expense in our utility segments. See Note 15, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.


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•A $16.8 million decrease in net income attributed to common shareholders at the Illinois segment, driven by higher operation and maintenance expense, primarily due to the period-over-period impact of a gain recorded in 2022 on the sale of certain real estate by PGL and the impact from a 2023 ICC order associated with an annual prudency review of the UEA riders. Lower natural gas distribution and maintenance costs and a decrease in expenses related to charitable contributions partially offset these increases in operating expenses. Also contributing to the lower earnings was an increase in interest expense on short-term and long-term borrowings. These negative impacts were partially offset by higher natural gas margins, primarily due to PGL's continued capital investment in the SMP project under its QIP rider.

•A $13.2 million decrease in net income attributed to common shareholders at the electric transmission segment, driven by the positive impact in the third quarter of 2022 related to the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE.

These decreases in earnings were partially offset by a $54.5 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive period-over-period impact from collections of fuel and purchased power costs. These positive impacts were partially offset by a decrease in electric and natural gas margins due to lower sales volumes and higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, and regulatory amortizations.

Expected 2023 Annual Effective Tax Rate

We expect our 2023 annual effective tax rate to be between 13.0% and 14.0%. 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, 2023 and 2022:


	Nine Months Ended September 30
(in millions)	2023		2022
Wisconsin	$	1,220.2	$	1,174.1
Illinois	290.4		296.3
Other states	52.7		45.5


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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 $685.9 million during the nine months ended September 30, 2023, representing a $54.5 million, or 8.6%, increase over the same period in 2022. The higher earnings were driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive period-over-period impact from collections of fuel and purchased power costs. These positive impacts were partially offset by a decrease in electric and natural gas margins due to lower sales volumes and higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, and regulatory amortizations.


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Electric revenues	$	3,851.7	$	3,858.7	$	(7.0)
Fuel and purchased power	1,258.0		1,485.5		227.5
Total electric margins	2,593.7		2,373.2		220.5

Natural gas revenues	1,191.1		1,317.8		(126.7)
Cost of natural gas sold	677.3		850.0		172.7
Total natural gas margins	513.8		467.8		46.0

Total electric and natural gas margins	3,107.5		2,841.0		266.5

Other operation and maintenance	1,119.7		979.6		(140.1)
Depreciation and amortization	632.9		564.0		(68.9)
Property and revenue taxes	134.7		123.3		(11.4)
Operating income	1,220.2		1,174.1		46.1

Other income, net	104.8		75.7		29.1
Interest expense	449.4		409.1		(40.3)
Income before income taxes	875.6		840.7		34.9

Income tax expense	188.8		208.4		19.6
Preferred stock dividends of subsidiary	0.9		0.9		—
Net income attributed to common shareholders	$	685.9	$	631.4	$	54.5

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


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in line items below	$	457.0	$	483.3	$	26.3
Transmission (1)	405.0		323.1		(81.9)
Regulatory amortizations and other pass through expenses (2)	153.5		108.0		(45.5)
We Power (3)	106.8		81.4		(25.4)


Earnings sharing mechanisms (4)	(2.6)		(16.2)		(13.6)
Total other operation and maintenance	$	1,119.7	$	979.6	$	(140.1)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During both the nine months ended September 30, 2023 and 2022, $391.5 million 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 lower transmission expense during the nine months ended September 30, 2022.


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(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, 2023 and 2022, $89.1 million and $80.6 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.

(4)For the nine months ended September 30, 2022, this amount represented 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.

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	2023	2022	B (W)
Customer Class
Residential	8,394.6	8,726.7	(332.1)
Small commercial and industrial (1)	9,685.2	9,793.9	(108.7)
Large commercial and industrial (1)	9,080.0	9,238.8	(158.8)
Other	90.4	98.9	(8.5)
Total retail (1)	27,250.2	27,858.3	(608.1)
Wholesale	1,396.5	1,942.8	(546.3)
Resale	4,484.0	3,326.7	1,157.3
Total sales in MWh (1)	33,130.7	33,127.8	2.9

(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	2023	2022	B (W)
Customer Class
Residential	702.9	810.0	(107.1)
Commercial and industrial	457.1	515.4	(58.3)
Total retail	1,160.0	1,325.4	(165.4)
Transportation	964.0	1,054.8	(90.8)
Total sales in therms	2,124.0	2,380.2	(256.2)


	Nine Months Ended September 30
	Degree Days
Weather	2023	2022	B (W)
WE and WG (1)
Heating (4,293 Normal)	3,623	4,254	(14.8)	%
Cooling (762 Normal)	834	936	(10.9)	%

WPS (2)
Heating (4,794 Normal)	4,337	4,880	(11.1)	%
Cooling (538 Normal)	565	717	(21.2)	%

UMERC (3)
Heating (5,482 Normal)	4,998	5,824	(14.2)	%
Cooling (340 Normal)	296	358	(17.3)	%

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

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


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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 decreased $7.0 million during the nine months ended September 30, 2023, compared with the same period in 2022. 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 $220.5 million during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the higher electric utility margins were:

•A $253.6 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023.

•A $46.5 million period-over-period positive impact from collections of fuel and purchased power costs. 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. In 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

•A $13.7 million increase in margins during the nine months ended September 30, 2023, related to the expiration of a capacity purchase contract driven by the acquisition of the Whitewater facility, effective January 1, 2023.

These increases in margins were partially offset by:

•A $56.8 million decrease in margins related to lower retail sales volumes, driven by the impact of unfavorable weather during the nine months ended September 30, 2023, compared with the same period in 2022. As measured by cooling degree days, the nine months ended September 30, 2023 were 10.9% and 21.2% cooler than the same period in 2022 in the Milwaukee area and Green Bay area, respectively. As measured by heating degree days, the nine months ended September 30, 2023 were 14.8% and 11.1% warmer than the same period in 2022 in the Milwaukee area and Green Bay area, respectively.

•A $21.5 million decrease in other revenues, primarily related to a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including our electric utilities, as well as lower revenues from third-party use of our assets.

•Lower margins of $7.9 million driven by the expiration of a wholesale contract in May 2022.

•A $4.1 million decrease in margins from our steam operations related to lower sales volumes, driven by the impact of unfavorable weather.

Natural Gas Revenues

Natural gas revenues decreased $126.7 million during the nine months ended September 30, 2023, compared with the same period in 2022. 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 decreased approximately 13% during the nine months ended September 30, 2023, compared with the same period in 2022. The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.


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Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $46.0 million during the nine months ended September 30, 2023, compared with the same period in 2022. The most significant factor impacting the higher natural gas utility margins was an $80.0 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023. This increase in margins was partially offset by a $34.2 million decrease in margins from lower sales volumes, driven by the impact of unfavorable weather during the nine months ended September 30, 2023, compared with the same period in 2022.

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

Other operating expenses at the Wisconsin segment increased $220.4 million during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the increase in other operating expenses were:

•An $81.9 million increase in transmission expense as approved in the PSCW's 2023 rate orders, effective January 1, 2023. See the notes under the other operation and maintenance table above for more information. This amount is net of a deferral of $9.2 million approved by the PSCW in June 2023, retroactive to December 1, 2022, in response to a FERC order eliminating reactive power compensation to our utilities, as discussed in electric margins above.

•A $68.9 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

•A $45.5 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $25.4 million increase 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 $13.6 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above.

•A $9.2 million increase in other operating and maintenance related to our power plants, driven by increased maintenance, including planned outages at the Weston power plant, and operating costs associated with Whitewater, which we purchased in January 2023.

These increases in other operating expenses were partially offset by:

•A $19.1 million increase in pre-tax gains on the sale of land, primarily at our Pleasant Prairie power plant site, during the nine months ended September 30, 2023, compared with the same period in 2022. See Note 3, Dispositions, for more information.

•A $7.3 million decrease in electric and natural gas distribution expenses, primarily driven by lower costs to maintain the distribution system and for storm restoration during the nine months ended September 30, 2023, compared with the same period in 2022.

Other Income, Net

Other income, net at the Wisconsin segment increased $29.1 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by higher AFUDC–Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $40.3 million during the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to the impact of WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively, and higher short-term debt interest rates. Also contributing to the increase was the deferral of $9.2 million of interest expense related to capital investments made by WG since its 2020 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


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increases. This deferred interest expense is now being amortized over a two-year period. These increases were partially offset by higher AFUDC–Debt due to continued capital investment and 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.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $19.6 million during the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to a $19.0 million increase in PTCs and a $4.6 million increase in income tax benefits associated with AFUDC-Equity driven by continued capital investment. These decreases in income tax expense were partially offset by higher pre-tax income.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $167.9 million during the nine months ended September 30, 2023, representing a $16.8 million, or 9.1%, decrease over the same period in 2022. The decrease was driven by higher operation and maintenance expense, primarily due to the period-over-period impact of a gain recorded in 2022 on the sale of certain real estate by PGL and the impact from a 2023 ICC order associated with an annual prudency review of the UEA riders. Lower natural gas distribution and maintenance costs and a decrease in expenses related to charitable contributions partially offset these increases in operating expenses. Also contributing to the lower earnings was an increase in interest expense on short-term and long-term borrowings. These negative impacts were partially offset by higher natural gas margins, primarily due to PGL's continued capital investment in the SMP project under its QIP rider.


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Natural gas revenues	$	1,116.5	$	1,354.8	$	(238.3)
Cost of natural gas sold	316.5		564.0		247.5
Total natural gas margins	800.0		790.8		9.2

Other operation and maintenance	305.5		292.9		(12.6)
Depreciation and amortization	176.3		172.1		(4.2)
Property and revenue taxes	27.8		29.5		1.7
Operating income	290.4		296.3		(5.9)

Other income, net	4.3		11.3		(7.0)
Interest expense	65.0		53.8		(11.2)
Income before income taxes	229.7		253.8		(24.1)

Income tax expense	61.8		69.1		7.3
Net income attributed to common shareholders	$	167.9	$	184.7	$	(16.8)

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


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in the line items below	$	231.3	$	208.7	$	(22.6)
Riders (1)	74.4		85.9		11.5
Regulatory amortizations (1)	(0.2)		(1.7)		(1.5)

Total other operation and maintenance	$	305.5	$	292.9	$	(12.6)

(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	2023	2022	B (W)
Customer Class
Residential	538.4	620.7	(82.3)
Commercial and industrial	214.0	248.9	(34.9)
Total retail	752.4	869.6	(117.2)
Transportation	524.5	585.9	(61.4)
Total sales in therms	1,276.9	1,455.5	(178.6)


	Nine Months Ended September 30
	Degree Days
Weather (1)	2023	2022	B (W)
Heating (3,913 Normal)	3,339	4,017	(16.9)	%

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

Natural Gas Revenues

Natural gas revenues decreased $238.3 million during the nine months ended September 30, 2023, compared with the same period in 2022. 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 decreased approximately 35% during the nine months ended September 30, 2023, compared with the same period in 2022. 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 $11.5 million impact of the riders referenced in the table above, increased $20.7 million during the nine months ended September 30, 2023, compared with the same period in 2022. The increase in margins was primarily driven by a $17.8 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 the end of 2023.

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

Other operating expenses at the Illinois segment increased $26.6 million, net of the $11.5 million impact of the riders referenced in the table above, during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the increase in other operating expenses were:

•A $54.5 million pre-tax gain on the sale of certain real estate in Chicago during the nine months ended September 30, 2022. See Note 3, Dispositions, for more information.

•An $11.1 million increase in expenses driven by an ICC order received in May 2023 related to an annual prudency review of PGL's and NSG's UEA riders, which required refunds to ratepayers starting in September 2023. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery for more information.

•An $8.4 million increase in expenses due to a ratemaking adjustment related to certain capitalized costs during the nine months ended September 30, 2023.


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These increases in other operating expenses were partially offset by:

•A $19.8 million decrease in natural gas distribution and maintenance costs, primarily related to work on the natural gas infrastructure during the nine months ended September 30, 2023, compared with the same period in 2022.

•A $10.0 million decrease in expenses related to contributions to charitable projects supporting our customers and the communities within our service territories during the nine months ended September 30, 2022.

•A $9.2 million decrease in expenses associated with the settlement of legal claims during the nine months ended September 30, 2022.

•A $6.4 million decrease in benefit costs, primarily due to lower stock-based compensation expense related to plan performance during the nine months ended September 30, 2023, compared with the same period in 2022.

Other Income, Net

Other income, net at the Illinois segment decreased $7.0 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs.

Interest Expense

Interest expense at the Illinois segment increased $11.2 million during the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to higher average short-term debt balances and increased short-term debt interest rates. Also contributing to the increase was a long-term debt issuance by PGL in December 2022.

Income Tax Expense

Income tax expense at the Illinois segment decreased $7.3 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by a decrease 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 $30.9 million during the nine months ended September 30, 2023, representing a $2.8 million, or 10.0%, increase over the same period in 2022. The increase was driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023. This positive impact was partially offset by a decrease in natural gas margins due to lower sales volumes and increases in property taxes and interest expense.


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	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Natural gas revenues	$	379.5	$	410.0	$	(30.5)
Cost of natural gas sold	208.0		249.3		41.3
Total natural gas margins	171.5		160.7		10.8

Other operation and maintenance	68.2		68.5		0.3
Depreciation and amortization	32.2		30.5		(1.7)
Property and revenue taxes	18.4		16.2		(2.2)
Operating income	52.7		45.5		7.2

Other income, net	0.7		1.8		(1.1)
Interest expense	12.0		9.8		(2.2)
Income before income taxes	41.4		37.5		3.9

Income tax expense	10.5		9.4		(1.1)
Net income attributed to common shareholders	$	30.9	$	28.1	$	2.8

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


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Operation and maintenance not included in line item below	$	53.5	$	54.6	$	1.1
Regulatory amortizations and other pass through expenses (1)	14.7		13.9		(0.8)

Total other operation and maintenance	$	68.2	$	68.5	$	0.3

(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	2023	2022	B (W)
Customer Class
Residential	204.4	240.5	(36.1)
Commercial and industrial	132.4	155.9	(23.5)
Total retail	336.8	396.4	(59.6)
Transportation	587.8	590.3	(2.5)
Total sales in therms	924.6	986.7	(62.1)


	Nine Months Ended September 30
	Degree Days
Weather (1)	2023	2022	B (W)
MERC
Heating (5,118 Normal)	4,882	5,608	(12.9)	%

MGU
Heating (4,078 Normal)	3,579	4,142	(13.6)	%


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Natural Gas Revenues

Natural gas revenues decreased $30.5 million during the nine months ended September 30, 2023, compared with the same period in 2022. 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 decreased approximately 3% during the nine months ended September 30, 2023, compared with the same period in 2022. 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 $10.8 million during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the increase in margins were:

•A $13.0 million increase related to an interim rate increase at MERC that was effective January 1, 2023.

•A $0.9 million increase in revenues related to late payment charges.

These increases in natural gas utility margins were partially offset by a $4.0 million decrease related to lower sales volumes, primarily driven by warmer weather. As measured by heating degree days, the nine months ended September 30, 2023, were 12.9% and 13.6% warmer than the same period in 2022 at MERC and MGU, respectively.

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 $3.6 million during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the increase in other operating expenses were:

•A $2.2 million increase in property and revenue taxes, driven by higher property taxes at MERC.

•A $1.7 million increase in depreciation and amortization related to continued capital investment.

•A $1.1 million increase in natural gas operations and customer service expense, primarily driven by various operation and maintenance projects at MERC.

These increases in other operating expenses were partially offset by a $0.6 million decrease in benefit costs, primarily due to lower stock-based compensation expense related to plan performance.

Other Income, Net

Other income, net at the other states segment decreased $1.1 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs. See Note 18, Employee Benefits, for more information on our benefit costs.

Interest Expense

Interest expense at the other states segment increased $2.2 million during the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to higher short-term debt interest rates.

Income Tax Expense

Income tax expense at the other states segment increased $1.1 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by higher pre-tax income.


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Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Equity in earnings of transmission affiliates	$	132.1	$	148.4	$	(16.3)
Interest expense	14.6		14.6		—
Income before income taxes	117.5		133.8		(16.3)

Income tax expense	29.4		32.5		3.1
Net income attributed to common shareholders	$	88.1	$	101.3	$	(13.2)

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates decreased $16.3 million during the nine months ended September 30, 2023, compared with the same period in 2022. The decrease was primarily driven by the $20.5 million positive impact in the third quarter of 2022 related to the D.C. Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE. Partially offsetting this negative impact was continued capital investment by ATC.

Income Tax Expense

Income tax expense at the electric transmission segment decreased $3.1 million during the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to a decrease in pre-tax income.

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


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Operating income	$	266.5	$	285.1	$	(18.6)

Interest expense	69.8		51.6		(18.2)
Income before income taxes	196.7		233.5		(36.8)

Income tax benefit	(44.2)		(10.5)		33.7
Net (income) loss attributed to noncontrolling interests	0.9		(1.2)		2.1
Net income attributed to common shareholders	$	241.8	$	242.8	$	(1.0)

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $18.6 million during the nine months ended September 30, 2023, compared with the same period in 2022. The decrease 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 FERC issued an order denying that complaint in the first quarter of 2022. In addition, unfavorable production at our renewable generation facilities resulting from lower wind speeds contributed to the decrease in operating income.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $18.2 million during the nine months ended September 30, 2023, compared with the same period in 2022, primarily due to a $10.8 million increase in intercompany interest expense due to WECI’s issuance of a $430.0 million long-term intercompany note payable to WEC Energy Group in April 2023. This intercompany interest expense is offset by higher intercompany interest income at the corporate and other segment. Also driving the increase was WECI Wind Holding II's issuance of long-term debt in December 2022.


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Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $33.7 million during the nine months ended September 30, 2023, compared with the same period in 2022. The increase was primarily due to a $24.4 million increase in PTCs in 2023, driven by the acquisition of three additional renewable generation facilities in the second half of 2022 and the first quarter of 2023. Also contributing to the favorable income tax variance were lower pre-tax earnings during the nine months ended September 30, 2023, compared with the same period in 2022.

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


	Nine Months Ended September 30
(in millions)	2023		2022		B (W)
Operating loss	$	(16.1)	$	(6.0)	$	(10.1)

Other income, net	35.3		6.2		29.1
Interest expense	183.9		78.1		(105.8)

Loss before income taxes	(164.7)		(77.9)		(86.8)

Income tax benefit	(63.3)		(45.0)		18.3
Net loss attributed to common shareholders	$	(101.4)	$	(32.9)	$	(68.5)

Operating Loss

The operating loss at the corporate and other segment increased $10.1 million during the nine months ended September 30, 2023, compared with the same period in 2022. The increased operating loss was driven by a $7.3 million decrease in operating income at Wispark, primarily due to the positive impact from a payment on a note receivable during 2022 that was previously written off due to uncertainty regarding its collectability. Lower gains related to the sale of land and other assets in 2023 also contributed to the decrease in operating income at Wispark.

Other Income, Net

Other income, net at the corporate and other segment increased $29.1 million during the nine months ended September 30, 2023, compared with the same period in 2022. The significant factors impacting the increase in other income, net were:

•A $7.5 million net gain from the investments held in the Integrys rabbi trust during the nine months ended September 30, 2023, compared with a $16.5 million net loss during the same period in 2022.

•A $13.3 million increase in intercompany interest income, driven by WECI's issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023 and higher interest rates on short-term borrowings to subsidiaries in our operating segments. This intercompany interest income is offset by higher intercompany interest expense in our operating segments.

These increases in other income, net were partially offset by a $3.2 million net loss from our equity method investments in technology and energy-focused investment funds during the nine months ended September 30, 2023, compared with $7.0 million of net earnings during the same period in 2022.

Interest Expense

Interest expense at the corporate and other segment increased $105.8 million during the nine months ended September 30, 2023, compared with the same period in 2022, due to long-term debt issuances by WEC Energy Group in September 2022, January 2023, and April 2023. Also driving the increase in interest expense were higher average short-term debt balances and increased short-term debt interest rates.


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Income Tax Benefit

The income tax benefit at the corporate and other segment increased $18.3 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by a higher pre-tax loss. This increase in income tax benefits was partially offset by a $6.5 million decrease in excess tax benefits recognized related to stock option exercises.

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)	2023		2022		Change in 2023 Over 2022
Cash provided by (used in):
Operating activities	$	2,538.4	$	2,059.5	$	478.9
Investing activities	(2,771.7)		(1,985.9)		(785.8)
Financing activities	192.5		(45.1)		237.6

Operating Activities

Net cash provided by operating activities increased $478.9 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by:

•A $1.1 billion increase in cash from lower payments for fuel and purchased power at our generation plants, as well as lower natural gas costs related to the natural gas sold to our customers during the nine months ended September 30, 2023, compared with the same period in 2022, primarily driven by a decrease in the price of natural gas.

•A $92.3 million increase in cash from higher overall collections from customers during the nine months ended September 30, 2023, compared with the same period in 2022. This increase was driven by the impact of the Wisconsin rate orders approved by the PSCW and the interim rates for MERC approved by the MPUC, both effective January 1, 2023. See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information on the 2023 rate orders.

•A $36.5 million increase in cash related to lower cash paid for income taxes, driven by lower taxable income during the nine months ended September 30, 2023, compared with the same period in 2022.

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

•A $481.2 million decrease in cash driven by collateral paid to counterparties during the nine months ended September 30, 2023, compared with collateral received from counterparties during the same period in 2022, as well as realized losses on derivative instruments recognized during the nine months ended September 30, 2023, compared with realized gains recognized during the same period in 2022.

•A $147.7 million decrease in cash from higher payments for other operation and maintenance expenses. During the nine months ended September 30, 2023, our payments were higher for charitable projects and operation and maintenance related to our We Power and Wisconsin generation units, as well as due to the timing of payments for accounts payable.

•A $121.5 million decrease in cash from higher payments for interest, driven by long-term debt issuances during the last four months of 2022 and early 2023, as well as higher interest rates during the nine months ended September 30, 2023, compared with the same period in 2022.


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Investing Activities

Net cash used in investing activities increased $785.8 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by:

•The acquisition of a 90% ownership interest in Sapphire Sky in February 2023 for $442.6 million, net of cash acquired of $0.3 million.

•The acquisition of an 80% ownership interest in Samson I in February 2023 for $249.4 million, net of cash acquired of $5.2 million.

•The acquisition of a 90% interest in Red Barn in April 2023 for $143.8 million. See Note 8, Jointly Owned Utility Facilities, for more information.

•The acquisition of a 13.8% ownership interest in West Riverside in June 2023 for $95.3 million. See Note 8, Jointly Owned Utility Facilities, for more information.

•The acquisition of Whitewater in January 2023 for $76.0 million.

•A decrease of $41.1 million in insurance proceeds received during the nine months ended September 30, 2023, compared to the same period in 2022. In 2022, we received insurance proceeds for property damage related to the Public Service Building water damage claim.

•A $38.6 million decrease in proceeds received from the sale of assets during the nine months ended September 30, 2023, compared with the same period in 2022.

•A $28.8 million increase in cash paid for capital expenditures during the nine months ended September 30, 2023, which is discussed in more detail below.

•A $12.1 increase in capital contributions paid to transmission affiliates during the nine months ended September 30, 2023, compared with the same period in 2022.

These increases in cash used in investing activities were partially offset by the acquisition of a 90% ownership interest in Thunderhead in September 2022 for $362.9 million, net of cash acquired of $0.5 million.

For more information on our acquisitions, see Note 2, Acquisitions.

Capital Expenditures

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


Reportable Segment (in millions)	2023		2022		Change in 2023 Over 2022
Wisconsin	$	1,263.5	$	1,189.0	$	74.5
Illinois	343.4		364.7		(21.3)
Other states	71.4		69.3		2.1
Non-utility energy infrastructure	33.9		63.3		(29.4)
Corporate and other	17.3		14.4		2.9
Total capital expenditures	$	1,729.5	$	1,700.7	$	28.8

The increase in cash paid for capital expenditures at the Wisconsin segment during the nine months ended September 30, 2023, compared with the same period in 2022, was driven by higher payments related to upgrades to WE's and WPS's electric and natural gas distribution systems and construction of WE's LNG facility, partially offset by decreased capital expenditures for renewable energy projects at WE and WPS.

The decrease in cash paid for capital expenditures at the Illinois segment during the nine months ended September 30, 2023, compared with the same period in 2022, was driven by lower payments related to PGL's natural gas distribution system, including SMP, partially offset by an increase in capital expenditures for the installation of meter reading devices during 2023.


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The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during the nine months ended September 30, 2023, compared with the same period in 2022, was primarily driven by lower capital expenditures for wastewater treatment system modifications for We Power's ERGS units. See Note 23, Commitments and Contingencies, for more information.

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

Financing Activities

Net cash related to financing activities increased $237.6 million during the nine months ended September 30, 2023, compared with the same period in 2022, driven by:

•A $650.0 million increase in cash due to higher issuances of long-term debt during the nine months ended September 30, 2023, compared with the same period in 2022.

•A $542.0 million increase in cash due to lower net repayments of commercial paper during the nine months ended September 30, 2023, compared with the same period in 2022.

•A $57.6 million increase in cash due to a decrease in common stock purchased during the nine months ended September 30, 2023, compared with the same period in 2022, to satisfy requirements of our stock-based compensation plans.

These increases in cash were partially offset by:

•A $931.1 million decrease in cash due to higher retirements of long-term debt during the nine months ended September 30, 2023, compared with the same period in 2022.

•A $49.6 million decrease in cash due to higher dividends paid on our common stock during the nine months ended September 30, 2023, compared with the same period in 2022. In January 2023, our Board of Directors increased our quarterly dividend by $0.0525 per share (7.2%) effective with the March 2023 dividend payment.

•A $30.1 million decrease in cash proceeds related to stock options exercised during the nine months ended September 30, 2023, compared with the same period in 2022.

Other Significant Financing Activities

For more information on our other significant financing activities, see Note 10, Short-Term Debt and Lines of Credit, and Note 11, 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 2022 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 23, Commitments and Contingencies.


(in millions)	2023 (1)		2024		2025
Wisconsin	$	2,142.0	$	2,542.5	$	2,979.5
Illinois	508.9		590.9		600.9
Other states	101.5		123.5		104.1
Non-utility energy infrastructure	749.9		395.7		31.5
Corporate and other	21.4		21.9		14.0
Total	$	3,523.7	$	3,674.5	$	3,730.0

(1)This includes actual capital expenditures incurred through September 30, 2023, 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 MWs 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 MWs of this project. WE's share of the cost of this project is estimated to be approximately $172 million. Commercial operation of Badger Hollow II is targeted for late 2023 or early 2024.

•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 MWs of solar generation and 99 MWs of battery storage of this project. WE's and WPS's combined share of the cost of this project is estimated to be approximately $542 million, with construction of the solar portion expected to be completed in 2024.

•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility. The project will be located in Rock and Walworth counties, Wisconsin and once fully constructed, WE and WPS will collectively own 225 MWs of solar generation. WE's and WPS's combined share of the cost of this project is estimated to be approximately $405 million, with construction expected to be completed in 2024. As part of its order, the PSCW approved battery capacity at this project, which is no longer included in the current capital plan. We will continue to evaluate timing, cost, and feasibility of the installation of batteries.

•In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $143.8 million.

•WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire Koshkonong, a utility-scale solar-powered electric generating facility. The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation. WE's and WPS's combined share of the cost of this project is estimated to be approximately $486 million, with construction expected to be completed in 2026. As part of its order, the PSCW approved battery capacity at this project, which is no longer included in the current capital plan. We will continue to evaluate timing, cost, and feasibility of the installation of batteries.


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•In July 2023, WE and WPS completed construction of 128 MWs of natural gas-fired generation at WPS's existing Weston power plant site in northern Wisconsin. The new facility consists of seven RICE units. Our plant in service balance on the Weston RICE units was $178.4 million as of September 30, 2023.

•In January 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electrical generation facility in Whitewater, Wisconsin. The cost of this facility was $76.0 million.

•In June 2023, WE closed on 100 MWs of capacity related to West Riverside for $95.3 million. West Riverside is a combined cycle natural gas plant completed and operated by an unaffiliated utility in Rock County, Wisconsin. In September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of capacity. In October 2023, WPS filed for approval to assign the second option to purchase part of West Riverside to WE. If approved, our share of the cost of this ownership interest is expected to be approximately $100 million, with the transaction expected to close in 2024.

In August 2023, the DOC issued a ruling in its 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 ruling and CBP actions related to solar panels, respectively. The expected in-service dates and costs 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 Bcf 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 $407 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. After 2023, PGL will return to the traditional ratemaking process to recover the costs of necessary infrastructure improvements. PGL's projected average annual investment through 2025 is between $280 million and $300 million.

The non-utility energy infrastructure line item in the table above includes WECI's recent investments in Sapphire Sky and Samson I, and its planned investment in 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 $230 million from 2023 through 2025. We do not expect to make any contributions to ATC Holdco during that period.

Long-Term Debt

See Note 11, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2023.

Common Stock Dividends

Our current quarterly dividend rate is $0.78 per share, which equates to an annual dividend of $3.12 per share. For information related to our most recent common stock dividend declared, see Note 9, Common Equity.


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Other Significant Cash Requirements

See Note 23, 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, 2023.

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 10, Short-Term Debt and Lines of Credit, Note 17, Guarantees, and Note 22, 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, as well as other types of securities. In addition, starting in 2024, we expect to issue common equity through a combination of our employee benefit plans, stock purchase, and dividend reinvestment plan and at-the-market offerings. 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. Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions.

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 2023, 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 2022 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, 2023, our current liabilities exceeded our current assets by $1,630.1 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 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 10, Short-Term Debt and Lines of Credit and Note 11, Long-Term Debt, for more information about our credit facilities, commercial paper, and debt securities.


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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 of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2022 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of September 30, 2023, 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	$	11,753.0		$	12,003.0
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	16,669.4			16,419.4
Short-term debt	1,549.3			1,549.3
Total capitalization	$	30,002.1		$	30,002.1

Total debt	$	18,218.7		$	17,968.7

Ratio of debt to total capitalization	60.7		%	59.9		%

Included in long-term debt on our balance sheet as of September 30, 2023, 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, 2023, 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 2022 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, 2023. 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, 2023, 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.


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On May 2, 2023, S&P Global Inc. affirmed WEC Energy Group’s ratings and revised its outlook to negative from stable, citing weakening financial measures. The ratings outlooks on our utilities remain stable. We do not believe the change in ratings outlook at WEC Energy Group will have a material impact on our ability to access capital markets.

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

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 2022 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.

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 ASC. 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. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation. The order requires a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively. These amounts are being refunded over a period of nine months, which began on September 1, 2023. PGL and NSG filed an application with the ICC requesting a rehearing of the May 2023 order, but it was denied by the ICC in June 2023. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders.

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is also subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending. As of September 30, 2023, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years, which include 2016 through 2022, will be deemed recoverable by the ICC.

See Note 25, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2022 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. 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.


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In July 2022, the PSCW found that the specific facts and circumstances merited the opening of a docket for each petition to consider whether to grant all or part of the requested declaratory ruling.

In December 2022, the PSCW granted one petitioner’s request for a declaratory ruling, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law. The ruling was limited to the specific facts and circumstances of the lease presented in that petition. A petition by the WUA to reopen or rehear the case expired without action by the PSCW. The WUA has filed an appeal which is pending consideration by the circuit court. The second petition is also currently being considered. Although the finding in the first petition was limited to the specific facts and circumstances of the lease presented in that petition, similar findings or a broader policy position could adversely impact our business operations.

Climate and Equitable Jobs Act

On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act. This 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.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities are no longer allowed to charge late payment fees to certain 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. 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, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and the related long-term impact to timing and cost of solar projects included in our capital plan. However, we are seeing some delays in the release of solar panels by the CBP, which are having an impact on the timing and cost of certain of our solar projects.

United States Department of Commerce Complaints

In February 2022, a California based company filed a petition (Antidumping and Countervailing Duties) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China and requested that the DOC conduct a country-wide inquiry into each of the four countries. After investigation, on December 2, 2022, the DOC announced its preliminary determination that certain companies are circumventing anti-dumping and countervailing duty orders on solar cells and modules from China.

On August 18, 2023, the DOC issued its final decision, substantially affirming its preliminary determination that circumvention was occurring in each of the four Southeast Asian countries noted above. In its decision, the DOC affirmed that the Biden Administration’s current 24-month tariff moratorium will remain in effect until June 6, 2024, subject to certain use and installation requirements, at which time tariffs are expected to resume. The Biden Administration also invoked the Defense Production Act to accelerate the production of solar panels in the U.S.; however, the DOC’s ruling may have an adverse impact on the solar industry overall. Additionally, the Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected. At this time, we do not expect this final ruling to have a material impact on our results of operations.

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 a five year period, 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


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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. Under this new IRA transferability option, we entered into a sales agreement in September 2023 to sell substantially all of our 2023 production tax credits to a third party. See Note 14, Income Taxes, for more information about the impact of these sales. 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 Complaint

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 a complaint was 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 ROE complaint section 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.

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.

•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


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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, 2023, 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.

Environmental Matters

See Note 23, 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 global conflicts, including 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 2022 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.


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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 three risk factors below that are disclosed in Part I of our 2022 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 the Operation of Our Business – We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

•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.

Collective Bargaining Agreement Negotiations

Management is engaged in contract negotiations with Local 2150 of the International Brotherhood of Electrical Workers, which represents certain Wisconsin employees who are currently operating under an expired collective bargaining agreement. The parties continue to negotiate in good faith. We have contingency plans in place. However, certain circumstances could have an adverse impact on our operations.

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 2022 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, 2023. 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. For our reporting units that 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.


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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, 2023, 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 19, 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 2022 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 15, Fair Value Measurements, Note 16, Derivative Instruments, and Note 17, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the third quarter of 2023 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 2022 Annual Report on Form 10-K. See Note 23, Commitments and Contingencies, and Note 25, 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 23, Commitments and Contingencies, Note 25, 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 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 is vigorously defending against the allegations made in this lawsuit and intends to continue to do so.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2022 Annual Report on Form 10-K.

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, 2023:


Issuer Purchases of Equity Securities
2023	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 – July 31	64	$	88.59	—	$	—
August 1 – August 31	—	—		—	—
September 1 – September 30	—	—		—	—
Total (1)	64	$	88.59	—

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

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 2023, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction, or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 of Regulation S-K).


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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. 15 of WEC Energy Group, effective as of September 5, 2023, under the Indenture for Debt Securities, dated as of March 15, 1999, between WEC Energy Group and The Bank of New York Mellon Trust Company N.A. (as successor to The First National Bank of Chicago), as Trustee. (Exhibit 4.1 to WEC Energy Group's Form 8-K filed September 12, 2023.)

















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 2, 2023	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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