WEC ENERGY GROUP, INC. [WEC] Filings

10-Q 1 wec-20240331.htm 10-Q wec-20240331

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 March 31, 2024


☐			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 (March 31, 2024):

Common Stock, $.01 Par Value, 315,822,587 shares outstanding

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WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2024

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Income Statements

Condensed Consolidated Statements of Comprehensive Income

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Equity

Notes to Condensed Consolidated Financial Statements

Page

Regulatory Assets and Liabilities

Note 6

Property, Plant, and Equipment

Note 7

Common Equity

Note 8

Short-Term Debt and Lines of Credit

Note 9

Long-Term Debt

Note 10

Materials, Supplies, and Inventories

Note 11

Income Taxes

Note 12

Fair Value Measurements

Note 13

Derivative Instruments

Goodwill and Intangibles

Note 17

Investment in Transmission Affiliates

Note 18

Segment Information

Note 19

Variable Interest Entities

Note 20

Commitments and Contingencies

Note 21

Supplemental Cash Flow Information

Note 22

Regulatory Environment

Note 23

New Accounting Pronouncements

ITEM 2.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.

CONTROLS AND PROCEDURES

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


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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

UMERC						Upper Michigan Energy Resources Corporation

WE						Wisconsin Electric Power Company
We Power						W.E. Power, LLC
WEC Energy Group						WEC Energy Group, Inc.
WECI						WEC Infrastructure LLC


WEPCo Environmental Trust						WEPCo Environmental Trust Finance I, LLC
WG						Wisconsin Gas LLC

WPS						Wisconsin Public Service Corporation

Federal and State Regulatory Agencies

CBP						United States Customs and Border Protection Agency
DOC						United States Department of Commerce
EPA						United States Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
ICC						Illinois Commerce Commission
IRS						United States Internal Revenue Service
MPSC						Michigan Public Service Commission
MPUC						Minnesota Public Utilities Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission
WDNR						Wisconsin Department of Natural Resources

Accounting Terms

ARO						Asset Retirement Obligation
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
CASAC						Clean Air Scientific Advisory Committee
CCR						Coal Combustion Residuals
CO2						Carbon Dioxide
CWA						Clean Water Act


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ELG						Steam Electric Effluent Limitation Guidelines
FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
NOV						Notice of Violation
NOx						Nitrogen Oxide
PM						Particulate Matter
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

CABO						Clean and Affordable Buildings Ordinance
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
CIP						Conservation Improvement Program
Compensation Committee						Compensation Committee of the Board of Directors
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
Darien						Darien Solar Park
Delilah I						Delilah I Solar Energy Center
DER						Distributed Energy Resource
DRER						Dedicated Renewable Energy Resource

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
LDC						Local Natural Gas Distribution Company

LNG						Liquefied Natural Gas
Maple Flats						Maple Flats Solar Energy Center LLC
MG&E						Madison Gas and Electric Company
MISO						Midcontinent Independent System Operator, Inc.
OCPP						Oak Creek Power Plant

Paris						Paris Solar-Battery Park
PPA						Power Purchase Agreement
PTC						Production Tax Credit

QIP						Qualifying Infrastructure Plant
Red Barn						Red Barn Wind Park
RICE						Reciprocating Internal Combustion Engine
RNG						Renewable Natural Gas
ROE						Return on Equity
S&P						Standard & Poor's
SIP						State Implementation Plan


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SMP						Safety Modernization Program
SOFR						Secured Overnight Financing Rate


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
WPL						Wisconsin Power and Light Company
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 2023 Annual Report on Form 10-K, and those identified below:

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

•Factors affecting the demand for electricity and natural gas, including political or regulatory developments, varying, adverse, or unusually severe weather conditions, including those caused by climate change, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

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

•The impact of federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, the results of recent or upcoming rate orders, 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 focus 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, including from sanctions, and impacts on supply chains and fuel prices, generally, from ongoing, expanding, or escalating regional conflicts, including those in Ukraine, Israel, and other parts of the Middle East;

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

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

•The direct or indirect effect on our business resulting from terrorist or other physical attacks and cybersecurity 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, changes in demand based on lower prices for alternative energy sources, the ability to replace expiring PPAs under acceptable terms, risks of rights related to property on which our projects are located but we do not own, 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, or portions thereof, 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
	March 31
(in millions, except per share amounts)		2024		2023
Operating revenues		$	2,680.2	$	2,888.1

Operating expenses
Cost of sales		927.1		1,309.7
Other operation and maintenance		530.8		534.0
Depreciation and amortization		333.4		305.5
Property and revenue taxes		75.5		69.6
Total operating expenses		1,866.8		2,218.8

Operating income		813.4		669.3

Equity in earnings of transmission affiliates		44.8		43.8
Other income, net		44.1		40.8
Interest expense		192.0		172.2
Other expense		(103.1)		(87.6)

Income before income taxes		710.3		581.7
Income tax expense		87.7		74.1
Net income		622.6		507.6

Preferred stock dividends of subsidiary		0.3		0.3
Net loss attributed to noncontrolling interests		—		0.2
Net income attributed to common shareholders		$	622.3	$	507.5

Earnings per share
Basic		$	1.97	$	1.61
Diluted		$	1.97	$	1.61

Weighted average common shares outstanding
Basic		315.6		315.4
Diluted		315.9		315.9

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
	March 31
(in millions)		2024		2023
Net income		$	622.6	$	507.6

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

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






Comprehensive income		622.5		507.5

Preferred stock dividends of subsidiary		0.3		0.3
Comprehensive loss attributed to noncontrolling interests		—		0.2
Comprehensive income attributed to common shareholders		$	622.2	$	507.4

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)	March 31, 2024		December 31, 2023
Assets
Current assets
Cash and cash equivalents	$	38.9	$	42.9
Accounts receivable and unbilled revenues, net of reserves of $190.7 and $193.5, respectively	1,557.0		1,503.2
Materials, supplies, and inventories	608.6		775.2
Prepaid taxes	143.0		173.9
Other prepayments	70.9		76.8

Other	186.2		223.7
Current assets	2,604.6		2,795.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,275.0 and $11,073.1, respectively	31,729.8		31,581.5
Regulatory assets (March 31, 2024 and December 31, 2023 include $84.1 and $85.9, respectively, related to WEPCo Environmental Trust)	3,247.0		3,249.8
Equity investment in transmission affiliates	2,027.1		2,005.9
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	883.9		870.9
Other	382.0		383.1
Long-term assets	41,322.6		41,144.0
Total assets	$	43,927.2	$	43,939.7

Liabilities and Equity
Current liabilities
Short-term debt	$	2,574.2	$	2,020.9
Current portion of long-term debt (March 31, 2024 and December 31, 2023 include $9.0, related to WEPCo Environmental Trust)	640.5		1,264.2
Accounts payable	640.9		896.6
Other	854.1		933.1
Current liabilities	4,709.7		5,114.8

Long-term liabilities
Long-term debt (March 31, 2024 and December 31, 2023 include $85.4 and $85.3, respectively, related to WEPCo Environmental Trust)	15,375.8		15,512.8
Deferred income taxes	5,120.0		4,918.5
Deferred revenue, net	351.1		356.4
Regulatory liabilities	3,730.2		3,697.7
Intangible liabilities	581.4		594.8
Environmental remediation liabilities	448.9		463.7
AROs	377.7		374.2
Other	806.3		835.3
Long-term liabilities	26,791.4		26,753.4

Commitments and contingencies (Note 20)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,822,587 and 315,434,531 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,145.7		4,115.9
Retained earnings	7,971.6		7,612.8
Accumulated other comprehensive loss	(7.8)		(7.7)
Common shareholders' equity	12,112.7		11,724.2

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	283.0		316.9
Total liabilities and equity	$	43,927.2	$	43,939.7

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2024		2023
Operating activities
Net income	$	622.6	$	507.6
Reconciliation to cash provided by operating activities
Depreciation and amortization	333.4		305.5
Deferred income taxes and ITCs, net	184.3		56.5
Contributions and payments related to pension and OPEB plans	(4.0)		(5.5)
Equity income in transmission affiliates, net of distributions	(9.1)		(6.4)
Change in –
Accounts receivable and unbilled revenues, net	(61.3)		60.7
Materials, supplies, and inventories	166.6		293.6
Collateral on deposit	17.2		(91.8)
Other current assets	19.7		89.4
Accounts payable	(229.8)		(424.7)
Other current liabilities	(44.8)		63.7
Other, net	(131.2)		(52.5)
Net cash provided by operating activities	863.6		796.1

Investing activities
Capital expenditures	(444.5)		(499.4)
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)
Capital contributions to transmission affiliates	(12.1)		(6.1)
Proceeds from the sale of investments held in rabbi trust	14.8		10.4
Other, net	5.6		(4.8)
Net cash used in investing activities	(436.2)		(1,267.9)

Financing activities
Exercise of stock options	3.7		0.9
Issuance of common stock	19.2		—
Purchase of common stock	(2.0)		(6.9)
Dividends paid on common stock	(263.5)		(246.1)
Issuance of long-term debt	—		1,100.0
Retirement of long-term debt	(756.9)		(35.2)
Change in commercial paper	552.8		(385.4)
Purchase of additional ownership interest in Samson I from noncontrolling interest	(28.1)		—
Other, net	(1.7)		(9.7)
Net cash provided by (used in) financing activities	(476.5)		417.6

Net change in cash, cash equivalents, and restricted cash	(49.1)		(54.2)
Cash, cash equivalents, and restricted cash at beginning of period	165.2		182.2
Cash, cash equivalents, and restricted cash at end of period	$	116.1	$	128.0

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, 2023	$	3.2	$	4,115.9	$	7,612.8	$	(7.7)	$	11,724.2	$	30.4	$	316.9	$	12,071.5
Net income attributed to common shareholders	—		—		622.3		—		622.3		—		—		622.3

Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Issuance of common stock	—		19.2		—		—		19.2		—		—		19.2
Common stock dividends of $0.8350 per share	—		—		(263.5)		—		(263.5)		—		—		(263.5)
Exercise of stock options	—		3.7		—		—		3.7		—		—		3.7
Purchase of common stock	—		(2.0)		—		—		(2.0)		—		—		(2.0)
Purchase of additional ownership interest in Samson I from noncontrolling interest	—		4.3		—		—		4.3		—		(32.4)		(28.1)

Distributions to noncontrolling interests	—		—		—		—		—		—		(1.5)		(1.5)
Stock-based compensation and other	—		4.6		—		—		4.6		—		—		4.6
Balance at March 31, 2024	$	3.2	$	4,145.7	$	7,971.6	$	(7.8)	$	12,112.7	$	30.4	$	283.0	$	12,426.1



	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

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)

March 31, 2024

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 17, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2023. 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 months ended March 31, 2024, are not necessarily indicative of expected results for 2024 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 16, Goodwill and Intangibles, for more information.

Acquisitions of Solar Generation Facilities in Texas

In March 2024, WECI signed an agreement to acquire a 90% ownership interest in Delilah I, a 300 MW solar generating facility under construction in Lamar County, Texas, for approximately $459.0 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of the second quarter of 2024, at which time the transaction is expected to close. Delilah I is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

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. Samson I was acquired for $257.3 million, which included payments related to contingent consideration, transaction costs, and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation, May 2022. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment. In January 2024, WECI acquired an additional 10% ownership interest in Samson I for $28.1 million.


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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, in October 2023, WPS filed for approval to assign its ownership interest pursuant to this second option to WE. The PSCW approved both requests in February 2024. WE's incremental share of this investment is expected to be approximately $100 million, with the transaction expected to close in June 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.

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.

Acquisitions of Electric Generation Facilities in Illinois

In February 2023, upon achievement of commercial operation, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a 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 project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. 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 from the date of commercial operation. The transaction is subject to FERC approval and commercial operation is expected to begin during the fourth quarter of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.


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NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2023 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 March 31, 2024
Electric	$	1,185.3	$	—	$	—	$	1,185.3	$	—	$	—	$	—		$	1,185.3
Natural gas	586.0		603.8		173.6		1,363.4		14.5		—		(14.2)			1,363.7
Total regulated revenues	1,771.3		603.8		173.6		2,548.7		14.5		—		(14.2)			2,549.0
Other non-utility revenues	—		—		5.0		5.0		52.1		—		(1.6)			55.5
Total revenues from contracts with customers	1,771.3		603.8		178.6		2,553.7		66.6		—		(15.8)			2,604.5
Other operating revenues	7.5		62.2		6.0		75.7		104.3		—		(104.3)		(1)	75.7
Total operating revenues	$	1,778.8	$	666.0	$	184.6	$	2,629.4	$	170.9	$	—	$	(120.1)		$	2,680.2


(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 March 31, 2023
Electric	$	1,203.8	$	—	$	—	$	1,203.8	$	—	$	—	$	—		$	1,203.8
Natural gas	784.4		577.7		245.0		1,607.1		21.3		—		(21.1)			1,607.3
Total regulated revenues	1,988.2		577.7		245.0		2,810.9		21.3		—		(21.1)			2,811.1
Other non-utility revenues	—		—		5.2		5.2		43.5		—		(1.6)			47.1
Total revenues from contracts with customers	1,988.2		577.7		250.2		2,816.1		64.8		—		(22.7)			2,858.2
Other operating revenues	8.1		22.0		(0.2)		29.9		101.4		—		(101.4)		(1)	29.9
Total operating revenues	$	1,996.3	$	599.7	$	250.0	$	2,846.0	$	166.2	$	—	$	(124.1)		$	2,888.1

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


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Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2024		2023
Residential	$	483.2	$	486.5
Small commercial and industrial	391.7		393.6
Large commercial and industrial	217.6		229.8
Other	7.9		8.0
Total retail revenues	1,100.4		1,117.9
Wholesale	25.6		34.2
Resale	45.1		40.6
Steam	10.2		11.0
Other utility revenues	4.0		0.1
Total electric utility operating revenues	$	1,185.3	$	1,203.8

Natural Gas Utility Operating Revenues

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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2024
Residential	$	397.6	$	375.0	$	111.4	$	884.0
Commercial and industrial	191.8		107.0		54.0		352.8
Total retail revenues	589.4		482.0		165.4		1,236.8
Transportation	29.8		90.1		11.6		131.5
Other utility revenues (1)	(33.2)		31.7		(3.4)		(4.9)
Total natural gas utility operating revenues	$	586.0	$	603.8	$	173.6	$	1,363.4


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2023
Residential	$	554.8	$	368.9	$	164.5	$	1,088.2
Commercial and industrial	295.2		117.9		91.5		504.6
Total retail revenues	850.0		486.8		256.0		1,592.8
Transportation	28.9		90.1		10.9		129.9
Other utility revenues (1)	(94.5)		31.7		(21.9)		(84.7)
Total natural gas utility operating revenues	$	784.4	$	608.6	$	245.0	$	1,638.0

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


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Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)	2024		2023
Wind generation revenues	$	44.5	$	36.0
We Power revenues (1)	6.0		5.9
Appliance service revenues	5.0		5.2


Total other non-utility operating revenues	$	55.5	$	47.1

(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. 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 March 31
(in millions)	2024		2023
Alternative revenues (1)	$	60.5	$	11.8
Late payment charges	14.6		17.2
Other	0.6		0.9
Total other operating revenues	$	75.7	$	29.9

(1)Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

NOTE 4—CREDIT LOSSES

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

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment related to the sale of electricity from our majority-owned 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


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

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at March 31, 2024 and December 31, 2023, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
March 31, 2024
Accounts receivable and unbilled revenues	$	1,100.6		$	516.7		$	90.9		$	1,708.2		$	33.0		$	6.5		$	1,747.7
Allowance for credit losses	83.0			104.6			3.1			190.7			—			—			190.7
Accounts receivable and unbilled revenues, net (1)	$	1,017.6		$	412.1		$	87.8		$	1,517.5		$	33.0		$	6.5		$	1,557.0

Total accounts receivable, net – past due greater than 90 days (1)	$	68.2		$	45.7		$	1.3		$	115.2		$	—		$	—		$	115.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	95.0		%	100.0		%	—		%	95.9		%	—		%	—		%	95.9		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2023
Accounts receivable and unbilled revenues	$	1,078.0		$	481.5		$	94.9		$	1,654.4		$	33.9		$	8.4		$	1,696.7
Allowance for credit losses	77.4			109.7			6.4			193.5			—			—			193.5
Accounts receivable and unbilled revenues, net (1)	$	1,000.6		$	371.8		$	88.5		$	1,460.9		$	33.9		$	8.4		$	1,503.2

Total accounts receivable, net – past due greater than 90 days (1)	$	51.7		$	45.0		$	2.1		$	98.8		$	—		$	—		$	98.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.6		%	100.0		%	—		%	94.5		%	—		%	—		%	94.5		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at March 31, 2024, $1,000.4 million, or 64.3%, 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 March 31, 2024 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2024	$	77.4	$	109.7	$	6.4	$	193.5
Provision for credit losses	13.8		15.1		(3.0)		25.9
Provision for credit losses deferred for future recovery or refund	15.7		1.3		—		17.0
Write-offs charged against the allowance	(35.6)		(28.0)		(1.3)		(64.9)
Recoveries of amounts previously written off	11.7		6.5		1.0		19.2
Balance at March 31, 2024	$	83.0	$	104.6	$	3.1	$	190.7

On a consolidated basis, there was a $2.8 million decrease in the allowance for credit losses at March 31, 2024, compared to January 1, 2024, driven by lower required reserve percentages at our Illinois and Other States segments as a result of an improvement in loss rates. Reserve percentages at our Wisconsin segment did not change significantly from those calculated in 2023. Largely offsetting the decrease in the allowance for credit losses, we saw an increase in past due accounts receivable balances at our Wisconsin and Illinois segments. An increase in past due balances is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31.


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Three Months Ended March 31, 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	11.2		8.5		1.3		21.0
Provision for credit losses deferred for future recovery or refund	20.4		15.2		—		35.6
Write-offs charged against the allowance	(28.9)		(23.0)		(1.6)		(53.5)
Recoveries of amounts previously written off	6.2		4.8		0.4		11.4
Balance at March 31, 2023	$	90.9	$	116.5	$	6.4	$	213.8

On a consolidated basis, there was a $14.5 million increase in the allowance for credit losses at March 31, 2023, compared to January 1, 2023, driven by an increase in past due accounts receivable balances at our Wisconsin and Illinois reportable segments. As discussed above, an increase in past due balances is a trend we generally see over the winter moratorium months.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2024 and December 31, 2023. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2023 Annual Report on Form 10-K.


(in millions)	March 31, 2024		December 31, 2023
Regulatory assets
Pension and OPEB costs	$	728.9	$	731.7
Plant retirement related items	637.8		646.2
Environmental remediation costs	583.8		596.8
Income tax related items	444.5		449.9
AROs	159.8		162.0
Uncollectible expense	133.7		127.7
System support resource	110.6		113.2
Derivatives	88.7		130.3
Decoupling	87.2		27.3
Securitization	84.1		85.9
Bluewater	51.1		45.3
Energy efficiency programs	29.3		33.9
Other, net	147.4		124.5
Total regulatory assets	$	3,286.9	$	3,274.7

Balance sheet presentation
Other current assets	$	39.9	$	24.9
Regulatory assets	3,247.0		3,249.8
Total regulatory assets	$	3,286.9	$	3,274.7


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(in millions)	March 31, 2024		December 31, 2023
Regulatory liabilities
Income tax related items	$	1,862.6	$	1,901.8
Removal costs	1,365.4		1,329.9
Pension and OPEB benefits	300.0		299.2
Energy costs refundable through rate adjustments	119.3		72.4
Electric transmission costs	31.0		30.3
Energy efficiency programs	20.6		17.2
Uncollectible expense	19.0		21.2
Derivatives	15.2		19.2
Other, net	76.3		54.0
Total regulatory liabilities	$	3,809.4	$	3,745.2

Balance sheet presentation
Other current liabilities	$	79.2	$	47.5
Regulatory liabilities	3,730.2		3,697.7
Total regulatory liabilities	$	3,809.4	$	3,745.2

NOTE 6—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. Subsequently, we have received additional approvals for electric generation facilities, including Koshkonong and 200 MWs of West Riverside. See Note 2, Acquisitions, for more information on the West Riverside acquisition and the two option exercises. OCPP Units 5 and 6 are expected to be retired by the end of 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 $760.0 million at March 31, 2024, 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 $255.2 million at March 31, 2024, 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 wind storms in March and June 2023, certain sections of our Samson I solar facility incurred damage. As of March 31, 2024, we recognized an impairment of $2.3 million related to storm damage, which was offset by a $2.3 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 these events.


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NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the three months ended March 31, 2024, 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)						283,869
Restricted shares (2)						105,778
Performance units						196,256

(1)Stock options awarded had a weighted-average exercise price of $85.05 and a weighted-average grant date fair value of $16.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $85.05 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 2023 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

As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans. As such, no new shares of common stock were issued during the three months ended March 31, 2023.

We had the following changes to our outstanding common stock during the three months ended March 31, 2024:


Common stock shares outstanding at beginning of period						315,434,531
Shares issued:
Stock-based compensation						142,178
401(k)						124,300
Stock investment plan						121,578
Common stock shares outstanding at end of period						315,822,587

On April 18, 2024, our Board of Directors declared a quarterly cash dividend of $0.835 per share, payable on June 1, 2024, to shareholders of record on May 14, 2024.


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NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

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


(in millions, except percentages)	March 31, 2024			December 31, 2023
Commercial paper
Amount outstanding	$	2,570.0		$	2,017.2
Weighted-average interest rate on amounts outstanding	5.50		%	5.49		%
Operating expense loans
Amount outstanding (1)	$	4.2		$	3.7

(1)Coyote Ridge Wind, LLC, Tatanka Ridge, and Jayhawk have 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 three months ended March 31, 2024 was $2,014.4 million with a weighted-average interest rate during the period of 5.48%.

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	March 31, 2024
WEC Energy Group	September 2026	$	1,500.0
WEC Energy Group	October 2024	200.0
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		$	3,300.0

Less:
Letters of credit issued inside credit facilities		$	2.3
Commercial paper outstanding		2,570.0
Available capacity under existing agreements		$	727.7

NOTE 9—LONG-TERM DEBT

WEC Energy Group, Inc.

In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes for $115.2 million with proceeds from issuing commercial paper. We recorded a $6.9 million gain related to the early settlement.

In March 2024, our $600.0 million of 0.80% Senior Notes, due March 15, 2024, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	March 31, 2024		December 31, 2023
Materials and supplies	$	330.5	$	320.0
Natural gas in storage	160.0		327.8
Fossil fuel	118.1		127.4
Total	$	608.6	$	775.2


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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 March 31, 2024, we had a temporary LIFO liquidation debit of $4.3 million recorded within other current assets on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 11—INCOME TAXES

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














	Three Months Ended March 31, 2024				Three Months Ended March 31, 2023
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	149.1	21.0	%	$	122.1	21.0	%
State income taxes net of federal tax benefit	43.4		6.1	%	35.8		6.2	%
PTCs, net	(88.0)		(12.4)	%	(66.2)		(11.4)	%
Federal excess deferred tax amortization	(15.4)		(2.2)	%	(13.1)		(2.3)	%



Other, net	(1.4)		(0.2)	%	(4.5)		(0.8)	%
Total income tax expense	$	87.7	12.3	%	$	74.1	12.7	%

The effective tax rates for the three months ended March 31, 2024 and 2023, 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 line above). See Note 26, Regulatory Environment, in our 2023 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 the PTCs we generated in 2023 to a third party. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We 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 is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

NOTE 12—FAIR VALUE MEASUREMENTS

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


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

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

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

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

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

When possible, we base the valuations of our 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:


	March 31, 2024
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.5	$	2.9	$	—	$	4.4
FTRs and TCRs	—		—		2.6		2.6
Coal contracts	—		0.2		—		0.2
Total derivative assets	$	1.5	$	3.1	$	2.6	$	7.2

Investments held in rabbi trust	$	41.3	$	—	$	—	$	41.3

Derivative liabilities
Natural gas contracts	$	51.4	$	1.2	$	—	$	52.6
Coal contracts	—		18.0		—		18.0
Total derivative liabilities	$	51.4	$	19.2	$	—	$	70.6


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	December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.2	$	8.3	$	—	$	10.5
FTRs and TCRs	—		—		7.2		7.2
Coal contracts	—		0.3		—		0.3
Total derivative assets	$	2.2	$	8.6	$	7.2	$	18.0

Investments held in rabbi trust	$	51.7	$	—	$	—	$	51.7

Derivative liabilities
Natural gas contracts	$	70.1	$	16.0	$	—	$	86.1
Coal contracts	—		20.3		—		20.3
Total derivative liabilities	$	70.1	$	36.3	$	—	$	106.4

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 Southwest Power Pool Integrated Marketplace, respectively.

We hold investments in the Integrys rabbi trust. These investments are used 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 March 31, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $3.7 million and $2.8 million, respectively.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:


	Three Months Ended March 31
(in millions)		2024		2023
Balance at the beginning of the period		$	7.2	$	7.8
Purchases		1.0		0.3
Realized and unrealized net losses included in earnings (1)		(0.8)		(0.3)
Settlements		(4.8)		(4.8)
Balance at the end of the period		$	2.6	$	3.0
Unrealized net gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)		$	0.1	$	(0.1)

(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:


	March 31, 2024				December 31, 2023
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	20.3	$	30.4	$	21.4
Long-term debt, including current portion (1)	15,871.6		14,669.6		16,631.1		15,564.3

(1)The carrying amount of long-term debt excludes finance lease obligations of $144.7 million and $145.9 million at March 31, 2024 and December 31, 2023, 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 13—DERIVATIVE INSTRUMENTS

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

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.


	March 31, 2024				December 31, 2023
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	4.1	$	49.5	$	10.4	$	78.1
FTRs and TCRs	2.6		—		7.2		—
Coal contracts	0.2		10.9		0.3		10.9
Total current	6.9		60.4		17.9		89.0

Long-term
Natural gas contracts	0.3		3.1		0.1		8.0
Coal contracts	—		7.1		—		9.4
Total long-term	0.3		10.2		0.1		17.4
Total	$	7.2	$	70.6	$	18.0	$	106.4

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 March 31, 2024			Three Months Ended March 31, 2023
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	67.8 Dth	$	(56.9)	58.7 Dth	$	(75.3)
FTRs and TCRs	7.6 MWh	1.6		7.3 MWh	0.4
Total		$	(55.3)		$	(74.9)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2024 and December 31, 2023, we had posted cash collateral of $83.1 million and $100.3 million, respectively. These amounts were recorded on our balance sheets in other current assets.


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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:


	March 31, 2024					December 31, 2023
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	7.2	$	70.6		$	18.0	$	106.4
Gross amount not offset on the balance sheet	(1.8)		(51.7)		(1)	(3.1)		(71.0)		(2)
Net amount	$	5.4	$	18.9		$	14.9	$	35.4

(1)Includes cash collateral posted of $49.9 million.

(2)Includes cash collateral posted of $67.9 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 months ended March 31, 2024 and 2023 were not significant. At March 31, 2024, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 14—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at March 31, 2024		Expiration

(in millions)			Less Than 1 Year		1 to 3 Years		Over 3 Years
Standby letters of credit (1)	$	117.3	$	20.7	$	—	$	96.6
Surety bonds (2)	33.7		32.6		1.1		—
Other guarantees (3)	10.5		—		—		10.5
Total guarantees	$	161.5	$	53.3	$	1.1	$	107.1

(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 15—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 March 31
(in millions)			2024		2023
Service cost			$	6.7	$	6.6
Interest cost			29.5		30.8
Expected return on plan assets			(45.8)		(47.4)

Amortization of prior service cost			—		0.1
Amortization of net actuarial loss			14.4		7.4
Net periodic benefit cost (credit)			$	4.8	$	(2.5)


		OPEB Benefits
	Three Months Ended March 31
(in millions)			2024		2023
Service cost			$	2.8	$	2.5
Interest cost			5.7		5.4
Expected return on plan assets			(13.2)		(13.3)

Amortization of prior service credit			(3.4)		(3.7)
Amortization of net actuarial gain			(1.9)		(3.2)
Net periodic benefit credit			$	(10.0)	$	(12.3)

During the three months ended March 31, 2024, we made contributions and payments of $3.7 million related to our pension plans and $0.3 million related to our OPEB plans. We expect to make contributions and payments of $9.5 million related to our pension plans and $1.9 million related to our OPEB plans during the remainder of 2024, 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 March 31, 2024, we recorded a $10.8 million regulatory asset for pension costs and a $20.7 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

NOTE 16—GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at March 31, 2024. We had no changes to the carrying amount of goodwill during the three months ended March 31, 2024.


(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 March 31, 2024.

Intangible Assets

At both March 31, 2024 and December 31, 2023, we had $29.3 million of indefinite-lived intangible assets, largely consisting of spectrum frequencies. 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.


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Intangible Liabilities

The intangible liabilities below were all obtained through acquisitions by WECI.


	March 31, 2024						December 31, 2023
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	653.9	$	(79.8)	$	574.1	$	653.9	$	(66.6)	$	587.3
Proxy revenue swap (2)	7.2		(3.6)		3.6		7.2		(3.5)		3.7
Interconnection agreements (3)	4.7		(1.0)		3.7		4.7		(0.9)		3.8
Total intangible liabilities	$	665.8	$	(84.4)	$	581.4	$	665.8	$	(71.0)	$	594.8

(1) Represents PPAs related to the acquisition of Blooming Grove Wind Energy Center LLC , Tatanka Ridge, Jayhawk, Thunderhead Wind Energy LLC, Samson I, and Sapphire Sky expiring between 2030 and 2037. The weighted-average remaining useful life of the PPAs is 11 years.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream Wind Energy LLC'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 months ended March 31, 2024 and 2023, was $13.4 million and $10.4 million, respectively. Amortization for the next five years, including amounts recorded through March 31, 2024, is estimated to be:


	For the Years Ending December 31
(in millions)	2024		2025		2026		2027		2028
Amortization to be recorded as an increase to operating revenues	$	53.4	$	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

NOTE 17—INVESTMENT IN TRANSMISSION AFFILIATES

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


	Three Months Ended March 31, 2024




















(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,980.8	$	25.1	$	2,005.9
Add: Earnings from equity method investment	44.4		0.4		44.8
Add: Capital contributions	12.1		—		12.1
Less: Distributions	35.7		—		35.7

Balance at end of period	$	2,001.6	$	25.5	$	2,027.1

	Three Months Ended March 31, 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	42.9		0.9		43.8
Add: Capital contributions	6.1		—		6.1
Less: Distributions	37.4		—		37.4


Balance at end of period	$	1,896.2	$	25.5	$	1,921.7

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


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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 March 31
(in millions)		2024		2023
Charges to ATC for services and construction		$	4.7	$	3.8
Charges from ATC for network transmission services		103.3		94.5

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


(in millions)	March 31, 2024		December 31, 2023
Accounts receivable for services provided to ATC	$	1.8	$	1.6

Accounts payable for services received from ATC	49.7		49.9
Amounts due from ATC for transmission infrastructure upgrades (1)	42.1		46.1

(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 March 31
(in millions)		2024		2023
Income statement data
Operating revenues		$	211.9	$	200.4
Operating expenses		104.8		99.1
Other expense, net		35.2		32.5
Net income		$	71.9	$	68.8


(in millions)	March 31, 2024		December 31, 2023
Balance sheet data
Current assets	$	133.2	$	115.2
Noncurrent assets	6,423.4		6,337.0
Total assets	$	6,556.6	$	6,452.2

Current liabilities	$	587.9	$	495.9
Long-term debt	2,736.3		2,736.0
Other noncurrent liabilities	562.2		585.2
Members' equity	2,670.2		2,635.1
Total liabilities and members' equity	$	6,556.6	$	6,452.2

NOTE 18—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At March 31, 2024, 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 operations of MERC and MGU and the non-utility operations of MERC.

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


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•The non-utility energy infrastructure segment includes:

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

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

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

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

•The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, 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 months ended March 31, 2024 and 2023:


	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 March 31, 2024
External revenues	$	1,778.8	$	666.0	$	184.6	$	2,629.4	$	—	$	50.8	$	—	$	—	$	2,680.2
Intersegment revenues	—		—		—		—		—		120.1		—		(120.1)		—
Other operation and maintenance	389.9		107.0		20.6		517.5		—		18.2		(3.4)		(1.5)		530.8
Depreciation and amortization	224.6		63.5		11.4		299.5		—		49.1		5.6		(20.8)		333.4
Equity in earnings of transmission affiliates	—		—		—		—		44.8		—		—		—		44.8
Interest expense	157.8		25.0		4.0		186.8		4.8		24.1		66.6		(90.3)		192.0
Income tax expense (benefit)	74.9		72.1		13.0		160.0		9.9		(23.4)		(58.8)		—		87.7
Net income	266.7		187.5		38.6		492.8		30.1		94.3		5.4		—		622.6
Net income attributed to common shareholders	266.4		187.5		38.6		492.5		30.1		94.3		5.4		—		622.3


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	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
Three Months Ended March 31, 2023
External revenues	$	1,996.3	$	599.7	$	250.0	$	2,846.0	$	—	$	42.1	$	—	$	—	$	2,888.1
Intersegment revenues	—		—		—		—		—		124.1		—		(124.1)		—
Other operation and maintenance	380.8		113.7		24.7		519.2		—		17.8		(1.4)		(1.6)		534.0
Depreciation and amortization	207.3		58.5		10.4		276.2		—		42.7		5.1		(18.5)		305.5
Equity in earnings of transmission affiliates	—		—		—		—		43.8		—		—		—		43.8
Interest expense	150.6		21.6		4.2		176.4		4.8		19.9		55.6		(84.5)		172.2
Income tax expense (benefit)	65.9		42.0		11.2		119.1		9.7		(17.8)		(36.9)		—		74.1
Net income (loss)	257.5		113.1		33.2		403.8		29.3		88.3		(13.8)		—		507.6
Net income (loss) attributed to common shareholders	257.2		113.1		33.2		403.5		29.3		88.5		(13.8)		—		507.5

NOTE 19—VARIABLE INTEREST ENTITIES

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

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

WEPCo Environmental Trust Finance I, LLC

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

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole 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.


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

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheets:


(in millions)	March 31, 2024		December 31, 2023
Assets
Other current assets (restricted cash)	$	3.2	$	0.8
Regulatory assets	84.1		85.9
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.0		9.0
Accounts payable	0.1		—
Other current liabilities (accrued interest)	0.5		0.1
Long-term debt	85.4		85.3

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 March 31, 2024 and December 31, 2023, our equity investment in ATC was $2,001.6 million and $1,980.8 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 March 31, 2024 and December 31, 2023, our equity investment in ATC Holdco was $25.5 million and $25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

NOTE 20—COMMITMENTS AND CONTINGENCIES

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

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 March 31, 2024, including those of our subsidiaries, were approximately $9.5 billion.


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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 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.

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 operations. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations.

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 initially issued a draft Policy Assessment in March 2023 that supported the reconsideration; however, in August 2023, the EPA announced 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.

The effective date for the initial nonattainment area designation was August 2018, and the attainment status is evaluated every three years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "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.

In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit adequate SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard. This action triggered a May 2025 deadline for states to get their SIP approved or the EPA will issue a federal implementation plan. Additionally, offset sanctions will take effect in 18 months if the SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas. The WDNR intends to submit a SIP revision by the May 2025 deadline.


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The next attainment evaluation date is August 2024. If the moderate attainment deadline is not met, the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. We are currently evaluating the impacts of the potential nonattainment redesignation on our operations.

Particulate Matter

All counties within our service territories are in attainment with current 2012 standards for fine PM2.5. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard of 35 µg/m3. On February 7, 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until May 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. The potential nonattainment status could impact future permitting activities for facilities in applicable locations. The impacts include the potential need for improved or new air pollution control equipment. As we transition to natural gas, this new standard is expected to have less of an impact on our units.

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 had replaced the Clean Power Plan. For coal plants, no standards would apply under the proposed version of the rule until 2032, and after 2032 the applicable standard would depend on the unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the proposed rule is highly dependent on the use of hydrogen as an alternative fuel, and on carbon capture technology. For simple cycle natural gas-fired combustion turbines, the proposed version of the rule does not include 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. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations.

In May 2023, the EPA also 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 natural gas 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.

In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule. The EPA had indicated it intends to draft a new rule for existing natural gas units in the near future. A non-regulatory docket has been opened by the EPA for this new rulemaking. The EPA 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, LDCs, 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. The EPA has indicated it anticipates a final rule in the second quarter of 2024. We cannot estimate the potential impact of the proposed rule on our operations until the rule is final.

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. We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3. See Note 6, Property, Plant, and Equipment, for more information related to these planned power plant 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 continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.


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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 natural gas utility distribution systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

Section 316(b) of the CWA 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.

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 final or interim BTA determinations for all applicable generation facilities. 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 the third quarter of 2024.

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 requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater. Although our coal-fueled facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications were still necessary to meet all of the ELG rule requirements. Through 2023, compliance costs associated with the ELG rule required $105 million in capital investment.

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 complete and was placed in service in December 2023 to meet the WPDES permit deadline, the timing of the project's completion did not comply with the deadline proposed by the EPA to qualify for the early adopter status. In addition, we do not believe that the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations.

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 have reviewed the proposed requirements to determine potential costs and actions required for our facilities. We submitted comments to the EPA regarding these proposed requirements.


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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)	March 31, 2024		December 31, 2023
Regulatory assets	$	583.8	$	596.8
Reserves for future environmental remediation	448.9		463.7

Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site. As proposed, the rule would regulate previously exempt closed landfills.

We are actively engaged with our trade organizations and provided them information to include in their comments to the EPA. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations. The 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; however, we expect the cost of any additional remediation would be recovered through future rates.

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 continue to work with the EPA on a closeout process for the Consent Decree.


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Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, 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 WPL, MG&E, 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. WPL started the process to close out this Consent Decree.

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Three Months Ended March 31
(in millions)	2024		2023
Cash paid for interest, net of amount capitalized	$	158.6	$	107.5
Cash paid (received) for income taxes, net (1)	(83.0)		1.0
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	147.2		123.0
Common stock issued for stock-based compensation plans	6.2		—
Increase in receivables related to insurance proceeds	—		20.7

(1) Cash received for income taxes in 2024 includes $83.4 million related to 2023 PTCs that were sold to a third party.

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)	March 31, 2024		December 31, 2023
Cash and cash equivalents	$	38.9	$	42.9
Restricted cash included in other current assets	43.6		70.1
Restricted cash included in other long-term assets	33.6		52.2
Cash, cash equivalents, and restricted cash	$	116.1	$	165.2

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.

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

•Cash related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account annually in order to fund future decommissioning.


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NOTE 22—REGULATORY ENVIRONMENT

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

2025 and 2026 Rate Case

On April 12, 2024, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2025 and January 1, 2026. The requests reflected the following:


	WE					WPS					WG
Proposed 2025 rate increase
Electric	$	240.7	million	/	6.9%	$	110.1	million	/	8.5%	N/A
Gas	$	57.5	million	/	10.0%	$	26.8	million	/	6.8%	$	67.7	million	/	8.2%
Steam	$	2.5	million	/	8.4%	N/A					N/A
Proposed 2026 rate increase (1)
Electric	$	177.9	million	/	4.6%	$	64.3	million	/	4.5%	N/A
Gas	$	31.0	million	/	4.6%	$	16.1	million	/	3.7%	$	30.6	million	/	3.3%
Proposed ROE	10.0%					10.0%					10.0%
Proposed common equity component average on a financial basis	53.5%					53.5%					53.5%

(1) The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025.

The primary drivers of the requested increases in electric rates are continued capital investments to transition our generation fleets from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW.

The requested increases in natural gas rates are driven by the companies' ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.

The utilities also proposed retaining their current earnings sharing mechanism. Under the current earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

A decision is expected in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

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

2023 Rate Order

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. PGL did not request an extension of the QIP rider as PGL returned to the traditional rate making process to recover the costs of necessary infrastructure improvements.

On November 16, 2023, the ICC issued final written orders approving base rate increases for PGL and NSG. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:

•A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.

•An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.


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The ICC approved an authorized ROE of 9.38% for both PGL and NSG, and set the common equity component average at 50.79% and 52.58% for PGL and NSG, respectively.

As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. In addition, the ICC ordered PGL to pause spending on its SMP until the ICC has a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding on January 31, 2024.

On December 15, 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. On January 3, 2024, the ICC granted PGL and NSG a limited-scope rehearing. The rehearing is limited to the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system.

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment during the fourth quarter of 2023. This amount included $177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $1.7 million of capital costs disallowed at NSG. The remaining disallowance of capital costs at PGL related to expected future spend. We anticipate appealing the ICC’s disallowance of PGL's and NSG's capital costs to the Illinois Appellate Court after the rehearing process is complete.

An ICC decision on our limited-scope rehearing is expected by June 1, 2024.

Uncollectible Expense Adjustment Rider

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. In June 2023, the ICC denied PGL's and NSG's application requesting a rehearing of the ICC's May 2023 order. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders. Their appeal is still pending.

As of March 31, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2023, will be deemed recoverable by the ICC. The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million during these open reconciliation years. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

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 was in effect until December 1, 2023. As discussed above, PGL has returned to the traditional rate-making process for recovery of these costs, and they are now included in PGL's base rates.

Costs previously incurred under PGL's QIP rider are still subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2022, are still pending. Annual costs included in the rider have ranged from $192 million to $348 million during these open reconciliation years.

As of March 31, 2024, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.


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Minnesota Energy Resources Corporation

2023 Rate Order

In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates. 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.

In November 2023, the MPUC issued a written order approving 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%. The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. 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. Final rates went into effect on March 1, 2024.

MERC’s customers are entitled to a refund to the extent the interim rate increase exceeded the final approved rate increase. As of March 31, 2024, MERC had recorded a regulatory liability of $10.8 million for refunds due to customers. These amounts will be refunded to customers during the second quarter of 2024.

Michigan Gas Utilities Corporation

2024 Rate Case

On March 1, 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates by $17.6 million (9.7%). The request reflects a 10.25% ROE and a common equity component average of 50.9%. The proposed natural gas rate increase is primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates over the past few years. The proposed rate increase also includes the expected impacts of the Pipeline and Hazardous Materials Safety Administration's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."

An MPSC decision is anticipated in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

Upper Michigan Energy Resources Corporation

2024 Rate Case

On May 1, 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers by $11.2 million (13.8%). The request reflects a 10.25% ROE and a common equity component average of 50.0%. The proposed rate increase is primarily driven by the construction of the now in-service RICE generation facilities and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates. A reduction of operation and maintenance costs partially offset these impacts.

An MPSC decision is anticipated in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to


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adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.


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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our 2023 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 ATC (a for-profit electric transmission company regulated by FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin that it leases to WE), Bluewater (which owns underground natural gas storage facilities in Michigan), and 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. The retirements will contribute to meeting our goals to reduce CO2 emissions from our electric generation. When taken together, the retirements and new investments in renewables and clean generation should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers.

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 continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

As part of our path toward these goals, we have started implementing co-firing with natural gas at the ERGS coal-fired units and plan to co-fire with natural gas at Weston Unit 4. 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. We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3. See Note 6, Property, Plant, and Equipment, for more information related to planned power plant retirements.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $7.0 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

•250 MWs of battery storage.


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We also plan on investing in a combination of clean, natural gas-fired generation, to be owned by WE, including:

•1,100 MWs of combustion turbines to be constructed in Oak Creek (we plan on constructing a new natural gas lateral pipeline to support this generation);

•128 MWs of RICE natural gas-fueled generation to be constructed in Kenosha County; and

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

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

In December 2018, WE received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 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 28 Solar Now projects and currently has another two under construction, together totaling more than 30 MWs. The second program, the DRER pilot, is designed to allow large commercial and industrial customers to access renewable resources that WE would operate. The DRER pilot is intended to help these larger customers meet their sustainability and renewable energy goals, and could add up to 35 MWs of renewables to WE's portfolio. In July 2023, the PSCW approved the Renewable Pathway Pilot, the third renewable energy program. This program allows WE and WPS commercial and industrial customers to subscribe to a portion of a utility-scale, Wisconsin-based renewable energy generating facility for up to 125 MWs at WE and 40 MWs at WPS. Under this program, WE has signed up three customers for a total of 41 MWs of generation capacity.

In August 2021, the PSCW approved pilot programs for WE and WPS to install and maintain 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 RNG throughout our natural gas utility systems. In 2022, we received approval from the PSCW for our RNG pilots. We have since signed contracts for 1.8 Bcf of RNG for our natural gas distribution business in Wisconsin, 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. RNG began flowing in 2023.

In December 2023, we started a pilot program with Electric Power Research Institute 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 at our Valley Power Plant. 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. We expect the full pilot to be completed in 2024.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with our ESG Progress Plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.

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

•WE and WG have completed the construction of their respective LNG facilities. Each facility provides approximately one Bcf of natural gas supply to meet anticipated peak demand, without requiring the construction of additional interstate pipeline capacity. The WE LNG facility was commercially operational in November 2023 and the WG LNG facility was commercially operational in February 2024.

•Included in the capital plan are additional proposed LNG storage facilities providing approximately four Bcf of natural gas supply, which is needed to ensure gas supply for winter reliability.


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•Through the SMP, PGL had been working to replace 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. In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months. For more information, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Future Illinois Proceedings.

On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which is limited to the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system. See Note 22, Regulatory Environment, for more information.

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

We expect to spend approximately $3.8 billion from 2024 to 2028 on reliability related projects with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the ESG Progress Plan. For example, we are making progress on our AMI 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.

Our planned investment focus from 2024 to 2028 is in our regulated utilities and non-utility energy infrastructure business, as well as our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $19.5 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 $1.2 billion in our non-utility energy infrastructure business over the same period, which includes our signed agreements to acquire the Delilah I and Maple Flats solar generating facilities. Specific projects included in the $23.7 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 MARCH 31, 2024

Consolidated Earnings

The following table compares our consolidated results for the first quarter of 2024 with the first quarter of 2023, including favorable or better, "B", and unfavorable or worse, "W", variances:


	Three Months Ended March 31
(in millions, except per share data)	2024		2023		B (W)
Wisconsin	$	266.4	$	257.2	$	9.2
Illinois	187.5		113.1		74.4
Other states	38.6		33.2		5.4
Electric transmission	30.1		29.3		0.8
Non-utility energy infrastructure	94.3		88.5		5.8
Corporate and other	5.4		(13.8)		19.2
Net income attributed to common shareholders	$	622.3	$	507.5	$	114.8

Diluted earnings per share	$	1.97	$	1.61	$	0.36

Earnings increased $114.8 million during the first quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the $114.8 million increase in earnings were:

•A $74.4 million increase in net income attributed to common shareholders at the Illinois segment, driven by an increase in natural gas margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are concentrated in the winter months when natural gas usage is highest, this rate design change drove a large increase in the first quarter 2024 margins. See Note 22, Regulatory Environment, for more information on the rate orders. This positive impact was partially offset by higher operating expenses, driven by increases in property and revenue taxes and depreciation and amortization expense.

•A $19.2 million increase in earnings at the corporate and other segment, driven by a positive impact of an interim tax benefit and an increase in earnings from our equity method investments in technology and energy-focused investment funds. These increases were partially offset by higher interest expense.

•A $9.2 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 a positive quarter-over-quarter impact from collections of fuel and purchased power costs and the impact of the Wisconsin rate case re-opener approved by the PSCW, effective January 1, 2024. These positive impacts were partially offset by a decrease in margins from lower sales volumes due to warmer winter weather, higher depreciation and amortization expense, higher costs for storm restoration, and an increase in interest expense.


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Expected 2024 Annual Effective Tax Rate

We expect our 2024 annual effective tax rate to be between 11.5% and 12.5%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

Non-GAAP Financial Measures

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 by segment for our utility operations during the first quarter of 2024 and 2023:


	Three Months Ended March 31
(in millions)	2024		2023
Wisconsin	$	466.0	$	441.8
Illinois	282.7		175.4
Other states	55.6		48.3

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.


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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 $266.4 million during the first quarter of 2024, representing a $9.2 million, or 3.6%, increase over the same quarter in 2023. The higher earnings were driven by an increase in electric and natural gas margins related to a positive quarter-over-quarter impact from collections of fuel and purchased power costs and the impact of the Wisconsin rate case re-opener approved by the PSCW, effective January 1, 2024. These positive impacts were partially offset by a decrease in margins from lower sales volumes due to warmer winter weather, higher depreciation and amortization expense, higher costs for storm restoration, and an increase in interest expense.


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Electric revenues	$	1,190.6	$	1,208.9	$	(18.3)
Fuel and purchased power	349.2		411.7		62.5
Total electric margins	841.4		797.2		44.2

Natural gas revenues	588.2		787.4		(199.2)
Cost of natural gas sold	301.8		508.6		206.8
Total natural gas margins	286.4		278.8		7.6

Total electric and natural gas margins	1,127.8		1,076.0		51.8

Other operation and maintenance	389.9		380.8		(9.1)
Depreciation and amortization	224.6		207.3		(17.3)
Property and revenue taxes	47.3		46.1		(1.2)
Operating income	466.0		441.8		24.2

Other income, net	33.4		32.2		1.2
Interest expense	157.8		150.6		(7.2)
Income before income taxes	341.6		323.4		18.2

Income tax expense	74.9		65.9		(9.0)
Preferred stock dividends of subsidiary	0.3		0.3		—
Net income attributed to common shareholders	$	266.4	$	257.2	$	9.2

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


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Operation and maintenance not included in line items below	165.4		$	155.0	$	(10.4)
Transmission (1)	135.8		138.1		2.3
Regulatory amortizations and other pass through expenses (2)	56.0		53.1		(2.9)
We Power (3)	33.6		35.5		1.9
Earnings sharing mechanisms	(0.9)		(0.9)		—
Total other operation and maintenance	$	389.9	$	380.8	$	(9.1)

(1)Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. As a result, WE and WPS defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the first quarter of 2024 and 2023, $137.8 million and $127.3 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the first quarter of 2024 and 2023, $29.5 million and $26.6 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.


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


	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2024	2023	B (W)
Customer Class
Residential	2,649.9	2,679.4	(29.5)
Small commercial and industrial (1)	3,118.0	3,095.1	22.9
Large commercial and industrial (1)	2,883.7	2,908.3	(24.6)
Other	36.2	37.5	(1.3)
Total retail (1)	8,687.8	8,720.3	(32.5)
Wholesale	433.1	474.5	(41.4)
Resale	1,396.2	1,259.0	137.2
Total sales in MWh (1)	10,517.1	10,453.8	63.3

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


	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2024	2023	B (W)
Customer Class
Residential	460.8	493.9	(33.1)
Commercial and industrial	277.2	298.5	(21.3)
Total retail	738.0	792.4	(54.4)
Transportation	395.8	408.8	(13.0)
Total sales in therms	1,133.8	1,201.2	(67.4)


	Three Months Ended March 31
	Degree Days
Weather	2024	2023	B (W)
WE and WG (1)
Heating (3,282 Normal)	2,701	2,833	(4.7)	%


WPS (2)
Heating (3,677 Normal)	3,038	3,356	(9.5)	%


UMERC (3)
Heating (4,001 Normal)	3,403	3,638	(6.5)	%

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

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

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

Electric Revenues

Electric revenues decreased $18.3 million during the first quarter of 2024, compared with the same quarter in 2023. 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 $44.2 million during the first quarter of 2024, compared with the same quarter in 2023. The significant factor impacting the higher electric utility margins was a $39.8 million quarter-over-quarter positive


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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.

This increase in margins was partially offset by a $0.8 million decrease in margins related to lower retail sales volumes, including steam operations, driven by the impact of warmer winter weather during the first quarter of 2024, compared with the same quarter in 2023. As measured by heating degree days, the first quarter of 2024 was 4.7% and 9.5% warmer than the same quarter in 2023 in the Milwaukee area and Green Bay area, respectively.

Natural Gas Revenues

Natural gas revenues decreased $199.2 million during the first quarter of 2024, compared with the same quarter in 2023. 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 36% during the first quarter of 2024, compared with the same quarter in 2023. 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 $7.6 million during the first quarter of 2024, compared with the same quarter in 2023. The most significant factor impacting the higher natural gas utility margins was a $24.5 million increase in margins related to the impact of the Wisconsin rate case re-opener approved by the PSCW, effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K, for more information on the 2024 limited rate case re-opener. This increase in margins was partially offset by a $16.2 million decrease in margins from lower sales volumes, driven by the impact of warmer winter weather during the first quarter of 2024, compared with the same quarter in 2023.

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

Other operating expenses at the Wisconsin segment increased $27.6 million during the first quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:

•A $17.3 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

•A $7.0 million increase in electric and natural gas distribution expenses, driven by higher costs for storm restoration during the first quarter of 2024, compared with the same quarter in 2023.

•A $4.5 million increase in expense related to environmental remediation and related studies.

Interest Expense

Interest expense at the Wisconsin segment increased $7.2 million during the first quarter of 2024, compared with the same quarter in 2023, driven by higher average short-term debt balances and increased short-term debt interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment increased $9.0 million during the first quarter of 2024, compared with the same quarter in 2023. The increase in income tax expense was due to higher pre-tax income.


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Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders was $187.5 million during the first quarter of 2024, representing a $74.4 million, or 65.8%, increase over the same quarter in 2023. The higher earnings were driven by an increase in natural gas margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates. As base revenues are concentrated in the winter months when natural gas usage is highest, this rate design change drove a large increase in the first quarter 2024 margins. See Note 22, Regulatory Environment, for more information on the rate orders. This positive impact was partially offset by higher operating expenses, driven by increases in property and revenue taxes and depreciation and amortization expense.

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 March 31
(in millions)	2024		2023		B (W)
Natural gas revenues	$	666.0	$	599.7	$	66.3
Cost of natural gas sold	194.7		239.2		44.5
Total natural gas margins	471.3		360.5		110.8

Other operation and maintenance	107.0		113.7		6.7
Depreciation and amortization	63.5		58.5		(5.0)
Property and revenue taxes	18.1		12.9		(5.2)
Operating income	282.7		175.4		107.3

Other income, net	1.9		1.3		0.6
Interest expense	25.0		21.6		(3.4)
Income before income taxes	259.6		155.1		104.5

Income tax expense	72.1		42.0		(30.1)
Net income attributed to common shareholders	$	187.5	$	113.1	$	74.4

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


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Operation and maintenance not included in the line items below	$	68.1	$	70.7	$	2.6
Riders (1)	38.1		43.2		5.1
Regulatory amortizations (1)	0.8		(0.2)		(1.0)

Total other operation and maintenance	$	107.0	$	113.7	$	6.7

(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 March 31
	Therms (in millions)
Natural Gas Sales Volumes	2024	2023	B (W)
Customer Class
Residential	353.5	373.9	(20.4)
Commercial and industrial	136.5	151.1	(14.6)
Total retail	490.0	525.0	(35.0)
Transportation	291.8	306.1	(14.3)
Total sales in therms	781.8	831.1	(49.3)


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	Three Months Ended March 31
	Degree Days
Weather (1)	2024	2023	B (W)
Heating (3,097 Normal)	2,614	2,719	(3.9)	%

(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 $66.3 million during the first quarter of 2024, compared with the same quarter in 2023. 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 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 $5.1 million impact of the riders referenced in the table above, increased $115.9 million during the first quarter of 2024, compared with the same quarter in 2023. The higher natural gas utility margins were driven by a $118.0 million increase related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively. PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates. Previously, these costs were being recovered under its QIP rider. As base revenues are concentrated in the winter months when natural gas usage is highest, this rate design change drove a large increase in first quarter 2024 margins.

See Note 22, 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 increased $8.6 million, net of the $5.1 million impact of the riders referenced in the table above, during the first quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other operating expenses were:

•A $5.2 million increase in property and revenue taxes, driven by a $6.2 million increase in the invested capital tax. This increase was related to an increase in regulatory amortizations and the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.

•A $5.0 million increase in depreciation and amortization expense, primarily driven by assets being placed into service as we continue to execute on our capital plan.

•A $3.5 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

•A $1.6 million increase in benefit costs, primarily due to higher deferred compensation expense during the first quarter of 2024, compared with the same quarter in 2023.

These increases in operating expenses were partially offset by a $10.5 million decrease in expenses associated with the favorable settlement of a legal claim during the first quarter of 2024.

Interest Expense

Interest expense at the Illinois segment increased $3.4 million during the first quarter of 2024, compared with the same quarter in 2023, due to the impact of PGL and NSG issuing long-term debt in November 2023, higher average short-term debt balances, and increased short-term debt interest rates.


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Income Tax Expense

Income tax expense at the Illinois segment increased $30.1 million during the first quarter of 2024, compared with the same quarter in 2023, 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 income attributed to common shareholders was $38.6 million during the first quarter of 2024, representing a $5.4 million, or 16.3%, increase over the same quarter in 2023. The increase was driven by lower operation and maintenance expense, primarily due to a decrease in bad debt expense. Higher natural gas margins, driven by MGU's rate increase approved by the MPSC that was effective January 1, 2024, also contributed to the increase in earnings.

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 March 31
(in millions)	2024		2023		B (W)
Natural gas revenues	$	184.6	$	250.0	$	(65.4)
Cost of natural gas sold	90.8		159.2		68.4
Total natural gas margins	93.8		90.8		3.0

Other operation and maintenance	20.6		24.7		4.1
Depreciation and amortization	11.4		10.4		(1.0)
Property and revenue taxes	6.2		7.4		1.2
Operating income	55.6		48.3		7.3

Other income, net	—		0.3		(0.3)
Interest expense	4.0		4.2		0.2
Income before income taxes	51.6		44.4		7.2

Income tax expense	13.0		11.2		(1.8)
Net income attributed to common shareholders	$	38.6	$	33.2	$	5.4

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


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Operation and maintenance not included in line item below	$	17.5	$	16.5	$	(1.0)
Regulatory amortizations and other pass through expenses (1)	3.1		8.2		5.1

Total other operation and maintenance	$	20.6	$	24.7	$	4.1

(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 March 31
	Therms (in millions)
Natural Gas Sales Volumes	2024	2023	B (W)
Customer Class
Residential	138.3	145.6	(7.3)
Commercial and industrial	80.8	92.8	(12.0)
Total retail	219.1	238.4	(19.3)
Transportation	236.9	219.6	17.3
Total sales in therms	456.0	458.0	(2.0)


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	Three Months Ended March 31
	Degree Days
Weather (1)	2024	2023	B (W)
MERC
Heating (3,987 Normal)	3,362	3,882	(13.4)	%

MGU
Heating (3,197 Normal)	2,687	2,738	(1.9)	%

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

Natural Gas Revenues

Natural gas revenues decreased $65.4 million during the first quarter of 2024, compared with the same quarter in 2023. 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 39% during the first quarter of 2024, compared with the same quarter in 2023. 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 $3.0 million during the first quarter of 2024, compared with the same quarter in 2023. The primary factors impacting the increase in natural gas utility margins were:

•A $4.5 million increase related to MGU's rate increase approved by the MPSC that was effective January 1, 2024. See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information.

•A $2.1 million increase related to MERC's final rate increase approved by MPUC in November 2023. See Note 22, Regulatory Environment, for more information.

These increases were partially offset by the following factors:

•A $1.0 million decrease in other non-service revenues due in part to lower late payment charges.

•A $0.9 million decrease related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

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

Other operating expenses at the other states segment decreased $4.3 million during the first quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the decrease in operating expenses were:

•A $4.3 million decrease in bad debt expense related to improvements in our loss rates.

•A $1.2 million decrease in property and revenue taxes, primarily at MERC.

•A $0.9 million decrease in operation and maintenance expense related to MERC's CIP program, which has an offsetting decrease in margins.

These decreases in other operating expenses were partially offset by a $1.0 million increase in depreciation and amortization related to continued capital investment.


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Income Tax Expense

Income tax expense at the other states segment increased $1.8 million during the first quarter of 2024, compared with the same quarter in 2023, driven by higher pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Equity in earnings of transmission affiliates	$	44.8	$	43.8	$	1.0
Interest expense	4.8		4.8		—
Income before income taxes	40.0		39.0		1.0

Income tax expense	9.9		9.7		(0.2)
Net income attributed to common shareholders	$	30.1	$	29.3	$	0.8

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


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Operating income	$	95.0	$	90.4	$	4.6

Interest expense	24.1		19.9		(4.2)
Income before income taxes	70.9		70.5		0.4

Income tax benefit	(23.4)		(17.8)		5.6
Net loss attributed to noncontrolling interests	—		0.2		(0.2)
Net income attributed to common shareholders	$	94.3	$	88.5	$	5.8

Operating Income

Operating income at the non-utility energy infrastructure segment increased $4.6 million during the first quarter of 2024, compared with the same quarter in 2023, primarily due to a $2.9 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $4.2 million during the first quarter of 2024, compared with the same quarter in 2023, 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.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $5.6 million during the first quarter of 2024, compared with the same quarter in 2023, primarily due to a $5.7 million increase in PTCs.


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


	Three Months Ended March 31
(in millions)	2024		2023		B (W)
Operating loss	$	(2.3)	$	(3.6)	$	1.3

Other income, net	15.5		8.5		7.0
Interest expense	66.6		55.6		(11.0)

Loss before income taxes	(53.4)		(50.7)		(2.7)

Income tax benefit	(58.8)		(36.9)		21.9
Net income (loss) attributed to common shareholders	$	5.4	$	(13.8)	$	19.2

Other Income, Net

Other income, net at the corporate and other segment increased $7.0 million during the first quarter of 2024, compared with the same quarter in 2023. The significant factors impacting the increase in other income, net were:

•Net earnings of $2.4 million from our equity method investments in technology and energy-focused investment funds during the first quarter of 2024, compared with net losses of $3.1 million during the same quarter in 2023.

•A $5.2 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. This intercompany interest income is offset by higher intercompany interest expense in our non-utility energy infrastructure segment and is eliminated in consolidation.

Interest Expense

Interest expense at the corporate and other segment increased $11.0 million during the first quarter of 2024, compared with the same quarter in 2023, driven by higher average short-term debt balances and increased short-term debt interest rates. Also contributing to the increase was the impact of long-term debt issuances by WEC Energy Group in January, April, and September 2023. Partially offsetting these increases in interest expense was the impact of the Integrys long-term debt redemption in August 2023, the WEC Energy Group long-term debt maturity in September 2023, and the WEC Energy Group tender offer in January and February 2024.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $21.9 million during the first quarter of 2024, compared with the same quarter in 2023. This increase was driven by a $21.0 million increase in the interim tax benefit recorded to adjust consolidated income tax expense to the projected, annualized consolidated effective income tax rate during the first quarter of 2024, compared with the same quarter in 2023.

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.


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Cash Flows

The following table summarizes our cash flows during the three months ended March 31:


(in millions)	2024		2023		Change in 2024 Over 2023
Cash provided by (used in):
Operating activities	$	863.6	$	796.1	$	67.5
Investing activities	(436.2)		(1,267.9)		831.7
Financing activities	(476.5)		417.6		(894.1)

Operating Activities

Net cash provided by operating activities increased $67.5 million during the first quarter of 2024, compared with the same quarter in 2023, driven by:

•A $137.6 million increase in cash driven by lower amounts of collateral paid to counterparties during the first quarter of 2024, compared with same quarter in 2023, as well as lower realized losses on derivative instruments recognized during the first quarter of 2024, compared with the same quarter in 2023.

•An $84.0 million increase in cash related to $83.0 million of cash received for income taxes during the first quarter of 2024, compared with $1.0 million of cash paid for income taxes during the same quarter in 2023. The increase in cash received for income taxes was driven by proceeds received during the first quarter of 2024 related to 2023 PTCs that were sold to a third party.

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

•A $99.9 million decrease in cash from lower overall collections from customers during the first quarter of 2024, compared with the same quarter in 2023. This decrease was driven by a lower per-unit cost of natural gas and lower sales volumes from warmer winter weather during the first quarter of 2024, compared with the same quarter in 2023.

•A $51.1 million decrease in cash from higher payments for interest, driven by long-term debt issuances during 2023, as well as higher average short-term debt balances and increased short-term debt interest rates during the first quarter of 2024, compared with the same quarter in 2023.

Investing Activities

Net cash used in investing activities decreased $831.7 million during the first quarter of 2024, compared with the same quarter in 2023, 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 Whitewater in January 2023 for $76.0 million.

•A $54.9 million decrease in cash paid for capital expenditures during the first quarter of 2024, which is discussed in more detail below.

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


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Capital Expenditures

Capital expenditures by segment for the three months ended March 31 were as follows:


Reportable Segment (in millions)	2024		2023		Change in 2024 Over 2023
Wisconsin	$	330.8	$	375.0	$	(44.2)
Illinois	75.7		90.8		(15.1)
Other states	18.1		14.9		3.2
Non-utility energy infrastructure	17.3		12.6		4.7
Corporate and other	2.6		6.1		(3.5)
Total capital expenditures	$	444.5	$	499.4	$	(54.9)

The decrease in cash paid for capital expenditures at the Wisconsin segment during the first quarter of 2024, compared with the same quarter in 2023, was driven by lower payments related to the natural gas-fired generation constructed at WPS's Weston power plant site, construction of WE's and WG's LNG facilities, upgrades to WE's natural gas distribution system, and decreased capital expenditures for renewable energy projects at WPS, partially offset by increased payments for WE's electric distribution system.

The decrease in cash paid for capital expenditures at the Illinois segment during the first quarter of 2024, compared with the same quarter in 2023, was driven by lower payments related to PGL's natural gas distribution system, including SMP. For more information on the reason for this decrease, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Future Illinois Proceedings.

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

Financing Activities

Net cash related to financing activities decreased $894.1 million during the first quarter of 2024, compared with the same quarter in 2023, driven by:

•A $1,100.0 million decrease in cash due to the issuance of long-term debt during the first quarter of 2023. We did not issue any long-term debt during the first quarter of 2024.

•A $721.7 million decrease in cash due to increased retirements of long-term debt during the first quarter of 2024, compared with the same quarter in 2023.

•The purchase of an additional 10% ownership interest in Samson I in January 2024 for $28.1 million.

•A $17.4 million decrease in cash due to higher dividends paid on our common stock during the first quarter of 2024, compared with the same quarter in 2023. In January 2024, our Board of Directors increased our quarterly dividend by $0.055 per share (7.1%) effective with the March 2024 dividend payment.

These decreases in cash were partially offset by:

•A $938.2 million increase in cash due to $552.8 million of net borrowings of commercial paper during the first quarter of 2024, compared with $385.4 million of net repayments of commercial paper during the same quarter in 2023.

•A $19.2 million increase in cash due to the issuance of common stock during the first quarter of 2024. We did not issue any common stock during the first quarter of 2023. See Note 7, Common Equity, for more information.

Other Significant Financing Activities

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


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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 2023 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, 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 20, Commitments and Contingencies.


(in millions)	2024 (1)		2025		2026
Wisconsin	$	2,636.6	$	3,153.5	$	3,583.8
Illinois	428.9		392.5		501.3
Other states	123.5		104.1		109.9
Non-utility energy infrastructure	948.8		286.6		29.8
Corporate and other	21.9		14.0		2.0
Total	$	4,159.7	$	3,950.7	$	4,226.8

(1)This includes actual capital expenditures incurred through March 31, 2024, 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, 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 and WPS, along with an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 180 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 and battery storage expected to be completed in 2024 and 2025, respectively.

•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 $427 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.

•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 $578 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 September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility in Rock County, Wisconsin, for $100 million. In October 2023, WPS filed for approval to assign the second option to purchase part of West Riverside to WE. These requests were approved in February 2024 and our share of the cost of this ownership interest is expected to be approximately $100 million, with the transaction expected to close by June 2024.

•WE and WPS plan to enhance fuel flexibility at the coal-fired ERGS units and Weston Unit 4.

•In February 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct High Noon Solar Energy Center, a utility-scale solar-powered electric generating facility. If approved, the project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation of this project. If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $576 million, with construction expected to be completed by the end of 2026. Approval for battery capacity at this project was also requested, which is not included in the current capital plan. We will continue to evaluate the timing, cost, and feasibility of the installation of batteries.

•UMERC received MPSC approval to acquire and construct Renegade Solar Energy Center, a utility-scale solar-powered electric generating facility. The project will be located in Delta County, Michigan and once fully constructed UMERC will own 100 MWs of solar generation. The cost of this project is estimated to be approximately $226 million, with construction expected to be completed by the end of 2026.

•In April 2024, WE filed a request with the PSCW to build five natural gas fired combustion turbines capable of producing approximately 1,100 MWs which would be located at the existing Oak Creek campus. If approved, the cost of this project is estimated to be approximately $1.2 billion.

•In April 2024, WE filed a request with the PSCW to add seven natural gas-fired RICE units near the Paris Generating Station. The new RICE units would be fueled with natural gas and capable of producing approximately 128 MWs. If approved, the cost of this project is estimated to be approximately $280 million.

•In April 2024, WE filed a request with the PSCW to construct the Rochester Lateral, which would supply additional natural gas service to the Oak Creek campus. The natural gas lateral would be built in Kenosha, Racine, and Milwaukee counties. If approved, the cost of this project is estimated to be approximately $180 million.

•In April 2024, WE filed a request with the PSCW to construct an LNG facility which would be located on the Oak Creek campus. If approved, the facility would have a storage capacity of two Bcf and the cost of this project is estimated to be approximately $460 million.

The construction of additional LNG facilities in Wisconsin has been proposed as part of the 2024-2028 capital plan and would provide another approximately two Bcf of natural gas supply. The facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

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.

During 2023, PGL continued work on the SMP, a project to replace approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC has a proceeding to determine the optimal method of pipeline replacement and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last twelve months. For more information, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Future Illinois Proceedings. On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which includes the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system. As a result, PGL has suspended neighborhood work pending the results of the limited hearing. See Note 22, Regulatory Environment, for more information on the SMP.


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The non-utility energy infrastructure line item in the table above includes WECI's investment in Maple Flats, Delilah I, and the purchase of an additional 10% ownership interest in Samson I. 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 $345 million from 2024 through 2026. We do not expect to make any contributions to ATC Holdco during that period. WEC's portion of the cost for MISO Tranche 1 is estimated to be approximately $330 million between 2024 and 2028. Tranche 1 is part of MISO's Long Range Transmission Planning initiative to upgrade the grid so that it can reliably accommodate for the shift in generation to lower-carbon resources.

Long-Term Debt

See Note 9, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the three months ended March 31, 2024.

Common Stock Dividends

Our current quarterly dividend rate is $0.835 per share, which equates to an annual dividend of $3.34 per share. For information related to our most recent common stock dividend declared, see Note 7, Common Equity.

Other Significant Cash Requirements

See Note 20, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural 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 three months ended March 31, 2024.

Off-Balance Sheet Arrangements

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

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, in January 2024, we started issuing common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan. We also anticipate issuing common equity through an at-the-market program in the future. 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. In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes.


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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 2024, 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 2023 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 March 31, 2024, our current liabilities exceeded our current assets by $2,105.1 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 8, Short-Term Debt and Lines of Credit, and Note 9, Long-Term Debt, for more information about our credit facilities, commercial paper, and debt securities.

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 have 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 2023 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of March 31, 2024, 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	$	12,112.7		$	12,301.6
Preferred stock of subsidiary	30.4			30.4
Long-term debt (including current portion)	16,016.3			15,827.4
Short-term debt	2,574.2			2,574.2
Total capitalization	$	30,733.6		$	30,733.6

Total debt	$	18,590.5		$	18,401.6

Ratio of debt to total capitalization	60.5		%	59.9		%

Included in long-term debt on our balance sheet as of March 31, 2024, is $377.9 million principal amount of the 2007 Junior Notes. The adjusted presentation attributes $188.9 million of the 2007 Junior Notes to common shareholders' equity and $189.0 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


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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 March 31, 2024, 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 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, in our 2023 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 March 31, 2024. 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 March 31, 2024, it could have been required to post $103 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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

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 2023 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 5, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.


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and NSG's application requesting a rehearing of the ICC's May 2023 order. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders. Their appeal is still pending. As of March 31, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2023, will be deemed recoverable by the ICC. The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million during these open reconciliation years. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

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, which was in effect until December 1, 2023, continues to be subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2022, are still pending. Annual costs included in PGL's QIP rider have ranged from $192 million to $348 million during these open reconciliation years. As of March 31, 2024, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

See Note 22, Regulatory Environment, in this report, and Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Future Illinois Proceedings

In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months.

On March 7, 2024, the ICC initiated a statewide "Future of Gas" proceeding. The goal of this proceeding is to explore the issues involved with decarbonization of the gas distribution system in Illinois and recommend any future ICC action or legislative changes needed. It will include the formal exploration and consideration of the role of natural gas in the future, including in the context of the state’s environmental and energy policy goals. The proceeding will include a broad range of stakeholders, including Illinois utilities and other interested parties. The “Future of Gas” proceeding is expected to last at least one year.

At this time, we cannot predict the ultimate outcome of these proceedings or the resulting impact to our natural gas operations in Illinois. Future natural gas investment opportunities in Illinois could be negatively impacted depending upon the outcomes. See Note 22, Regulatory Environment, for more information regarding the November 2023 ICC rate order.

Chicago Decarbonization Efforts

The CABO was introduced at a meeting of the Chicago city council held on January 24, 2024. If approved, this ordinance would set an indoor emissions standard that would require zero-to-low-emission energy systems in newly built commercial and residential buildings and major building additions in the city of Chicago. The proposed emission standards would effectively prohibit the use of natural gas in new buildings and homes and require electric heat and appliances. The CABO would not impact existing homes and businesses. In addition, certain buildings and equipment, such as hospitals, commercial kitchens, and back-up generators, would be exempt from the new emission limits.

In response to the CABO, a resolution was also introduced that would require the formation of a working group comprised of various subject matter experts to analyze the costs of converting buildings from natural gas to electricity, the costs for additional electric generation capacity needed for future building conversions, and the impact of shifting natural gas system costs from new construction to existing buildings if electrification measures are adopted. If the resolution is passed, this analysis would need to be completed prior to the adoption of any decarbonization initiatives, such as the CABO.

If approved by the city council, the CABO is expected to become effective one year after the approval date. PGL's future natural gas operations could be materially adversely impacted if the CABO is passed.

Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

In May 2022, a petition was 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


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regulating public utilities. The party that filed the petition provides financing to its 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.

The PSCW opened a docket to consider the petition and, in December 2022, granted the 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. After a petition by the WUA to reopen or rehear the case expired without action by the PSCW, the WUA filed an appeal with the Dane County Circuit Court. On April 26, 2024, the circuit court reversed the PSCW’s decision, finding that the PSCW erroneously interpreted the definition of "public utility," and the evidence did not support its determination that the lease at issue in the petition did not involve the sale of electricity to the "public" under Wisconsin law. The case was remanded to the PSCW for further review. The petitioner has the right to appeal the circuit court decision. We are continuing to monitor this case for any potential impact on our business 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 whether we will experience any further impacts to the timing and cost of solar projects included in our long-term capital plan.

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.

In August 2023, the DOC issued its final decision, substantially affirming its December 2022 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. In December 2023, two U.S. solar manufacturers filed a challenge to this moratorium in the United States Court of International Trade.

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 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


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customers can benefit from the IRA’s provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us. Overall, we believe the IRA will help reduce our cost of investing in projects that will support our commitment to reduce emissions and provide customers affordable, reliable, and clean energy over the longer term.

Return on Equity Incentive for Membership in a Transmission Organization

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

American Transmission Company Allowed Return on Equity 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 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


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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. The FERC has not provided a ruling in response to the August 2022 Decision issued by the D.C. Circuit Court of Appeals yet.

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

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 regional conflicts, including those in Ukraine, Israel and in other parts of the Middle East, 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 2023 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below that are disclosed in Part I of our 2023 Annual Report on Form 10-K.


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•Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Public health crises, including epidemics and pandemics, could adversely affect our business functions, financial condition, liquidity, and results of operations.

•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 operations.

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

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 2023 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 12, Fair Value Measurements, Note 13, Derivative Instruments, and Note 14, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the first quarter of 2024 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 2023 Annual Report on Form 10-K. See Note 20, Commitments and Contingencies, and Note 22, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.

In addition to those legal proceedings discussed in Note 20, Commitments and Contingencies, Note 22, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material 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 "Court"). The plaintiffs alleged 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 putative class included participants in the Plan from May 10, 2016 through the date of judgment. The complaint sought injunctive relief, damages, interest, costs, and attorneys' fees. On March 29, 2024, the Court dismissed the lawsuit with prejudice and the matter is now concluded.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2023 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 March 31, 2024:


Issuer Purchases of Equity Securities
2024	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
January 1 – January 31	18,837	$	86.25	—	$	—
February 1 – February 29	—	—		—	—
March 1 – March 31	—	—		—	—
Total (1)	18,837	$	86.25	—

(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 March 31, 2024, 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.

Number	Exhibit
















10	Material Contracts

	10.1*	Letter Agreement by and between WEC Energy Group and Michael Hooper, dated March 7, 2024 (Exhibit 10.1 to WEC Energy Group's 03/12/2024 Form 8-K).*

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:	May 3, 2024	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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