WEC Energy Group (NYSE: WEC) grows Q1 2026 profit and cash flow

Rhea-AI Filing Summary

WEC Energy Group reported higher results for the quarter ended March 31, 2026. Operating revenues rose to $3,434.2 million from $3,149.5 million, driven by stronger electric and natural gas utility revenues across Wisconsin and other states and higher other operating revenues.

Net income reached $806.1 million versus $725.5 million, with net income attributed to common shareholders of $804.4 million. Diluted EPS increased to $2.45 from $2.27 as earnings grew faster than share count. Operating cash flow was strong at $1,218.4 million, funding substantial capital expenditures of $817.9 million while the company also refinanced and added long‑term debt.

The balance sheet showed total assets of $51.7 billion, long‑term debt (including current portion) of $19.9 billion, and common shareholders’ equity of $14.1 billion. WEC continued investing in renewable and regulated infrastructure, managed credit losses under regulatory mechanisms, and maintained a quarterly dividend of $0.9525 per share.

Key Figures

Operating revenues: $3,434.2 million Net income: $806.1 million Diluted EPS: $2.45 per share +5 more

8 metrics

Operating revenues $3,434.2 million Three months ended March 31, 2026

Net income $806.1 million Three months ended March 31, 2026

Diluted EPS $2.45 per share Three months ended March 31, 2026

Net cash from operating activities $1,218.4 million Three months ended March 31, 2026

Capital expenditures and asset acquisitions $817.9 million Three months ended March 31, 2026

Common stock dividend $0.9525 per share Quarterly dividend declared April 16, 2026

Commercial paper outstanding $2,040.5 million Short-term debt at March 31, 2026

Total assets $51,734.0 million Consolidated balance sheet at March 31, 2026

Key Terms

Production Tax Credit, AFUDC-Equity, winter moratorium, decoupling, +2 more

6 terms

Production Tax Credit financial

"PTCs are an inflation adjusted United States federal income tax credit for each kilowatt hour of electricity generated by certain renewable energy projects."

A production tax credit is a government benefit that pays producers a fixed amount for each unit they make or sell — for example a set payment per megawatt-hour of electricity or per barrel of a commodity. It matters to investors because it directly raises a project’s cash flow and lowers the effective cost of production, much like a per‑unit coupon, which can change profitability, valuation and the attractiveness of financing or new investment.

AFUDC-Equity financial

"AFUDC-Equity represents the cost of capital (i.e. ROE) that is added to the construction cost of an asset while it is being built."

AFUDC‑equity is the accounting credit that a regulated company adds to the cost of building long‑lived assets to recognize a notional return on the portion of construction financed by shareholders’ equity. Think of it like paying the company’s owners a running “interest” on their money while a project is being built; it boosts reported profits and the capitalized cost of the asset today and can influence future regulated rates and cash flows received by investors.

winter moratorium regulatory

"This increase is driven by an increase in past due balances over the winter moratorium months, when we are not allowed to disconnect service as a result of non-payment."

decoupling regulatory

"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."

Decoupling describes when two things that used to move together—such as two countries’ economies, a sector and the broader market, or related asset prices—start behaving independently, so one no longer reliably predicts the other. Investors care because decoupling changes how risk, diversification and forecasts work: strategies that relied on historical links may fail, like assuming two dancers will mirror each other and finding they suddenly follow different rhythms.

at-the-market offering program financial

"we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $3.0 billion through an at-the-market offering program."

An at-the-market offering program lets a company sell newly issued shares directly into the open market at current trading prices through a broker, rather than issuing a large block of stock all at once. It matters to investors because it provides the company a flexible way to raise cash over time, which can dilute existing shares gradually and affect earnings per share and stock price depending on how much and when shares are sold—think of it as a faucet the company can open or close to add supply to the market.

forward sales contracts financial

"we did enter into several forward sales contracts. As of March 31, 2026, no shares had been settled under these contracts."

10-Q Quarterly Reports: What Changes Quarter to Quarter →

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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, 2026

OR

☐ 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, 2026):

Common Stock, $.01 Par Value, 325,725,678 shares outstanding

Table of Contents

WEC ENERGY GROUP, INC.

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2026

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

1

PART I.

FINANCIAL INFORMATION

4

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

4

Condensed Consolidated Income Statements

4

Condensed Consolidated Statements of Comprehensive Income

5

Condensed Consolidated Balance Sheets

6

Condensed Consolidated Statements of Cash Flows

7

Condensed Consolidated Statements of Equity

8

Notes to Condensed Consolidated Financial Statements

9

Page

Note 1

General Information

9

Note 2

Acquisitions

9

Note 3

Disposition

10

Note 4

Operating Revenues

10

Note 5

Credit Losses

13

Note 6

Regulatory Assets and Liabilities

15

Note 7

Property, Plant, and Equipment

16

Note 8

Common Equity

16

Note 9

Short-Term Debt and Lines of Credit

18

Note 10

Long-Term Debt

19

Note 11

Materials, Supplies, and Inventories

20

Note 12

Income Taxes

21

Note 13

Fair Value Measurements

21

Note 14

Derivative Instruments

23

Note 15

Guarantees

25

Note 16

Employee Benefits

25

Note 17

Goodwill and Intangibles

26

Note 18

Investment in Transmission Affiliates

27

Note 19

Segment Information

28

Note 20

Variable Interest Entities

31

Note 21

Commitments and Contingencies

33

Note 22

Supplemental Cash Flow Information

37

Note 23

Regulatory Environment

38

Note 24

Other Income, Net

42

Note 25

New Accounting Pronouncements

42

ITEM 2.

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

43

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

67

ITEM 4.

CONTROLS AND PROCEDURES

67

PART II.

OTHER INFORMATION

68

ITEM 1.

LEGAL PROCEEDINGS

68

ITEM 1A.

RISK FACTORS

68

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

68

ITEM 5.

OTHER INFORMATION

68

ITEM 6.

EXHIBITS

69

SIGNATURE

70

03/31/2026 Form 10-Q i WEC Energy Group, Inc.

Table of Contents

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
Delilah I						Delilah Solar Energy LLC
Hardin III						Hardin Solar Energy III Center
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 Solar Energy LLC
Tatanka Ridge						Tatanka Ridge Wind LLC
Thunderhead						Thunderhead Wind Energy 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
MPSC						Michigan Public Service Commission
PSCW						Public Service Commission of Wisconsin
SEC						United States Securities and Exchange Commission
USITC						United States International Trade Commission
Accounting Terms
AFUDC						Allowance for Funds Used During Construction
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
BTA						Best Technology Available
CAA						Clean Air Act
CCR						Coal Combustion Residuals
CO2						Carbon Dioxide
CRL						Combustion Residual Leachate
ELG						Steam Electric Effluent Limitation Guidelines

03/31/2026 Form 10-Q ii WEC Energy Group, Inc.

Table of Contents

GHG						Greenhouse Gas
GHG Power Plant Rule						2024 Greenhouse Gas Power Plant Rule
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
NOx						Nitrogen Oxide
PCCC						Permanent Cessation of Coal Combustion
PM						Particulate Matter
PM2.5						Particulates Less Than 2.5 Micrometers in Diameter
ZLD						Zero Liquid Discharge
Measurements
Bcf						Billion Cubic Feet
Dth						Dekatherm
GW						Gigawatt
lb/MMBtu						Pound Per Million British Thermal Unit
MW						Megawatt
MWh						Megawatt-hours
µg/m3						Micrograms Per Cubic Meter
Other Terms and Abbreviations
2024A Junior Notes						WEC Energy Group, Inc.'s Series 2024A 6.69% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due June 15, 2055
2024B Junior Notes						WEC Energy Group, Inc.'s Series 2024B 6.69% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due June 15, 2055
2025 Junior Notes						WEC Energy Group, Inc.'s Series 2025 5.625% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due May 15, 2056
2027 Notes						WEC Energy Group, Inc.'s 4.375% Convertible Senior Notes Due 2027
2028 Notes						WEC Energy Group, Inc.'s 3.375% Convertible Senior Notes Due 2028
2029 Notes						WEC Energy Group, Inc.'s 4.375% Convertible Senior Notes Due 2029
AD						Antidumping
AI						Artificial Intelligence
AREP						Amended Renewable Energy Plan
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
CODM						Chief Operating Decision Maker
Columbia						Columbia Energy Center
Compensation Committee						Compensation Committee of the Board of Directors
CT						Combustion Turbine
CVD						Countervailing Duty
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
EDA						Equity Distribution Agreement
EPS						Earnings Per Share
ERGS						Elm Road Generating Station
ETB						Environmental Trust Bond
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
IRA						Inflation Reduction Act
ITC						Investment Tax Credit
LDC						Local Natural Gas Distribution Company
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.
OBBBA						One Big Beautiful Bill Act
OCPP						Oak Creek Power Plant
PPA						Power Purchase Agreement
PRP						Pipe Retirement Program
PTC						Production Tax Credit
Pulliam						J.P. Pulliam Generating Station
QIP						Qualifying Infrastructure Plant

03/31/2026 Form 10-Q iii WEC Energy Group, Inc.

Table of Contents

Renegade						Renegade Solar Energy Center
RNG						Renewable Natural Gas
ROE						Return on Equity
S&P						Standard & Poor's
Supreme Court						United States Supreme Court
TCR						Transmission Congestion Right
UEA						Uncollectible Expense Adjustment
UFLPA						Uyghur Forced Labor Prevention Act
VLC						Very Large Customer
Weston						Weston Generating Station

03/31/2026 Form 10-Q iv WEC Energy Group, Inc.

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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 capital 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 2025 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, electric grid reliability, and electric transmission or natural gas pipeline system constraints;

•Factors affecting the demand for electricity and natural gas, including political or regulatory developments, varying, adverse, or unusually severe weather conditions, changes in economic conditions, including continued economic growth, customer growth and declines, including our ability to develop and/or acquire new generation to meet demand from data centers and other large customers and uncertainty regarding the projected demand from these customers, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers or co-location of generation near data centers;

•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 rate orders, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, changes to address energy affordability concerns, 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 changing environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in and uncertainty regarding 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;

•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 changes to United States trade policy (including changes to tariffs on imports, port fees, and other trade policy tools) as well as changes to foreign governments' trade policies impacting United States exports, supply chain disruptions (including from rail congestion), inflation, and other factors;

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•Risks related to providing service to data centers and other large-scale customers including project termination, cancellation or delay, failure to receive regulatory approvals of projects or tariffs or other necessary permitting or siting approvals, delays in recovery of contractual reimbursement for project costs, the ability to fully recover our investment on assets developed to serve our large-scale customers, lower than anticipated need for electricity by these customers, failure to garner public support, or new legislation or regulation impacting large-scale customer cost allocation;

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

•Risks inherent in electric generation and distribution and natural gas transportation, distribution, and storage activities, including leaks, accidental explosions, mechanical problems, fires, discharges or releases of toxic or hazardous substances or gases, and risks related to the ability to obtain adequate insurance to cover such events;

•Factors affecting the achievement of our CO2 emission reduction goal and related opportunities and actions, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, significant increases in demand, the feasibility of competing generation projects, and our ability to execute our capital plan;

•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 increasing tensions between the United States and other countries, such as the war with Iran, or from other new, protracted or escalating regional or international conflicts;

•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 data centers and other large-scale customers, 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;

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•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 involved in developing and implementing AI, including data privacy concerns or other legal liability, new or enhanced governmental or regulatory scrutiny or regulations governing the use of AI, the ability to meet expectations or requirements relating to adoption or implementation of AI technology, or other complications related to the use of AI;

•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, pricing differentials between the facilities' point of interconnection and our required delivery location, the ability to replace expiring PPAs under acceptable terms, rights to property on which our projects are located but we do not own, the availability of reliable interconnection and electricity grids, the performance and quality of the wind turbine and solar panel components and availability of replacement parts, and exposure to the rules and procedures of the power markets in which these facilities are located;

•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.

03/31/2026 Form 10-Q 3 WEC Energy Group, Inc.

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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)																		2026						2025
Operating revenues																		$	3,434.2					$	3,149.5
Operating expenses
Cost of sales																		1,391.0						1,165.7
Other operation and maintenance																		608.7						608.0
Depreciation and amortization																		379.8						359.9
Property and revenue taxes																		74.7						78.4
Total operating expenses																		2,454.2						2,212.0
Operating income																		980.0						937.5
Equity in earnings of transmission affiliates																		59.5						53.6
Other income, net																		48.2						18.1
Interest expense																		228.5						223.0
Other expense																		(120.8)						(151.3)
Income before income taxes																		859.2						786.2
Income tax expense																		53.1						60.7
Net income																		806.1						725.5
Preferred stock dividends of subsidiary																		0.3						0.3
Net income attributed to noncontrolling interests																		(1.4)						(1.0)
Net income attributed to common shareholders																		$	804.4					$	724.2
EPS
Basic																		$	2.47					$	2.28
Diluted																		$	2.45					$	2.27
Weighted average common shares outstanding
Basic																		325.6						318.2
Diluted																		328.3						319.3

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)						Three Months Ended
						March 31
(in millions)						2026						2025
Net income						$	806.1					$	725.5
Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Reclassification of realized derivative gains to net income, net of tax						—						(0.1)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax						0.1						—
Other comprehensive income (loss), net of tax						0.1						(0.1)
Comprehensive income						806.2						725.4
Preferred stock dividends of subsidiary						0.3						0.3
Comprehensive income attributed to noncontrolling interests						(1.4)						(1.0)
Comprehensive income attributed to common shareholders						$	804.5					$	724.1

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)						March 31, 2026						December 31, 2025
Assets
Current assets
Cash and cash equivalents						$	45.6					$	27.6
Accounts receivable and unbilled revenues, net of reserves of $156.0 and $148.7, respectively						1,914.4						2,062.7
Materials, supplies, and inventories						612.3						803.4
Prepaid taxes						125.2						178.8
Other prepayments						80.5						92.4
Other						203.0						119.8
Current assets						2,981.0						3,284.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $12,667.5 and $12,411.5, respectively						38,707.0						38,278.1
Regulatory assets (March 31, 2026 and December 31, 2025 include $65.5 and $67.5, respectively, related to WEPCo Environmental Trust)						3,111.3						3,156.3
Equity investment in transmission affiliates						2,369.5						2,280.4
Goodwill						3,052.8						3,052.8
Pension and OPEB assets						1,098.5						1,082.4
Other						413.9						383.6
Long-term assets						48,753.0						48,233.6
Total assets						$	51,734.0					$	51,518.3
Liabilities and Equity
Current liabilities
Short-term debt						$	2,045.2					$	1,924.7
Current portion of long-term debt (March 31, 2026 and December 31, 2025 include $9.3 related to WEPCo Environmental Trust)						520.4						1,519.4
Accounts payable						830.8						1,140.1
Accrued interest						264.1						161.3
Other						728.9						847.9
Current liabilities						4,389.4						5,593.4
Long-term liabilities
Long-term debt (March 31, 2026 and December 31, 2025 include $67.4 related to WEPCo Environmental Trust)						19,381.8						18,498.1
Finance lease obligations						370.4						372.0
Deferred income taxes						5,967.2						5,891.7
Deferred revenue, net						309.6						314.2
Regulatory liabilities						4,114.7						4,121.3
Intangible liabilities						565.3						580.3
Environmental remediation liabilities						474.3						484.1
AROs						660.6						647.0
Other						931.4						963.4
Long-term liabilities						32,775.3						31,872.1
Commitments and contingencies (Note 21)
Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 325,725,678 and 325,461,519 shares outstanding, respectively						3.3						3.3
Additional paid in capital						5,147.4						5,124.4
Retained earnings						8,987.8						8,493.5
Accumulated other comprehensive loss						(7.5)						(7.6)
Common shareholders' equity						14,131.0						13,613.6
Preferred stock of subsidiary						30.4						30.4
Noncontrolling interests						407.9						408.8
Total liabilities and equity						$	51,734.0					$	51,518.3

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)						Three Months Ended
						March 31
(in millions)						2026						2025
Operating activities
Net income						$	806.1					$	725.5
Reconciliation to cash provided by operating activities
Depreciation and amortization						379.8						359.9
Deferred income taxes and ITCs, net						27.8						55.6
Contributions and payments related to pension and OPEB plans						(3.8)						(3.9)
Equity income in transmission affiliates, net of distributions						(13.3)						2.2
Change in –
Accounts receivable and unbilled revenues, net						77.9						(180.3)
Materials, supplies, and inventories						191.1						237.2
Other current assets						(10.2)						13.0
Accounts payable						(201.0)						(195.4)
Accrued interest						102.8						83.5
Other current liabilities						(47.9)						74.2
Other, net						(90.9)						(8.9)
Net cash provided by operating activities						1,218.4						1,162.6
Investing activities
Capital expenditures						(817.9)						(701.1)
Acquisition of Hardin III, net of cash acquired of $0.2						—						(406.1)
Capital contributions to transmission affiliates						(75.8)						(42.3)
Proceeds from the sale of assets						21.7						—
Reimbursement for ATC's transmission infrastructure upgrades						—						39.7
Other, net						(14.4)						8.0
Net cash used in investing activities						(886.4)						(1,101.8)
Financing activities
Exercise of stock options						7.4						21.2
Issuance of common stock, net						12.8						117.1
Dividends paid on common stock						(310.1)						(283.6)
Issuance of long-term debt						1,005.2						—
Retirement of long-term debt						(1,118.9)						(17.9)
Change in commercial paper						119.2						209.5
Other, net						(11.2)						(5.9)
Net cash provided by (used in) financing activities						(295.6)						40.4
Net change in cash, cash equivalents, and restricted cash						36.4						101.2
Cash, cash equivalents, and restricted cash at beginning of period						70.9						42.2
Cash, cash equivalents, and restricted cash at end of period						$	107.3					$	143.4

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 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, 2025						$	3.3					$	5,124.4					$	8,493.5					$	(7.6)					$	13,613.6					$	30.4					$	408.8					$	14,052.8
Net income attributed to common shareholders						—						—						804.4						—						804.4						—						—						804.4
Net income attributed to noncontrolling interests						—						—						—						—						—						—						1.4						1.4
Other comprehensive income						—						—						—						0.1						0.1						—						—						0.1
Issuance of common stock, net						—						12.8						—						—						12.8						—						—						12.8
Common stock dividends of $0.9525 per share						—						—						(310.1)						—						(310.1)						—						—						(310.1)
Exercise of stock options						—						7.4						—						—						7.4						—						—						7.4
Capital contributions from noncontrolling interest						—						—						—						—						—						—						0.8						0.8
Distributions to noncontrolling interests						—						—						—						—						—						—						(3.1)						(3.1)
Stock-based compensation and other						—						2.8						—						—						2.8						—						—						2.8
Balance at March 31, 2026						$	3.3					$	5,147.4					$	8,987.8					$	(7.5)					$	14,131.0					$	30.4					$	407.9					$	14,569.3

						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, 2024						$	3.2					$	4,315.8					$	8,083.8					$	(7.8)					$	12,395.0					$	30.4					$	376.5					$	12,801.9
Net income attributed to common shareholders						—						—						724.2						—						724.2						—						—						724.2
Net income attributed to noncontrolling interests						—						—						—						—						—						—						1.0						1.0
Other comprehensive loss						—						—						—						(0.1)						(0.1)						—						—						(0.1)
Issuance of common stock, net						—						117.1						—						—						117.1						—						—						117.1
Common stock dividends of $0.8925 per share						—						—						(283.6)						—						(283.6)						—						—						(283.6)
Exercise of stock options						—						21.2						—						—						21.2						—						—						21.2
Acquisition of noncontrolling interests						—						—						—						—						—						—						45.1						45.1
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.8)						(1.8)
Stock-based compensation and other						—						2.0						—						—						2.0						—						—						2.0
Balance at March 31, 2025						$	3.2					$	4,456.1					$	8,524.4					$	(7.9)					$	12,975.8					$	30.4					$	420.8					$	13,427.0

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

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2026

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.7 million electric customers and 3.1 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 18, 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, 2025. 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, 2026, are not necessarily indicative of expected results for 2026 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 the below acquisitions met the criteria of asset acquisitions. The purchase price of the Hardin III acquisition discussed below includes intangibles recorded as long-term liabilities related to PPAs. See Note 17, Goodwill and Intangibles, for more information.

Pending Acquisitions of Electric Generation Facilities in Wisconsin

WE filed for PSCW approval to purchase a 30% ownership interest in Weston Unit 4, an approximately 500 MW supercritical pulverized coal base load electric generating facility located in the Villages of Kronenwetter and Rothschild, Wisconsin and the Town of Knowlton, Wisconsin. WPS currently owns a 70% interest in this facility. Pursuant to the asset purchase agreement, WE would purchase the remaining 30% interest currently owned by an unrelated third-party for its book value at the closing date, currently estimated at $150 million. If approved, it is anticipated that the transaction would close by the end of 2026.

In December 2025, WE and WPS, along with an unaffiliated utility, signed an agreement to acquire Whitetail Wind Energy Generation Facility, a wind-powered electric generation project with a total capacity of 67.2 MW. This project has been approved by the PSCW and will be located in Grant County, Wisconsin and WE will own 80% and WPS will own 10%. WE's share of the purchase price is expected to be approximately $178 million and WPS's share of the purchase price is expected to be approximately $22 million. The project is expected to close in late 2027 and it is expected to qualify for PTCs.

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Acquisition of a Solar Generation Facility in Ohio

Upon commercial operation in February 2025, WECI completed the acquisition of a 90% ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for $406.1 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. Hardin III qualifies for PTCs and is included in the non-utility energy infrastructure segment.

NOTE 3—DISPOSITION

Illinois Segment

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

In January 2026, we sold approximately 15 acres of real estate owned by PGL that was no longer being utilized in its operations, for $20.9 million, which is net of selling costs. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $11.9 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2025 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, 2026
Electric						$	1,433.3					$	—					$	—					$	1,433.3					$	—					$	—					$	—					$	1,433.3
Natural gas						892.3						712.0						253.5						1,857.8						13.2						—						(13.1)						1,857.9
Total regulated revenues						2,325.6						712.0						253.5						3,291.1						13.2						—						(13.1)						3,291.2
Other non-utility revenues						—						—						5.6						5.6						75.7						—						(1.6)						79.7
Total revenues from contracts with customers						2,325.6						712.0						259.1						3,296.7						88.9						—						(14.7)						3,370.9
Other operating revenues						12.7						37.7						(1.8)						48.6						121.8						—						(107.1)			(1)			63.3
Total operating revenues						$	2,338.3					$	749.7					$	257.3					$	3,345.3					$	210.7					$	—					$	(121.8)					$	3,434.2

03/31/2026 Form 10-Q 10 WEC Energy Group, Inc.

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended March 31, 2025
Electric						$	1,320.0					$	—					$	—					$	1,320.0					$	—					$	—					$	—					$	1,320.0
Natural gas						734.1						759.3						223.7						1,717.1						14.1						—						(13.4)						1,717.8
Total regulated revenues						2,054.1						759.3						223.7						3,037.1						14.1						—						(13.4)						3,037.8
Other non-utility revenues						—						—						5.5						5.5						61.5						—						(1.6)						65.4
Total revenues from contracts with customers						2,054.1						759.3						229.2						3,042.6						75.6						—						(15.0)						3,103.2
Other operating revenues						5.8						29.0						(2.1)						32.7						118.7						—						(105.1)			(1)			46.3
Total operating revenues						$	2,059.9					$	788.3					$	227.1					$	3,075.3					$	194.3					$	—					$	(120.1)					$	3,149.5

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

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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

						Three Months Ended March 31
(in millions)						2026						2025
Residential						$	573.4					$	545.0
Small commercial and industrial						451.6						421.1
Large commercial and industrial						274.0						238.3
Other						8.1						8.0
Total retail revenues						1,307.1						1,212.4
Wholesale						30.1						27.7
Resale						77.0						62.8
Steam						13.8						12.8
Other utility revenues						5.3						4.3
Total electric utility operating revenues						$	1,433.3					$	1,320.0

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, 2026
Residential						$	567.3					$	452.2					$	150.5					$	1,170.0
Commercial and industrial						288.6						131.2						81.3						501.1
Total retail revenues						855.9						583.4						231.8						1,671.1
Transportation						34.4						93.8						13.6						141.8
Other utility revenues (1)						2.0						34.8						8.1						44.9
Total natural gas utility operating revenues						$	892.3					$	712.0					$	253.5					$	1,857.8

03/31/2026 Form 10-Q 11 WEC Energy Group, Inc.

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(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2025
Residential						$	488.8					$	465.6					$	142.7					$	1,097.1
Commercial and industrial						250.4						131.2						73.1						454.7
Total retail revenues						739.2						596.8						215.8						1,551.8
Transportation						33.2						97.4						13.5						144.1
Other utility revenues (1)						(38.3)						65.1						(5.6)						21.2
Total natural gas utility operating revenues						$	734.1					$	759.3					$	223.7					$	1,717.1

(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, compared with the recovery of natural gas costs that were included 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.

Other Non-Utility Operating Revenues

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

						Three Months Ended March 31
(in millions)						2026						2025
Renewable generation revenues						$	68.0					$	53.8
We Power revenues (1)						6.1						6.1
Appliance service revenues						5.6						5.5
Total other non-utility operating revenues						$	79.7					$	65.4

(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)						2026						2025
Alternative revenues (1)						$	26.9					$	18.3
Late payment charges						15.9						13.8
Amortization of revenue intangibles (2)						14.7						13.6
Bespoke resources current return (3)						4.3						—
Other						1.5						0.6
Total other operating revenues						$	63.3					$	46.3

(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 2025 Annual Report on Form 10-K.

(2)    We account for our asset acquisitions by recognizing identifiable intangible assets and liabilities assumed at fair value at the acquisition date. Amortization of these intangible assets and liabilities, which relate to PPAs and a proxy revenue swap, is recognized on a straight-line basis over the remaining contract term as a decrease or increase to operating revenues, respectively. See Note 17, Goodwill and Intangibles, for more information.

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(3)    Consists of carrying costs earned during the construction of certain bespoke resources assigned to WE's VLCs. For more information about the bespoke resources current return, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

NOTE 5—CREDIT LOSSES

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

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment related to the sale of electricity from our majority-owned renewable generating facilities through agreements with several large high credit quality counterparties.

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

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, 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, 2026 and December 31, 2025, 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, 2026
Accounts receivable and unbilled revenues						$	1,279.3					$	605.3					$	122.7					$	2,007.3					$	56.7					$	6.4					$	2,070.4
Allowance for credit losses						63.6						88.3						4.1						156.0						—						—						156.0
Accounts receivable and unbilled revenues, net (1)						$	1,215.7					$	517.0					$	118.6					$	1,851.3					$	56.7					$	6.4					$	1,914.4
Total accounts receivable, net – past due greater than 90 days (1)						$	48.8					$	45.3					$	2.3					$	96.4					$	—					$	—					$	96.4
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						96.5		%				100.0		%				—		%				95.8		%				—		%				—		%				95.8		%

03/31/2026 Form 10-Q 13 WEC Energy Group, Inc.

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
December 31, 2025
Accounts receivable and unbilled revenues						$	1,368.8					$	654.8					$	130.2					$	2,153.8					$	50.3					$	7.3					$	2,211.4
Allowance for credit losses						61.7						82.3						4.7						148.7						—						—						148.7
Accounts receivable and unbilled revenues, net (1)						$	1,307.1					$	572.5					$	125.5					$	2,005.1					$	50.3					$	7.3					$	2,062.7
Total accounts receivable, net – past due greater than 90 days (1)						$	46.4					$	36.8					$	6.6					$	89.8					$	—					$	—					$	89.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						94.6		%				100.0		%				—		%				89.9		%				—		%				—		%				89.9		%

(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, 2026, $1,240.3 million, or 64.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 23, Regulatory Environment, for more information on PGL and NSG's UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and amounts recovered in rates.

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

Three Months Ended March 31, 2026 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2026						$	61.7					$	82.3					$	4.7					$	148.7
Provision for credit losses						48.8						16.8						(0.1)						65.5
Provision for credit losses deferred for future recovery or refund						(25.2)						5.6						—						(19.6)
Write-offs charged against the allowance						(36.0)						(23.5)						(1.1)						(60.6)
Recoveries of amounts previously written off						14.3						7.1						0.6						22.0
Balance at March 31, 2026						$	63.6					$	88.3					$	4.1					$	156.0

On a consolidated basis, there was a $7.3 million increase in the allowance for credit losses at March 31, 2026, compared to January 1, 2026. This increase is driven by an increase in past due balances 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. In Illinois, the winter moratorium begins on December 1 and ends on March 31.

Three Months Ended March 31, 2025 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2025						$	73.6					$	83.9					$	5.3					$	162.8
Provision for credit losses						16.1						16.3						0.2						32.6
Provision for credit losses deferred for future recovery or refund						(7.3)						2.2						—						(5.1)
Write-offs charged against the allowance						(33.8)						(25.6)						(0.7)						(60.1)
Recoveries of amounts previously written off						12.3						16.4						0.5						29.2
Balance at March 31, 2025						$	60.9					$	93.2					$	5.3					$	159.4

On a consolidated basis, there was a $3.4 million decrease in the allowance for credit losses at March 31, 2025, compared to January 1, 2025. The allowance for credit losses decreased in Wisconsin during the quarter mainly driven by customer write-offs in addition to a decrease in past due account balances. Reserves increased in Illinois due to an increase in past due balances over the winter moratorium months.

03/31/2026 Form 10-Q 14 WEC Energy Group, Inc.

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NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2026 and December 31, 2025. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2025 Annual Report on Form 10-K.

(in millions)						March 31, 2026						December 31, 2025
Regulatory assets
Plant retirement related items						$	751.8					$	768.6
Environmental remediation costs						553.6						566.0
Pension and OPEB costs						544.8						564.5
Income tax related items						511.1						493.4
AROs						194.7						185.1
System support resource						90.1						92.6
Uncollectible expense						87.8						123.9
Decoupling						70.6						43.8
Energy costs recoverable through rate adjustments						66.4						6.7
Securitization						65.5						67.5
Derivatives						41.3						57.7
Finance and operating leases						41.0						36.0
Electric transmission costs						38.1						30.7
Bluewater						34.8						37.7
Other, net						92.0						99.4
Total regulatory assets						$	3,183.6					$	3,173.6
Balance sheet presentation
Other current assets						$	72.3					$	17.3
Regulatory assets						3,111.3						3,156.3
Total regulatory assets						$	3,183.6					$	3,173.6

(in millions)						March 31, 2026						December 31, 2025
Regulatory liabilities
Income tax related items						$	1,783.5					$	1,802.4
Removal costs						1,620.7						1,584.7
Pension and OPEB benefits						299.4						301.5
Energy costs refundable through rate adjustments						144.2						119.2
Proposed settlement related to QIP and UEA riders						125.0						125.0
Uncollectible expense						63.7						73.1
Earnings sharing mechanisms						34.9						35.8
MERC property tax tracker						24.2						23.1
Energy efficiency programs						21.0						12.2
Derivatives						11.9						27.4
Other, net						89.8						105.8
Total regulatory liabilities						$	4,218.3					$	4,210.2
Balance sheet presentation
Other current liabilities						$	103.6					$	88.9
Regulatory liabilities						4,114.7						4,121.3
Total regulatory liabilities						$	4,218.3					$	4,210.2

03/31/2026 Form 10-Q 15 WEC Energy Group, Inc.

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NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7-8

The retirement of OCPP Units 7 and 8 became probable at the end of 2022, following initial PSCW approvals for replacement generation. On April 1, 2026, we announced plans to extend the operating lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through 2027. These units were previously scheduled to be retired at the end of 2026. The decision to postpone the retirement dates for these units is based on two critical factors, reliability and affordability for WE’s customers. This past winter the Midwest power market experienced tightened energy supply and higher energy costs during extreme temperatures. Keeping OCPP Units 7 and 8 available will better position WE to serve customers with safe, reliable and affordable energy on the hottest and coldest days of the year. The extension of these units will serve as a bridge until new dispatchable generation begins to come online, which is expected in late 2027.

The total net book value of WE's ownership share of OCPP Units 7 and 8 was $613.3 million at March 31, 2026, 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.

Samson Solar Energy LLC and Delilah Solar Energy LLC – Storm Damage

During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage. We had previously recognized an impairment loss of $2.8 million related to damage from these storms, and recorded an offsetting $2.8 million receivable for future insurance recoveries. However, in the second quarter of 2025, we determined it was no longer probable that we would receive insurance proceeds sufficient to recover our losses associated with the 2023 and 2024 storms. As a result, the insurance receivable balance was written off, resulting in the recognition of the $2.8 million impairment loss within other operation and maintenance expense on our income statement.

In addition, in March 2025, both our Samson I and Delilah I solar facilities experienced damage from a storm. In the second quarter of 2025, we recognized an impairment loss within other operation and maintenance expense on our income statement in the amount of $8.8 million, related to damage incurred associated with the March 2025 storm. The impairment loss associated with the March 2025 storm was increased from $8.8 million to $12.0 million in the third quarter of 2025 as a result of ongoing damage assessment.

The Peoples Gas Light and Coke Company Impairment

In the fourth quarter of 2025, PGL recorded a $130.0 million impairment to property, plant, and equipment related to the terms of a proposed settlement that would resolve its open QIP proceedings. See Note 23, Regulatory Environment, for more information.

NOTE 8—COMMON EQUITY

Stock-Based Compensation

During the three months ended March 31, 2026, 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)						269,085
Restricted shares (2)						75,222
Performance units						182,146

(1)Stock options awarded had a weighted-average exercise price of $106.09 and a weighted-average grant date fair value of $21.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $106.09 per share.

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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 2025 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

We issue new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensation plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

In August 2024, we entered into an EDA, under which we could offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $1.5 billion through an at-the-market offering program. In October 2025, we terminated this EDA and entered into a new EDA, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $3.0 billion through an at-the-market offering program. This EDA also includes an equity forward sales component and a collared forward sales component. We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement. The October 2025 EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) October 31, 2028. Actual sales of common stock under the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding. Any shares offered and sold under our EDA will be done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplements.

As of March 31, 2026, we had not yet issued any shares of common stock under our October 2025 EDA; however, we did enter into several forward sales contracts. As of March 31, 2026, no shares had been settled under these contracts. The following table presents information related to the common stock sold under our outstanding forward sales contracts at March 31, 2026:

Forward Sale Contract Effective Date

Maturity Date

Shares

Initial Forward Price (1)

Fourth quarter - 2025

June 30, 2027

58,533

$

110.7748

First quarter - 2026

September 30, 2027

3,726,090

114.8548

(1)Amount represents the weighted-average initial forward price of the forward sales contracts that became effective during the quarter. The initial forward price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts as specified in the contract.

No amounts are recorded on our balance sheet with respect to these contracts until actual settlement occurs. The contracts require us, at our election, to either (i) physically settle the transaction by issuing shares of our stock in exchange for net cash proceeds at the then-applicable forward sales price or (ii) net settle the transaction through the delivery or receipt of cash or shares in accordance with the contract provisions. At March 31, 2026, we could have settled our outstanding forward sales contracts as follows:

(Dollars in millions)						Physical Share Settlement						Net Settlement
Forward Sale Contract Effective Date						Cash Proceeds						Cash Payments						Shares Issued
Fourth quarter - 2025						$	6.5					$	(0.3)					(2,486)
First quarter - 2026						428.8						(2.5)						(22,022)

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We had the following changes to our outstanding common stock during the three months ended March 31, 2026 and 2025:

												Three Months Ended March 31
																		2026						2025
Common stock shares outstanding at beginning of period																		325,461,519						317,680,855
Shares issued:
At-the-market offering program																		—						977,824
Stock-based compensation																		151,210						342,711
401(k)																		30,934						43,300
Stock investment plan																		82,015						88,811
Common stock shares outstanding at end of period																		325,725,678						319,133,501

On April 16, 2026, our Board of Directors declared a quarterly cash dividend of $0.9525 per share, payable on June 1, 2026, to shareholders of record on May 14, 2026.

Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the three months ended March 31, 2026 and 2025:

												Three Months Ended March 31
(in millions)																		2026						2025
Numerator:
Net income attributed to common shareholders																		$	804.4					$	724.2
Denominator:
Weighted average basic shares outstanding																		325.6						318.2
Dilutive effect of stock-based compensation awards																		0.5						0.5
Dilutive effect of convertible senior notes																		2.2						0.6
Weighted average diluted shares																		328.3						319.3
Basic EPS																		$	2.47					$	2.28
Diluted EPS																		$	2.45					$	2.27

NOTE 9—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)						March 31, 2026						December 31, 2025
Commercial paper
Amount outstanding						$	2,040.5					$	1,921.3
Weighted-average interest rate on amounts outstanding						4.07		%				3.89		%
Operating expense loans
Amount outstanding (1)						$	4.7					$	3.4

(1)Coyote Ridge Wind, LLC, Tatanka Ridge, Samson I, Thunderhead, 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, 2026 was $2,271.8 million with a weighted-average interest rate during the period of 3.88%.

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

(in millions)						Maturity						March 31, 2026
WEC Energy Group						August 2030						$	1,700.0
WE						August 2030						800.0
PGL						August 2030						600.0
WPS						August 2030						450.0
WG						August 2030						350.0
Total short-term credit capacity												$	3,900.0
Less:
Letters of credit issued inside credit facilities												$	2.3
Commercial paper outstanding												2,040.5
Available capacity under existing agreements												$	1,857.2

NOTE 10—LONG-TERM DEBT

WEC Energy Group, Inc.

In January 2026, our $1,000.0 million of 4.75% Senior Notes due January 9, 2026, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In February 2026, we issued an additional $400.0 million of our 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Convertible Senior Notes

As of March 31, 2026, the conditions allowing holders to convert their notes were not met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes, 2028 Notes, and 2029 Notes were accounted for in their entirety as a liability on our balance sheet. The following is a summary of our convertible debt instruments as of March 31, 2026:

(in millions)						Principal Amount						Unamortized Debt Issuance Costs						Net Carrying Amount						Fair Value Amount (1)
2027 Notes						$	862.5					$	(3.9)					$	858.6					$	1,041.2
2028 Notes						900.0						(7.7)						892.3						932.8
2029 Notes						862.5						(6.3)						856.2						1,065.7

(1)    The fair values are categorized in Level 2 of the fair value hierarchy. See Note 13, Fair Value Measurements, for more information on the levels of the fair value hierarchy.

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The following table provides a summary of the interest expense recorded for each of the 2027 Notes, 2028 Notes, and 2029 Notes:

												Three Months Ended March 31
(in millions)																		2026						2025
2027 Notes
Contractual interest expense																		$	9.4					$	9.4
Amortization of debt issuance costs																		0.8						0.8
Total interest expense – 2027 Notes																		10.2						10.2
2028 Notes
Contractual interest expense																		7.6						—
Amortization of debt issuance costs																		0.9						—
Total interest expense – 2028 Notes																		$	8.5					$	—
2029 Notes
Contractual interest expense																		9.4						9.4
Amortization of debt issuance costs																		0.5						0.5
Total interest expense – 2029 Notes																		$	9.9					$	9.9

Wisconsin Electric Power Company

In March 2026, WE issued $300.0 million of 5.65% Debentures, due March 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Public Service Corporation

In January 2026, WPS issued $300.0 million of 4.25% Senior Notes, due January 15, 2031, and used the net proceeds to repay short-term debt and for other general corporate purposes.

The Peoples Gas Light and Coke Company

PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued tax exempt bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued $100.0 million of collateralized First Mortgage Bonds. In February 2026, PGL provided notice of its intent to redeem in full all $50.0 million of its First and Refunding Mortgage Bonds, Series VV and all of its $50.0 million First and Refunding Mortgage Bonds, Series ZZ. In addition, notices of redemption for all $50.0 million of the related 3.90% Illinois Finance Authority Gas Supply Refunding Revenue Bonds, Series 2010 due March 1, 2030 and all $50.0 million of the 4.00% Illinois Finance Authority Gas Supply Refunding Revenue Bonds, Series 2013A due February 1, 2033 were issued. In March 2026, all redemptions were made.

NOTE 11—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:

(in millions)						March 31, 2026						December 31, 2025
Materials and supplies						$	425.5					$	416.4
Fossil fuel						94.4						94.5
Natural gas in storage						92.4						292.5
Total						$	612.3					$	803.4

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, 2026, we had a temporary LIFO liquidation credit of $44.6 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 12—INCOME TAXES

Statutory Rate Reconciliation

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, 2026												Three Months Ended March 31, 2025
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Income before income taxes						$	859.2											$	786.2
United States federal statutory income tax rate						$	180.1					21.0		%				$	164.8					21.0		%
State and local income taxes net of federal tax effect (1)						49.3						5.8		%				48.5						6.2		%
Tax credits
PTCs, net (2)						(129.7)						(15.1)		%				(120.1)						(15.3)		%
Other						(3.9)						(0.5)		%				(3.3)						(0.4)		%
Nontaxable or nondeductible items
AFUDC-Equity (3)						(19.1)						(2.2)		%				(8.5)						(1.1)		%
Other						5.8						0.7		%				3.4						0.4		%
Changes in unrecognized tax benefits						—						—		%				0.1						—		%
Other adjustments
Federal excess deferred tax amortization (4)						(18.5)						(2.2)		%				(18.7)						(2.4)		%
Other, net						(10.9)						(1.3)		%				(5.5)						(0.7)		%
Total income tax expense						$	53.1					6.2		%				$	60.7					7.7		%

(1)    State taxes in Wisconsin made up the majority of the tax effect in this category.

(2)    PTCs are an inflation adjusted United States federal income tax credit for each kilowatt hour of electricity generated by certain renewable energy projects.

(3)    AFUDC-Equity represents the cost of capital (i.e. ROE) that is added to the construction cost of an asset while it is being built. The tax benefit for regulated utilities from AFUDC-Equity is a regulatory gross-up to allow the recovery of income taxes on the equity portion of construction costs, even though it is not a tax deductible expense.

(4)    The Tax Cuts and Jobs Act of 2017 required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018, in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

The IRA contains a tax credit transferability provision that allows us to sell PTCs and ITCs produced after December 31, 2022, to third parties. Under this transferability provision, we entered into agreements to sell the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties. We have also entered into an agreement to sell the majority of PTCs that we expect to generate in 2026 to third parties. 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 and ITCs. 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.

There were no income taxes paid or received during the three months ended March 31, 2026 and 2025.

NOTE 13—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, 2026
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	2.6					$	4.9					$	—					$	7.5
FTRs						—						—						2.3						2.3
Total derivative assets						$	2.6					$	4.9					$	2.3					$	9.8
Investments held in rabbi trust						$	37.6					$	—					$	—					$	37.6
Derivative liabilities
Natural gas contracts						$	32.4					$	3.3					$	—					$	35.7
FTRs						—						—						0.4						0.4
Total derivative liabilities						$	32.4					$	3.3					$	0.4					$	36.1

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						December 31, 2025
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	1.5					$	18.3					$	—					$	19.8
FTRs						—						—						6.5						6.5
Total derivative assets						$	1.5					$	18.3					$	6.5					$	26.3
Investments held in rabbi trust						$	42.0					$	—					$	—					$	42.0
Derivative liabilities
Natural gas contracts						$	23.3					$	8.4					$	—					$	31.7
FTRs						—						—						0.8						0.8
Total derivative liabilities						$	23.3					$	8.4					$	0.8					$	32.5

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, 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.

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. For the three months ended March 31, 2026 and 2025, the net unrealized losses included in earnings related to the investments held at the end of the period were $1.7 million and $1.8 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)						2026						2025
Balance at the beginning of the period						$	5.7					$	7.8
Purchases						—						1.2
Net realized and unrealized losses included in earnings (1)						—						(0.3)
Sales						(0.3)						—
Settlements						(3.5)						(5.7)
Balance at the end of the period						$	1.9					$	3.0

(1)Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized 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, 2026												December 31, 2025
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock of subsidiary						$	30.4					$	21.6					$	30.4					$	21.2
Long-term debt, including current portion						19,902.2						19,401.8						20,017.5						19,609.1

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

NOTE 14—DERIVATIVE INSTRUMENTS

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

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

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, 2026												December 31, 2025
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	7.4					$	33.6					$	19.7					$	30.0
FTRs						2.3						0.4						6.5						0.8
Total current						9.7						34.0						26.2						30.8
Long-term
Natural gas contracts						0.1						2.1						0.1						1.7
Total						$	9.8					$	36.1					$	26.3					$	32.5

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 realized gains and losses and the estimated notional volumes related to these settlements were as follows:

						Three Months Ended March 31, 2026												Three Months Ended March 31, 2025
(in millions)						Volumes						Gains						Volumes						Gains (Losses)
Natural gas contracts						63.0 Dth						$	29.6					61.5 Dth						$	(1.9)
FTRs and TCRs
Regulated utility operations						5.8 MWh						1.7						7.1 MWh						1.7
Non-utility operations						0.1 MWh						0.1						0.3 MWh						(0.2)
Total												$	31.4											$	(0.4)

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, 2026 and December 31, 2025, we had posted cash collateral of $68.2 million and $41.4 million, respectively. These amounts were recorded on our balance sheets in other current assets. At March 31, 2026, we had also received cash collateral of $2.5 million. This amount was recorded on our balance sheet in other current liabilities.

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

						March 31, 2026												December 31, 2025
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Gross amount recognized on the balance sheet						$	9.8					$	36.1					$	26.3					$	32.5
Gross amount not offset on the balance sheet						(3.4)						(33.2)			(1)			(2.0)						(23.8)			(2)
Net amount						$	6.4					$	2.9					$	24.3					$	8.7

(1)Includes cash collateral posted of $29.8 million.

(2)Includes cash collateral posted of $21.8 million.

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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, 2026 and 2025 were not significant. At March 31, 2026, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 15—GUARANTEES

The following table shows our outstanding guarantees:

						Total Amounts Committed at March 31, 2026						Expiration
(in millions)												Less Than 1 Year						1 to 3 Years						Over 3 Years
Standby letters of credit (1)									$	177.3					$	18.7					$	32.9					$	125.7
Surety bonds (2)						46.4						45.4						1.0						—
Other guarantees (3)						10.4						—						—						10.4
Total guarantees						$	234.1					$	64.1					$	33.9					$	136.1

(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.

NOTE 16—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)																		2026						2025
Service cost																		$	6.1					$	5.7
Interest cost																		28.6						30.3
Expected return on plan assets																		(42.8)						(44.1)
Amortization of net actuarial loss																		10.4						13.6
Net periodic benefit cost																		$	2.3					$	5.5

															OPEB Benefits
												Three Months Ended March 31
(in millions)																		2026						2025
Service cost																		$	3.1					$	2.8
Interest cost																		6.7						6.5
Expected return on plan assets																		(14.4)						(13.6)
Amortization of prior service credit																		(1.1)						(3.2)
Amortization of net actuarial gain																		(1.7)						(1.4)
Net periodic benefit credit																		$	(7.4)					$	(8.9)

During the three months ended March 31, 2026, we made contributions and payments of $3.4 million related to our pension plans and $0.4 million related to our OPEB plans. We expect to make contributions and payments of $13.2 million related to our pension

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plans and $2.4 million related to our OPEB plans during the remainder of 2026, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

We utilize escrow accounting for our current pension and OPEB costs, as approved by the PSCW. As of March 31, 2026 and December 31, 2025, our balance sheets included regulatory liabilities of $11.6 million and $14.7 million, respectively, for pension costs and regulatory assets of $13.7 million and $0.7 million, respectively, for OPEB costs. In accordance with our PSCW rate orders, we amortize the related regulatory assets and liabilities. The above tables do not reflect any adjustments for the creation or amortization of these regulatory assets and liabilities.

NOTE 17—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, 2026. We had no changes to the carrying amount of goodwill during the three months ended March 31, 2026.

(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, 2026.

Other Indefinite-Lived Intangible Assets

At March 31, 2026 and December 31, 2025, we had $59.1 million and $44.4 million, respectively, of other indefinite-lived intangible assets included in other long-term assets on our balance sheets. These assets consist of $24.1 million of spectrum frequencies, which enable our 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. In October 2025, we entered into an option agreement for exclusive rights to purchase land for future generation development in Wisconsin. We have made two annual option payments and incurred total costs of $29.8 million and $15.1 million as of March 31, 2026 and December 31, 2025, respectively, with a right to exercise our option before December 31, 2030.

Finite-Lived Intangible Assets

At March 31, 2026 and December 31, 2025, we had $18.9 million and $17.4 million, respectively, of finite-lived intangible assets included in other long-term assets on our balance sheets. These assets largely consist of a PPA for Maple Flats Solar Energy Center LLC acquired by WECI in November 2024, with a gross carrying amount of $18.8 million. The PPA will be amortized over a useful life of 15 years and expires in 2039. At March 31, 2026 and December 31, 2025, accumulated amortization related to the intangible asset was $1.7 million and $1.4 million, respectively. Amortization expense related to the intangible asset was not material for the three months ended March 31, 2026 and 2025. Amortization expense to be recorded as a decrease to operating revenues is expected to be $1.3 million in each of the next five years.

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Intangible Liabilities

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

						March 31, 2026																		December 31, 2025
(in millions)						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount
PPAs (1)						$	751.2					$	(191.3)					$	559.9					$	751.2					$	(176.5)					$	574.7
Proxy revenue swap (2)						7.2						(5.1)						2.1						7.2						(4.9)						2.3
Interconnection agreements (3)						4.7						(1.4)						3.3						4.7						(1.4)						3.3
Total intangible liabilities						$	763.1					$	(197.8)					$	565.3					$	763.1					$	(182.8)					$	580.3

(1)    Represents PPAs related to the acquisitions of Blooming Grove Wind Energy Center LLC, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky Wind Energy LLC, Delilah I, and Hardin III expiring between 2030 and 2040. The weighted-average remaining useful life of the PPAs is 10 years. See Note 2, Acquisitions, for more information on recent WECI acquisitions.

(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 three 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 15 years.

Amortization related to these intangible liabilities for the three months ended March 31, 2026 and 2025, was $15.0 million and $13.9 million, respectively. Amortization for the next five years, including amounts recorded through March 31, 2026, is estimated to be:

						For the Years Ending December 31
(in millions)						2026						2027						2028						2029						2030
Amortization to be recorded as an increase to operating revenues						$	59.9					$	59.9					$	59.9					$	59.9					$	59.9
Amortization to be recorded as a decrease to other operation and maintenance						0.2						0.2						0.2						0.2						0.2

NOTE 18—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, 2026
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	2,256.9					$	23.5					$	2,280.4
Add: Earnings from equity method investment						59.2						0.3						59.5
Add: Capital contributions						75.8						—						75.8
Less: Distributions						45.2						1.0						46.2
Balance at end of period						$	2,346.7					$	22.8					$	2,369.5
						Three Months Ended March 31, 2025
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	2,085.1					$	23.8					$	2,108.9
Add: Earnings from equity method investment						50.0						3.6						53.6
Add: Capital contributions						42.3						—						42.3
Less: Distributions						55.8						—						55.8
Balance at end of period						$	2,121.6					$	27.4					$	2,149.0

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

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

												Three Months Ended March 31
(in millions)																		2026						2025
Charges to ATC for services and construction																		$	7.3					$	4.5
Charges from ATC for network transmission services																		129.2						116.7
Refund from ATC related to FERC ROE orders																		2.0						1.4

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

(in millions)						March 31, 2026						December 31, 2025
Accounts receivable for services provided to ATC						$	2.7					$	1.6
Accounts payable for services received from ATC						42.9						38.4
Amounts due from ATC for transmission infrastructure upgrades (1)						37.4						32.2

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

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

												Three Months Ended March 31
(in millions)																		2026						2025
Income statement data
Operating revenues																		$	265.3					$	234.9
Operating expenses																		127.4						116.7
Other expense, net																		43.8						39.1
Net income																		$	94.1					$	79.1

(in millions)						March 31, 2026						December 31, 2025
Balance sheet data
Current assets						$	156.8					$	137.5
Noncurrent assets						7,826.0						7,590.8
Total assets						$	7,982.8					$	7,728.3
Current liabilities						$	486.6					$	839.8
Long-term debt						3,576.6						3,156.3
Other noncurrent liabilities						679.1						638.9
Members' equity						3,240.5						3,093.3
Total liabilities and members' equity						$	7,982.8					$	7,728.3

NOTE 19—SEGMENT INFORMATION

Our President and Chief Executive Officer, who is our CODM, reviews financial information presented on a segment basis for purposes of making operating decisions and assessing performance. The CODM regularly reviews net income attributed to common shareholders to measure segment profitability and to allocate resources, including assets, to our businesses. Net income attributed to common shareholders best measures our segment profitability as it reflects all revenues and costs, including the impact on our tax provision from tax credits generated through investments in renewable generation facilities.

Our CODM allocates resources, such as employees, as well as financial and capital resources, to our segments during the annual review of budgets and the capital plan. Our CODM also reviews and revises the resources throughout the year during the monthly forecasting process in order to make timely decisions that align with our overall corporate strategy. The CODM uses each segment's

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net income to evaluate performance by comparing actual results to budgeted and forecasted amounts, as well as the ROE earned for each utility within the various utility segments.

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, equity investment interests, as well as the revenue streams for the products or services provided to customers through electric, natural gas, and renewable operations. See Note 4, Operating Revenues, for more information on disaggregation of operating revenues, including intercompany eliminations. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies, in our 2025 Annual Report on Form 10-K.

At March 31, 2026, we reported six segments, which are described below. All of our operations are located within the United States.

•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. See Note 18, Investment in Transmission Affiliates, for more information on ATC and ATC Holdco.

•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 owns majority interests in multiple renewable generating facilities.

See Note 2, Acquisitions, for more information on WECI's acquisition of Hardin III.

•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.

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The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2026 and 2025:

						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, 2026
External revenues						$	2,338.3					$	749.7					$	257.3					$	3,345.3					$	—					$	88.9					$	—					$	—					$	3,434.2
Intersegment revenues						—						—						—						—						—						121.8						—						(121.8)						—
Fuel and purchased power						449.8						—						—						449.8						—						—						—						—						449.8
Cost of natural gas sold						523.0						275.2						151.7						949.9						—						4.4						—						(13.1)						941.2
Other operation and maintenance						450.2						114.2						29.5						593.9						—						20.5						(4.1)						(1.6)						608.7
Depreciation and amortization						262.7						65.9						13.1						341.7						—						60.7						5.2						(27.8)						379.8
Property and revenue taxes						51.3						11.0						7.0						69.3						—						5.4						—						—						74.7
Equity in earnings of transmission affiliates						—						—						—						—						59.5						—						—						—						59.5
Other income, net (1)						43.1						2.1						—						45.2						—						0.5						10.3						(7.8)						48.2
Interest expense						162.3						22.4						5.3						190.0						3.9						29.7						92.0						(87.1)						228.5
Income tax expense (benefit)						73.7						74.2						13.1						161.0						13.7						(31.5)						(90.1)						—						53.1
Preferred stock dividends of subsidiary						0.3						—						—						0.3						—						—						—						—						0.3
Net income attributed to noncontrolling interests						—						—						—						—						—						(1.4)						—						—						(1.4)
Net income attributed to common shareholders						$	408.1					$	188.9					$	37.6					$	634.6					$	41.9					$	120.6					$	7.3					$	—					$	804.4
Other Segment Disclosures
Three Months Ended March 31, 2026
Capital expenditures and asset acquisitions						$	716.3					$	55.9					$	12.2					$	784.4					$	—					$	27.0					$	6.5					$	—					$	817.9
Balance at March 31, 2026
Equity method investments						18.4						—						—						18.4						2,369.5						—						57.4						—						2,445.3
Total assets (2)						34,246.0						8,048.7						1,714.4						44,009.1						2,369.5						7,746.8						1,320.5						(3,711.9)						51,734.0

(1)    Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2)    Total assets at March 31, 2026 reflect an elimination of $2,592.1 million for all lease activity between We Power and WE.

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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, 2025
External revenues						$	2,059.9					$	788.3					$	227.1					$	3,075.3					$	—					$	74.2					$	—					$	—					$	3,149.5
Intersegment revenues						—						—						—						—						—						120.1						—						(120.1)						—
Fuel and purchased power						390.3						—						—						390.3						—						—						—						—						390.3
Cost of natural gas sold						378.5						288.2						117.6						784.3						—						4.5						—						(13.4)						775.4
Other operation and maintenance						415.1						146.9						28.7						590.7						—						22.1						(3.2)						(1.6)						608.0
Depreciation and amortization						243.6						64.4						12.2						320.2						—						58.2						5.4						(23.9)						359.9
Property and revenue taxes						46.0						20.4						6.5						72.9						—						5.4						0.1						—						78.4
Equity in earnings of transmission affiliates						—						—						—						—						53.6						—						—						—						53.6
Other income, net (1)						17.6						2.1						0.1						19.8						—						0.7						5.0						(7.4)						18.1
Interest expense						161.8						23.2						4.3						189.3						4.8						30.6						86.9						(88.6)						223.0
Income tax expense (benefit)						82.0						69.2						14.8						166.0						11.9						(35.6)						(81.6)						—						60.7
Preferred stock dividends of subsidiary						0.3						—						—						0.3						—						—						—						—						0.3
Net income attributed to noncontrolling interests						—						—						—						—						—						(1.0)						—						—						(1.0)
Net income (loss) attributed to common shareholders						$	359.9					$	178.1					$	43.1					$	581.1					$	36.9					$	108.8					$	(2.6)					$	—					$	724.2
Other Segment Disclosures
Three Months Ended March 31, 2025
Capital expenditures and asset acquisitions						$	616.9					$	53.8					$	17.8					$	688.5					$	—					$	414.6					$	4.1					$	—					$	1,107.2
Balance at March 31, 2025
Equity method investments						16.3						—						—						16.3						2,149.0						—						68.6						—						2,233.9
Total assets (2)						30,836.9						8,344.2						1,638.1						40,819.2						2,159.4						7,886.4						1,243.2						(3,876.1)						48,232.1

(1)    Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2)    Total assets at March 31, 2025 reflect an elimination of $2,648.6 million for all lease activity between We Power and WE.

NOTE 20—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.

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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 use of securitization to recover $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 do not have any recourse to WE or any of WE's affiliates.

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

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

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

(in millions)						March 31, 2026						December 31, 2025
Assets
Other current assets (restricted cash)						$	4.6					$	2.0
Regulatory assets						65.5						67.5
Other long-term assets (restricted cash)						0.6						0.6
Liabilities
Current portion of long-term debt						9.3						9.3
Accounts payable						0.1						0.1
Accrued interest						0.4						0.1
Long-term debt						67.4						67.4

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, 2026 and December 31, 2025, our equity investment in ATC was $2,346.7 million and $2,256.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since

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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, 2026 and December 31, 2025, our equity investment in ATC Holdco was $22.8 million and $23.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 18, 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 21—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, 2026, including those of our subsidiaries, were approximately $11.8 billion.

Environmental Matters

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

Federal Deregulatory Actions

In March 2025, the EPA announced a large-scale deregulatory effort that will likely take multiple years to complete. Of the proposed deregulatory actions, those that apply to us include actions impacting the Good Neighbor Rule, MATS, the PM2.5 Standard, the GHG Power Plant Rule, the Mandatory Greenhouse Gas Reporting Rule, the ELG, and the CCR Rule. Any EPA actions will require formal rulemaking proceedings and are likely to be subject to legal challenges. We continue to monitor and evaluate these deregulatory actions for potential risks and benefits.

In February 2026, the EPA published a final rule rescinding the 2009 declaration that determined that CO2 and other GHGs endanger public health and welfare. The "endangerment finding" has been the legal underpinning of a host of climate regulations under the CAA. Litigation over the rule has been initiated in the D.C. Circuit Court of Appeals.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

In 2023, the EPA issued a final Good Neighbor Rule, which required significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. In June 2024, the rule was stayed by the Supreme Court with respect to the specific applicant states, pending ongoing judicial review.

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In response to the Supreme Court's order, in November 2024, the EPA administratively stayed the effectiveness of the Good Neighbor Rule through an interim final rule which extends a stay to all states to which the rule originally applied, including states in which we operate. The interim final rule also includes provisions to ensure that covered facilities in states with previously established requirements to mitigate interstate air pollution with respect to the 2008 ozone NAAQS will remain subject to equivalent requirements while the Good Neighbor Rule's effectiveness is stayed. Regardless of the outcome, we believe we are well positioned to comply with either standard. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

The EPA issued the MATS rule to limit emissions of mercury, acid gases, and other hazardous air pollutants. In May 2024, the EPA finalized amendments to the MATS rule (the "2024 Amendments") which among other things, lowered the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu.

In February 2026, the EPA issued a final rule effective April 27, 2026, repealing the 2024 Amendments. The final rule reverts back to the prior PM limit of 0.03 lb/MMBtu and eliminates the requirement of continuous emissions monitoring of PM emissions.

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. The EPA's initial ozone nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 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 based on the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 2022.

After the most recent evaluation, the EPA issued a final rule in December 2024 that determined that parts of Southeast Wisconsin failed to attain 2015 ozone NAAQS and consequently would be reclassified from "moderate" to "serious," effective January 2025.

In February 2025, the State of Wisconsin filed a petition for review of this reclassification in the United States Court of Appeals for the Seventh Circuit. Wisconsin subsequently moved for a stay of the reclassification, which was granted in September 2025, pending the Court's review. This means that Southeast Wisconsin has returned to "moderate" status while the underlying lawsuit proceeds.

A nonattainment status of "serious" could have a material adverse effect on future permitting activities for our facilities in applicable locations, including additional costs associated with more strenuous emission control requirements or the need to purchase emission reduction credits.

Particulate Matter

All counties within our service territories are currently in attainment with current 2012 NAAQS for PM2.5. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS from 12 µg/m3 to 9 µg/m3 (the "2024 PM2.5 Standard"). In February 2025, the Wisconsin Department of Natural Resources submitted a State Implementation Plan to the EPA recommending Wisconsin be designated as an attainment area under the 2024 PM2.5 Standard. The EPA has not yet issued its attainment designations and has indicated it may extend the designation period by 1 year due to a lack of adequate air monitoring data. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect the 2024 PM2.5 Standard to have a material impact on our units.

In November 2025, the EPA filed a motion with the D.C. Circuit Court of Appeals to vacate the 2024 PM2.5 Standard. The 2024 PM2.5 Standard remains in effect while the motion is being considered. In April 2026, the State of Wisconsin signed onto a complaint filed in California that seeks an order directing the EPA to implement the 2024 PM2.5 Standard and make nonattainment designations. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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New Source Performance Standards

Nitrogen Oxides

In January 2026, the EPA released a final rule regulating NOx for CTs constructed, modified, or reconstructed after December 13, 2024. The final rule became effective January 15, 2026, and established NOx emissions standards for several subcategories of new, modified, and reconstructed CTs based on the size, rates of utilization, design efficiency, and fuel type of these turbines. We believe the CTs included in our capital plan will be well positioned to comply with this rule. The existing simple cycle CTs will require more stringent NOx limits if they undergo upgrades.

Climate Change

Pursuant to the final GHG Power Plant Rule, there are no applicable GHG emission standards for coal plants until the end of 2031. Thereafter, the applicable standard is dependent upon the unit's retirement date. Numerous parties have challenged the GHG Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals, and it is being held in abeyance at the request of the parties.

In March 2024, the EPA announced it had removed regulations on existing natural gas CTs from the rule. At that time, the EPA indicated it would work on new rulemaking in phases, focusing on CO2 emissions, as well as NOx and hazardous air pollutants emissions. See New Source Performance Standards - Nitrogen Oxides above for a discussion of the EPA's recent actions addressing NOx.

In June 2025, the EPA issued a proposed rule that contains a primary and an alternative proposal which, depending on the version that is finalized, would result in either a broad repeal of GHG emissions standards or a more narrow repeal of the rule's carbon capture and storage requirements. We do not expect either alternative to have any impact on our current capital plan. Any final rule would likely be subject to litigation. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, which includes updates to the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. In its current form, the rule will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the current form of this rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities; however, as part of the Federal Deregulatory Actions discussed above, in September 2025, the EPA released a proposal to amend the GHG Reporting Program to permanently remove program obligations for most source categories, including our generation facilities. The EPA is also proposing to suspend program reporting requirements that would be applicable to our underground storage, LNG, and transmission affiliates until 2034. We continue to monitor the status of these deregulatory actions.

Our capital plan includes the planned retirement of older, fossil-fueled generation, to be replaced with natural gas-fired generation and zero-carbon-emitting renewables. We have retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018. We expect to retire approximately 900 MWs of additional coal-fired generation by the end of 2031. In conjunction with our new capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2029, and continue to evaluate the conversion of both units to natural gas. See Note 7, Property, Plant, and Equipment, for more information related to Columbia Units 1 and 2 and our planned power plant retirements. We have a long-term goal to achieve net carbon-neutral electric generation by the end of 2050. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. As part of our path toward this goal, we started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4 in 2025. We expect to use coal only as a backup fuel by the end of 2030 and to be in a position to eliminate coal as an energy source by the end of 2032.

We also continue to focus on methane emission reductions by improving and upgrading our natural gas distribution systems and using RNG throughout our natural gas utility systems.

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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

The Clean Water Act Cooling Water Intake Structure Rule 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.

Other than OCPP Units 7 and 8, we have received final or interim BTA determinations for all generation facilities where applicable. We believe existing technology at OCPP Units 7 and 8 also meets the rule requirements for BTA and anticipate that the units will receive that determination when their Wisconsin Pollutant Discharge Elimination System permit is reissued, which is expected in 2026.

Steam Electric Effluent Limitation Guidelines

The EPA's 2024 Supplemental ELG Rule (the "2024 ELG Rule") established ZLD requirements for bottom ash transport water, flue gas desulfurization, and CRL wastewaters at coal-fueled facilities. The 2024 ELG Rule also established a new subcategory, providing an alternative compliance pathway for facility owners that commit to the PCCC at a particular facility by December 31, 2034. In exchange for this commitment, ZLD technologies will not be required and less stringent standards will apply at applicable facilities. The 2024 ELG Rule also allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2034 if needed for reliability concerns (i.e., energy emergencies and reliability must run agreements) as determined by the United States Department of Energy, a public utility commission, or independent system operator. Based on current electric generation resource planning, in December 2025, we filed Notices of Planned Participation to opt into the PCCC subcategory for certain of our past and current coal-fueled facilities.

The EPA published a final rule which became effective March 2, 2026, that extends the deadline for facility owners to opt into a subcategory under the 2024 ELG Rule, allowing them more time to assess potential compliance pathways to continue producing low-cost electricity into the future while meeting wastewater standards.

When the deadline extension rule was proposed, the EPA also solicited public comments related to the economic achievability and technical availability of ZLD technologies. Additional ELG rulemaking is anticipated that may lead to substantive changes to the ZLD technology-based requirements established in the 2024 ELG Rule. Another proposed ELG rule is expected during the first half of 2026 to address CRL treatment requirements.

In addition, numerous parties have challenged the 2024 ELG Rule through litigation in SWEPCO v. U.S. EPA pending in the United States Court of Appeals for the Eighth Circuit, which has been held in abeyance since February 2025. The 2025 deadline extension rule has also been challenged, and the case has been consolidated into the United States Court of Appeals for the Second Circuit. The 2024 ELG Rule, as well as the deadline extension rule, remain in effect during the pendency of the legal challenges. The outcome of these cases may affect our compliance plans.

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. We are working with the EPA as well as various state jurisdictions, as applicable, in our investigation and remediation planning and efforts. These sites are at various stages of investigation, monitoring, remediation, and closure.

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.

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

(in millions)						March 31, 2026						December 31, 2025
Regulatory assets						$	553.6					$	566.0
Reserves for future environmental remediation						474.3						484.1

Coal Combustion Residuals Rule

An EPA rule for CCR that applies to landfills, historic fill sites, and projects where CCR was placed at a power plant site became effective in November 2024. The rule also regulates previously exempt closed landfills.

We anticipate this rule will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. We expect the cost of additional remediation would be recoverable through future rates.

The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. In December 2025, the D.C. Circuit Court of Appeals granted the EPA's motion to extend the ongoing abeyance while the EPA reconsiders certain aspects of the rule. In February 2026, the EPA published a final rule extending certain deadlines and making various corrections to the 2024 CCR rule. In April 2026, the EPA published a rule seeking comments on proposed amendments to the legacy/CCR rule. These amendments include (1) changes to the existing self-implementing regulations; (2) new compliance pathways allowing for site-specific flexibility under a state or federal permit; and (3) changes impacting the definition of CCR beneficial use. The EPA stated its intent is to revise the rule based on public feedback, including technical information submittals, and currently plans to publish a new final rule by early 2027. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.

NOTE 22—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides additional information regarding our statements of cash flows:

						Three Months Ended March 31
(in millions)						2026						2025
Cash paid for interest, net of amount capitalized						$	120.5					$	132.4
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						154.4						146.7
Common stock issued for stock-based compensation plans						4.2						3.2
Increase in receivables for corporate-owned life insurance proceeds						0.4						4.0

Cash, Cash Equivalents, and 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, 2026						December 31, 2025
Cash and cash equivalents						$	45.6					$	27.6
Restricted cash included in other current assets						33.2						9.1
Restricted cash included in other long-term assets						28.5						34.2
Cash, cash equivalents, and restricted cash						$	107.3					$	70.9

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Our restricted cash primarily 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, WEC Infrastructure Energy Holding III 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 in order to fund future decommissioning.

NOTE 23—REGULATORY ENVIRONMENT

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

2027 and 2028 Rate Cases

On April 1, 2026, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2027 and January 1, 2028. The requests reflected the following:

						WE												WPS												WG
Proposed 2027 rate increase
Electric (2)						$	175.8	million	/			4.7%						$	86.1	million	/			6.3%						N/A
Gas						$	2.1	million	/			0.3%			(3)			$	21.7	million	/			4.9%						$	59.4	million	/			6.8%
Steam						$	0.1	million	/			0.2%						N/A												N/A
Proposed 2028 rate increase (1)
Electric (2)						$	179.5	million	/			4.5%						$	50.8	million	/			3.5%						N/A
Gas						$	33.3	million	/			4.9%			(3)			$	6.9	million	/			1.5%						$	37.2	million	/			4.0%
Steam						$	1.2	million	/			3.8%						N/A												N/A
Proposed ROE						9.9%												9.9%												9.9%
Proposed common equity component average on a financial basis						53.5%												55.0%												53.5%

(1)    The proposed 2028 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2027.

(2)    Amounts reflect the impact to our Wisconsin retail electric operations and exclude any impacts from updated fuel costs.

(3)    Increase excludes the impact of the costs directly assigned to natural gas electric generation facilities.

The primary driver of the requested increases in electric rates is continued capital investments to transition our generation fleet from coal to renewables and natural gas-fueled generation, as well as the related investments in transmission and distribution assets. These capital investments, which will strengthen reliability and help reduce carbon emissions, have either already been approved by the PSCW or are expected to receive PSCW approval before or during 2028. Increased operation and maintenance costs, driven by higher inflation, was also a significant driver of the rate increases.

The requested increases in natural gas rates are driven by our ongoing capital investments in reliability and safety projects, including the previously approved Oak Creek LNG storage facility and the Rochester lateral, as well as the impact from higher inflation on operation and maintenance costs.

The utilities also proposed retaining their respective current earnings sharing mechanisms. Under WE's current earnings sharing mechanism, if WE earns above its authorized ROE: (i) it retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 25 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. Under WPS's and WG's current 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.

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A PSCW decision is expected in the fourth quarter of 2026.

Very Large Customer and Bespoke Resources Tariffs

In March 2025, WE filed an application with the PSCW requesting approval to implement a VLC Tariff and a Bespoke Resources Tariff. The PSCW verbally approved the tariffs, with modifications, at its open meeting on April 24, 2026. Under these inter-connected tariffs, VLCs (customers with new demand exceeding 100 MWs, such as large data centers) will have access to reliable power to meet their needs and will directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them and operating and transmission costs allocated to their usage. The tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

The two new tariffs will work in tandem as VLCs will be required to sign a service agreement and subscribe to a portion of one or more "Bespoke Resources," including renewable generation facilities, battery storage, and natural gas generation units. Under these agreements, if a VLC terminates or downsizes its plans, it will still be required to pay for the Bespoke Resources and dedicated distribution facilities that have been built to support its forecasted load, unless the facilities can be repurposed, subject to PSCW approval. Service agreements under the Bespoke Resources Tariff will be effective for the depreciable life of a company-owned generation resource, except for wind and solar resources which will have a term of 20 years. The ROE, which may range from 10.48% to 10.98% as agreed upon with the customer, and the equity ratio of 57% will both be fixed for the entire term of the agreement. The revenue and costs recovered through the tariffs will be excluded from future rate case proceedings and earnings sharing mechanisms.

We expect a final written order from the PSCW by the end of May 2026. WE requires VLCs to enter into payment and cancellation agreements which obligate the VLC to reimburse WE for all costs associated with projects, including any associated costs incurred by ATC for transmission infrastructure projects, requested by the customer until service agreements are executed under the approved tariffs. Reimbursement is required if, among other things, the VLC terminates the payment and cancellation agreement or reduces its anticipated load, or regulatory approval is not received for the construction of a project.

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

2026 Rate Application

In January 2026, PGL and NSG filed requests with the ICC to increase their natural gas base rates. They are requesting rate increases of $201.3 million (20.95%) and $12.7 million (12.2%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL's rate request includes the estimated revenue requirements associated with its PRP projects. As discussed below, projects completed under PGL's PRP are to meet the ICC's directive to retire all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. PGL's rate request includes the revenue requirements associated with approximately $360 million of capital investments planned under its PRP in 2027. Higher operating costs, driven by inflation, and increases in the cost of capital, also drove the requested rate increases. Both companies are requesting an ROE of 10.10% and a common equity component average of 54.0%.

An ICC decision is anticipated in the fourth quarter of 2026, with new rates expected to be effective by January 1, 2027.

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.

In November 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 that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.

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•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.

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 projects to upgrade its natural gas delivery system until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 2023 written orders. The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of projects to upgrade PGL's natural gas delivery system that started in 2023 and emergency repairs needed to ensure the safety and reliability of the delivery system. In May 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement.

In June 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 2023 and May 2024 orders; however, the Illinois Appellate Court affirmed these orders and the related disallowances in March 2026. PGL and NSG petitioned the Illinois Supreme Court on April 14, 2026 seeking review and reversal of these orders.

In accordance with the November 2023 rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure. In February 2025, the ICC issued an order setting expectations for PGL's prospective operations. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute. PGL is working to retire this cast and ductile iron pipe through its PRP. Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases. In addition, the program will be overseen by a safety monitor hired by the ICC. As discussed above, PGL initiated a general rate case proceeding in January 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated with the PRP.

Illinois Riders

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. As of March 31, 2026, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years will be deemed recoverable by the ICC. Future disallowances by the ICC could be material. 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. However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

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 August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL subsequently filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order; however, in January 2026, PGL filed an unopposed motion to stay the appeal, which was granted by the court.

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PGL's QIP reconciliations from 2017 through 2023 are still pending. Future disallowances by the ICC could be material. The aggregate capital costs included in the rider during the open reconciliation years, along with any previously recognized return on these investments, totaled approximately $3.0 billion as of March 31, 2026. However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement

In February 2026, PGL and NSG agreed on the terms of a proposed settlement with the Illinois Attorney General that, if approved by the ICC, would resolve all open proceedings related to the UEA and QIP riders. ICC staff and the Illinois Citizens Utility Board also subsequently agreed with the terms of the settlement. On April 28, 2026, we filed the settlement for approval by the ICC.

Under the terms of the proposed settlement, PGL and NSG agreed to refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a period of three years between 2026 and 2028 to resolve the open UEA proceedings. In order to resolve the open QIP proceedings, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a period of three years between 2026 and 2028. As a result of this agreement, we recorded a $205.0 million charge to income during the fourth quarter of 2025. The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $75.0 million reduction to revenues. The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at March 31, 2026 is $255.0 million. This includes the $205.0 million charge to income recorded during the fourth quarter of 2025 and a $50.0 million charge to income recorded in years prior to 2025. This proposed settlement is subject to ICC approval following a public review process.

Michigan Gas Utilities Corporation

2026 Rate Application

In December 2025, MGU provided notification to the MPSC of its intent to file an application requesting an increase to its natural gas rates. MGU subsequently determined that it no longer intends to file a rate case as initially indicated and withdrew its filing announcement with the MPSC in March 2026.

Upper Michigan Energy Resources Corporation

Amended Renewable Energy Plan

In accordance with Michigan Public Act 235, UMERC filed an AREP with the MPSC in February 2025. UMERC's AREP addressed its compliance with the Act 235 renewable portfolio standards and its proposal to recover the projected compliance costs through an incremental renewable energy surcharge. The projected compliance costs included the purchase of Michigan-sourced renewable energy credits and the revenue requirements for UMERC's previously approved investment in Renegade, a 100 MW utility-scale solar-powered electric generating facility, and any other incremental renewable generation resources required to meet the Act 235 renewable portfolio standards. In December 2025, the MPSC issued an order denying UMERC's AREP and requiring UMERC to file a new AREP by October 15, 2026.

Renegade achieved commercial operation in March 2026. The estimated cost of Renegade is approximately $226 million. As UMERC's proposal to recover the annual revenue requirement of Renegade through a renewable energy surcharge was denied, UMERC subsequently filed a request for deferral accounting treatment. On April 17, 2026, the MPSC issued an order authorizing UMERC to defer all of the costs associated with owning and operating Renegade. The costs will be reviewed for recovery in a future proceeding.

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NOTE 24—OTHER INCOME, NET

Total other income, net was as follows for the three months ended March 31:

(in millions)						2026						2025
AFUDC-Equity						$	44.0					$	17.3
Earnings (losses) from equity method investments (1)						2.3						(2.6)
Interest income						1.1						3.3
Losses from investments held in rabbi trust						(1.4)						(0.8)
Other, net						2.2						0.9
Other income, net						$	48.2					$	18.1

(1)    Amounts do not include equity earnings of transmission affiliates as those earnings are shown as a separate line item on the income statements.

NOTE 25—NEW ACCOUNTING PRONOUNCEMENTS

Improvements to Interim Reporting

In December 2025, the FASB issued ASU No. 2025-11, Interim Reporting (Topic 270) Narrow-Scope Improvements. The amendments clarify interim disclosure requirements and the applicability of Topic 270. The amendments include a comprehensive list of interim disclosures that are currently required under GAAP. The amendments also include a disclosure principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. Finally, the amendments clarify the types of interim reporting and the form and content of interim financial statements in accordance with GAAP. The amendments are effective for interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Accounting for Government Grants

In December 2025, the FASB issued ASU No. 2025-10, Government Grants (Topic 832) Accounting for Government Grants Received by Business Entities. The amendments establish the accounting for a government grant received by a business entity, including guidance for a grant related to an asset and a grant related to income. The amendments also require disclosures, including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. The amendments are effective for annual periods beginning after December 15, 2028, and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) Disaggregation of Income Statement Expenses. The amendments require disclosure of certain costs and expenses in the notes to financial statements, which are disaggregated from relevant expense captions on the income statement. The amendments also require additional qualitative disclosures of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. Finally, the amendments require disclosure of the total amount of selling expenses and, in annual reporting periods, an entity's definition of selling expenses. The amendments are effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2027, 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 2025 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 the 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

We are working to build and sustain long-term value for our shareholders and customers by supporting economic growth in our region while focusing on the fundamentals of our business: reliability, operating efficiency, financial discipline, environmental stewardship, exceptional customer care, and safety. Our capital plan provides a roadmap for us to achieve this goal. It is a plan premised upon maintaining superior reliability, delivering savings for customers, and growing 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.

Supporting Economic Growth Within Our Communities

Economic growth continues in our Wisconsin service territories. Companies are investing in major projects, including data centers and modern manufacturing facilities. We anticipate electric demand growth in the years ahead from these economic developments. Microsoft has announced plans to invest over $20 billion in data centers in southeastern Wisconsin over the next several years, and we expect up to 2.6 GWs of load growth in the Milwaukee-to-Chicago corridor through 2030. Additionally, Vantage Data Centers plan to develop a large data center campus in Port Washington that is forecasted to add 1.3 GWs of demand through 2030. This site has the potential to add an incremental 2.2 GWs, for a total of up to 3.5 GWs over time. We are working closely with these large customers to provide power to meet this substantial projected demand. On April 24, 2026, we received verbal approval from the PSCW for new VLC and Bespoke Resources tariffs. These tariffs specifically address the unique needs of VLCs while protecting our other customers and shareholders. See Note 23, Regulatory Environment, for more information on the VLC and Bespoke Resources tariffs.

To meet the forecasted electric demand growth in the years ahead, greater capacity will be required to provide affordable, reliable, and clean energy for our communities. Our capital plan addresses that demand with a range of planned investments in natural gas-fired generation, renewables, and battery storage. We plan on investing approximately $5.4 billion from 2026 to 2030 in a combination of efficient natural gas-fired generation, including:

•3,300 MWs of CTs (we plan on constructing a new natural gas lateral pipeline to support the CTs planned at our OCPP site); and

•180 MWs of reciprocating internal combustion engine natural gas-fueled generation.

We expect to invest approximately $12.6 billion from 2026 to 2030 in regulated renewable energy in Wisconsin. Our plan is to build and own zero-carbon-emitting renewable generation facilities that are anticipated to include the following investments:

•3,850 MWs of utility-scale solar;

•2,130 MWs of battery storage; and

•555 MWs of wind.

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

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Our capital plan also reflects the planned retirement of our older, fossil-fueled generation, which we expect to replace with the natural gas-fired generation and zero-carbon-emitting renewables discussed above. These retirements are intended to address compliance with EPA regulations established under the CAA, as well as contribute to meeting our goal to reduce CO2 emissions from our electric generation. Our long-term goal is to achieve net carbon neutral electric generation by the end of 2050. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. We expect to use coal only as a backup fuel by the end of 2030 and to be in a position to eliminate coal as an energy source by the end of 2032.

As part of our path toward this goal, we have started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4. We and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2029, but continue to evaluate the conversion of both units to natural gas. Additionally, we have retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle Power Plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Generating Station Unit 4 generating unit. We expect to retire approximately 900 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8 and Weston Unit 3. See Note 7, Property, Plant, and Equipment, for more information related to the planned retirement of OCPP Units 7 and 8.

When taken together, the retirements and new investments in natural gas generation and renewables should better balance our supply with our demand, while helping to address compliance and maintaining reliable, affordable energy for our customers.

We also continue to focus on methane emission reductions by improving and upgrading our natural gas distribution systems and using RNG throughout our natural gas utility systems. In 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin. The RNG supplied is replacing higher-emission methane from natural gas that would have entered our pipes. We currently have contracts in place for 2.1 Bcf of RNG.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with our capital 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 of the more significant projects that are proposed, currently underway, or recently completed.

•The PSCW approved WE's request to construct an LNG facility with a storage capacity of two Bcf, which will be located on the OCPP site. In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of our capital plan and would provide another approximately four Bcf of natural gas supply. The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

•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 these projects until the ICC completed a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In a limited-scope rehearing of this order, PGL was authorized spending for completion of projects that had started in 2023. In February 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter of less than 36 inches by January 1, 2035. PGL is working to retire this cast and ductile iron pipe through its PRP. For more information, see Note 23, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceeding – Replacement of Aging Natural Gas Infrastructure.

•Our capital plan includes $2.9 billion of investments in battery energy storage systems from 2026 to 2030, which are intended to capture excess power and release it during peak demand or when power is limited due to weather or other unexpected disruptions.

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

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We expect to spend approximately $7.1 billion and $4.7 billion on reliability related to natural gas and electric distribution projects, respectively, from 2026 to 2030, 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 our capital plan. For example, we are making progress on our advanced metering infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between our utilities and our customers. This program reduces the manual effort for customer connections and enhances outage management capabilities.

Through our multiyear Energy Delivery Program, we are planning to implement capabilities and standard processes for customer service, natural gas and electric operations, work management, and field operations. This includes improvements to outage management, geographic information systems, and work and asset management systems, as well as the implementation of new capabilities through advanced distribution management systems.

We continue to focus on integrating the resources of all our businesses and improving our business processes to find the best and most efficient processes possible, including evaluating the use of AI tools. We expect these efforts to continue to drive operational efficiency and to put us in a position to effectively support plans for future growth.

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 work to earn allowed rates of return through a focus on cost control and strategic investment.

Our planned investment focus from 2026 to 2030 is in our regulated utilities and our investment in ATC. We expect total capital expenditures for our regulated utility businesses to be approximately $33.4 billion from 2026 to 2030. In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $4.1 billion. For additional information regarding projects included in the $37.5 billion capital plan, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 2, Acquisitions, and Note 3, Disposition, for additional information on our 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.

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. To further protect public safety, we monitor the integrity of our distribution systems, have emergency response and business continuity plans in place, and provide key safety information to customers, contractors, and first responders.

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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, 2026

Consolidated Earnings

The following table compares our consolidated results for the first quarter of 2026 with the first quarter of 2025, including favorable or better, "B", and unfavorable or worse, "W", variances:

						Three Months Ended March 31
(in millions, except per share data)						2026						2025						B (W)
Wisconsin						$	408.1					$	359.9					$	48.2
Illinois						188.9						178.1						10.8
Other states						37.6						43.1						(5.5)
Electric transmission						41.9						36.9						5.0
Non-utility energy infrastructure						120.6						108.8						11.8
Corporate and other						7.3						(2.6)						9.9
Net income attributed to common shareholders						$	804.4					$	724.2					$	80.2
Diluted EPS						$	2.45					$	2.27					$	0.18

Earnings increased $80.2 million during the first quarter of 2026, compared with the same quarter in 2025. The $80.2 million increase in earnings was driven by:

•A $48.2 million increase in net income attributed to common shareholders at the Wisconsin segment, primarily due to higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K for more information. Higher AFUDC-Equity and increases in certain income tax benefits also contributed to the higher earnings. These positive impacts were partially offset by higher operating expenses, primarily due to an increase in regulatory amortizations and other pass through expenses, higher depreciation and amortization expense, and an increase in transmission expense.

•An $11.8 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by higher operating income at WECI.

•A $10.8 million increase in net income attributed to common shareholders at the Illinois segment, driven by lower operating expenses, primarily due to the quarter-over-quarter positive impact from a gain on the sale of certain real estate at PGL and a decrease in natural gas distribution and maintenance costs.

Expected 2026 Annual Effective Tax Rate

We expect our 2026 annual effective tax rate to be between 5.5% and 6.5%. 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.

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Non-GAAP Financial Measures

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

We believe that utility margin provides 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 utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders was $408.1 million during the first quarter of 2026, representing a $48.2 million, or 13.4%, increase over the same quarter in 2025. The increase in earnings was primarily due to higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K for more information. Higher AFUDC-Equity and increases in certain income tax benefits also contributed to the higher earnings. These positive impacts were partially offset by higher operating expenses, primarily due to an increase in regulatory amortizations and other pass through expenses, higher depreciation and amortization expense, and an increase in transmission expense.

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operating revenues						$	2,338.3					$	2,059.9					$	278.4
Operating expenses
Cost of sales (1)						972.8						768.8						(204.0)
Other operation and maintenance						450.2						415.1						(35.1)
Depreciation and amortization						262.7						243.6						(19.1)
Property and revenue taxes						51.3						46.0						(5.3)
Operating income						601.3						586.4						14.9
Other income, net						43.1						17.6						25.5
Interest expense						162.3						161.8						(0.5)
Income before income taxes						482.1						442.2						39.9
Income tax expense						73.7						82.0						8.3
Preferred stock dividends of subsidiary						0.3						0.3						—
Net income attributed to common shareholders						$	408.1					$	359.9					$	48.2

(1)    Cost of sales includes fuel and purchased power and cost of natural gas sold.

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

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operation and maintenance not included in line items below						$	174.0					$	179.9					$	5.9
Transmission (1)						161.2						145.9						(15.3)
Regulatory amortizations and other pass through expenses (2)						84.5						57.6						(26.9)
We Power (3)						31.4						32.6						1.2
Earnings sharing mechanisms						(0.9)						(0.9)						—
Total other operation and maintenance						$	450.2					$	415.1					$	(35.1)

(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 2026 and 2025, $164.3 million and $149.0 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3)Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During the first quarter of 2026 and 2025, $34.9 million and $27.1 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

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

						Three Months Ended March 31
Electric Sales Volumes (MWh - in thousands)						2026						2025						B (W)
Customer Class
Residential						2,802.1						2,796.6						5.5
Small commercial and industrial (1)						3,207.4						3,184.6						22.8
Large commercial and industrial (1)						2,968.5						2,853.5						115.0
Other						31.6						33.8						(2.2)
Total retail (1)						9,009.6						8,868.5						141.1
Wholesale						440.5						448.8						(8.3)
Resale						826.6						1,311.5						(484.9)
Total sales in MWh (1)						10,276.7						10,628.8						(352.1)

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

						Three Months Ended March 31
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						526.0						547.8						(21.8)
Commercial and industrial						317.3						333.1						(15.8)
Total retail						843.3						880.9						(37.6)
Transportation						419.4						428.1						(8.7)
Total sales in therms						1,262.7						1,309.0						(46.3)

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						Three Months Ended March 31
Weather (Degree Days) (1)						2026						2025						B (W)
WE and WG
Heating (3,214 Normal)						3,153						3,283						(4.0)		%
WPS
Heating (3,592 Normal)						3,567						3,526						1.2		%
UMERC
Heating (3,913 Normal)						3,869						3,914						(1.1)		%

(1)Normal degree days are based on a 20-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations within each company's respective service territories.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Electric revenues						$	1,443.3					$	1,323.6					$	119.7
Natural gas revenues						895.0						736.3						158.7
Operating revenues						2,338.3						2,059.9						278.4
Operating expenses
Fuel and purchased power						(449.8)						(390.3)						(59.5)
Cost of natural gas sold						(523.0)						(378.5)						(144.5)
Other operation and maintenance (1)						(312.9)						(294.6)						(18.3)
Depreciation and amortization						(262.7)						(243.6)						(19.1)
Property and revenue taxes						(51.3)						(46.0)						(5.3)
Gross margin (GAAP)						738.6						706.9						31.7
Other operation and maintenance (1)						312.9						294.6						18.3
Depreciation and amortization						262.7						243.6						19.1
Property and revenue taxes						51.3						46.0						5.3
Utility margin (non-GAAP)						$	1,365.5					$	1,291.1					$	74.4

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Wisconsin segment increased $31.7 million during the first quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) increased $74.4 million during the first quarter of 2026, compared with the same quarter in 2025. Both measures were driven by:

•A $73.4 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026. See Note 26, Regulatory Environment, in our 2025 Annual Report on Form 10-K, for more information.

•A current return of $4.3 million consisting of carrying costs earned during the construction of certain bespoke resources assigned to our VLCs during the first quarter of 2026.

These increases in margins were partially offset by a $6.6 million decrease related to lower sales volumes, driven by retail natural gas sales, including the impact of warmer weather during the first quarter of 2026, compared with the same quarter in 2025. As measured by heating degree days, the first quarter of 2026 was 4.0% warmer than the same quarter in 2025 in the Milwaukee area.

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Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•A $19.1 million increase in depreciation and amortization expense;

•A $15.3 million increase in transmission expense;

•A $5.3 million increase in property and revenues taxes; and

•A partially offsetting $5.3 million decrease in electric and natural gas distribution expenses.

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

Other operating expenses at the Wisconsin segment increased $59.5 million during the first quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the increase in other operating expenses were:

•A $26.9 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $19.1 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

•A $15.3 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2026. See the notes under the other operation and maintenance table above for more information.

•A $5.3 million increase in property and revenue taxes, driven by gross receipt taxes.

These increases in other operating expenses were partially offset by a $5.3 million decrease in electric and natural gas distribution expenses, driven by lower costs to maintain the distribution systems and for storm damage in the first quarter of 2026 compared with the same quarter of 2025.

Other Income, Net

Other income, net at the Wisconsin segment increased $25.5 million during the first quarter of 2026, compared with the same quarter in 2025, driven by a $26.8 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $0.5 million during the first quarter of 2026, compared with the same quarter in 2025. The increase was primarily due to the impact of long-term debt issuances in 2025 and 2026. Also contributing to the increase was higher average short-term debt balances. These increases were substantially offset by AFUDC-Debt that was $11.2 million higher quarter-over-quarter due to continued capital investment and the impact of long-term debt maturities in 2025.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $8.3 million during the first quarter of 2026, compared with the same quarter in 2025, driven by:

•An $8.0 million increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment;

•A $4.7 million increase in income tax benefits associated with certain regulatory tax deferral items; and

•A $4.6 million increase in PTCs.

Partially offsetting these favorable income tax variances was 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 $188.9 million during the first quarter of 2026, representing a $10.8 million, or 6.1%, increase over the same quarter in 2025. The increase in earnings was driven by lower operating expenses, primarily due to the quarter-over-quarter positive impact from a gain on the sale of certain real estate at PGL and a decrease in natural gas distribution and maintenance costs.

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)						2026						2025						B (W)
Operating revenues						$	749.7					$	788.3					$	(38.6)
Operating expenses
Cost of natural gas sold						275.2						288.2						13.0
Other operation and maintenance						114.2						146.9						32.7
Depreciation and amortization						65.9						64.4						(1.5)
Property and revenue taxes						11.0						20.4						9.4
Operating income						283.4						268.4						15.0
Other income, net						2.1						2.1						—
Interest expense						22.4						23.2						0.8
Income before income taxes						263.1						247.3						15.8
Income tax expense						74.2						69.2						(5.0)
Net income attributed to common shareholders						$	188.9					$	178.1					$	10.8

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

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operation and maintenance not included in the line items below						$	68.1					$	83.4					$	15.3
Riders (1)						45.6						62.9						17.3
Regulatory amortizations (1)						0.3						0.6						0.3
Other						0.2						—						(0.2)
Total other operation and maintenance						$	114.2					$	146.9					$	32.7

(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
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						404.1						411.6						(7.5)
Commercial and industrial						151.5						153.4						(1.9)
Total retail						555.6						565.0						(9.4)
Transportation						302.7						324.8						(22.1)
Total sales in therms						858.3						889.8						(31.5)

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						Three Months Ended March 31
Weather (Degree Days) (1)						2026						2025						B (W)
Heating (3,064 Normal)						2,924						3,042						(3.9)		%

(1)Normal heating degree days are based on a 12-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout our Illinois service territories.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Three Months Ended March 31
(in millions)						2026						2025												B (W)
Operating revenues						$	749.7					$	788.3											$	(38.6)
Operating expenses
Cost of natural gas sold						(275.2)						(288.2)												13.0
Other operation and maintenance (1)						(53.6)						(57.7)												4.1
Depreciation and amortization						(65.9)						(64.4)												(1.5)
Property and revenue taxes						(11.0)						(20.4)												9.4
Gross margin (GAAP)						344.0						357.6												(13.6)
Other operation and maintenance (1)						53.6						57.7												(4.1)
Depreciation and amortization						65.9						64.4												1.5
Property and revenue taxes						11.0						20.4												(9.4)
Utility margin (non-GAAP)						$	474.5					$	500.1											$	(25.6)

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) at the Illinois segment decreased $13.6 million during the first quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) decreased $25.6 million during the first quarter of 2026, compared with the same quarter in 2025. Both measures were driven by:

•A $17.3 million decrease in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

•A $9.4 million decrease in revenues associated with the invested capital tax adjustment rider, which was offset in property and revenue taxes and therefore does not have a significant impact on net income. The invested capital tax adjustment rider is a mechanism that allows us to recover or refund the difference between the cost of invested capital tax incurred and the amount collected through base rates.

Additionally, the smaller decrease in gross margin (GAAP) as compared with the decrease in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

•A $9.4 million decrease in property and revenue taxes; and

•A $4.5 million decrease in natural gas distribution and maintenance costs.

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

Other operating expenses at the Illinois segment decreased $23.3 million, net of the $17.3 million impact of the riders referenced above, during the first quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the decrease in other operating expenses were:

•An $11.9 million gain related to the sale of certain real estate owned by PGL. See Note 3, Disposition, for more information.

•A $9.4 million decrease in property and revenue taxes, driven by the invested capital tax.

•A $4.5 million decrease in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure.

Interest Expense

Interest expense at the Illinois segment decreased $0.8 million during the first quarter of 2026, compared with the same quarter in 2025, driven by both lower short-term debt balances and interest rates.

Income Tax Expense

Income tax expense at the Illinois segment increased $5.0 million during the first quarter of 2026, compared with the same quarter in 2025, driven by an increase in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders was $37.6 million during the first quarter of 2026, representing a $5.5 million, or 12.8%, decrease over the same quarter in 2025. The lower earnings were driven by a decrease in margins related to lower retail sales volumes, along with higher interest expense and an increase in depreciation and amortization expense.

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)						2026						2025						B (W)
Operating revenues						$	257.3					$	227.1					$	30.2
Operating expenses
Cost of natural gas sold						151.7						117.6						(34.1)
Other operation and maintenance						29.5						28.7						(0.8)
Depreciation and amortization						13.1						12.2						(0.9)
Property and revenue taxes						7.0						6.5						(0.5)
Operating income						56.0						62.1						(6.1)
Other income, net						—						0.1						(0.1)
Interest expense						5.3						4.3						(1.0)
Income before income taxes						50.7						57.9						(7.2)
Income tax expense						13.1						14.8						1.7
Net income attributed to common shareholders						$	37.6					$	43.1					$	(5.5)

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

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operation and maintenance not included in line item below						$	20.9					$	20.1					$	(0.8)
Regulatory amortizations and other pass through expenses (1)						8.6						8.6						—
Total other operation and maintenance						$	29.5					$	28.7					$	(0.8)

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

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

						Three Months Ended March 31
Natural Gas Sales Volumes (Therms - in millions)						2026						2025						B (W)
Customer Class
Residential						153.8						159.1						(5.3)
Commercial and industrial						95.3						97.0						(1.7)
Total retail						249.1						256.1						(7.0)
Transportation						228.9						222.6						6.3
Total sales in therms						478.0						478.7						(0.7)

						Three Months Ended March 31
Weather (Degree Days) (1)						2026						2025						B (W)
MERC
Heating (3,912 Normal)						3,677						3,898						(5.7)		%
MGU
Heating (3,100 Normal)						3,041						3,006						1.2		%

(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 temperature readings from National Oceanic and Atmospheric Administration weather stations throughout their respective service territories.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operating revenues						$	257.3					$	227.1					$	30.2
Operating expenses
Cost of natural gas sold						(151.7)						(117.6)						(34.1)
Other operation and maintenance (1)						(14.9)						(14.5)						(0.4)
Depreciation and amortization						(13.1)						(12.2)						(0.9)
Property and revenue taxes						(7.0)						(6.5)						(0.5)
Gross margin (GAAP)						70.6						76.3						(5.7)
Other operation and maintenance (1)						14.9						14.5						0.4
Depreciation and amortization						13.1						12.2						0.9
Property and revenue taxes						7.0						6.5						0.5
Utility margin (non-GAAP)						$	105.6					$	109.5					$	(3.9)

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

Gross margin (GAAP) decreased $5.7 million during the first quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) decreased $3.9 million during the first quarter of 2026, compared with the same quarter in 2025. Both measures were driven by a $3.6 million decrease in margins related to lower retail sales volumes, including the impact of weather, during the first quarter of 2026, compared with the same quarter in 2025.

Additionally, the larger decrease in gross margin (GAAP) as compared to the decrease in utility margin (non-GAAP), was driven by a $0.9 million increase in depreciation and amortization expense that is further described in Other Operating Expenses below.

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

Other operating expenses at the other states segment increased $2.2 million during the first quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the increase in operating expenses were:

•A $0.9 million increase in depreciation and amortization expense related to continued capital investment.

•A $0.8 million increase related to MGU's energy optimization program, which provides rebates, incentives, and energy efficiency education to customers.

Interest Expense

Interest expense at the other states segment increased $1.0 million during the first quarter of 2026, compared with the same quarter in 2025, driven by the impact of MERC and MGU issuing long-term debt in April 2025.

Income Tax Expense

Income tax expense at the other states segment decreased $1.7 million during the first quarter of 2026, compared with the same quarter in 2025, driven by lower pre-tax income.

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Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Equity in earnings of transmission affiliates						$	59.5					$	53.6					$	5.9
Interest expense						3.9						4.8						0.9
Income before income taxes						55.6						48.8						6.8
Income tax expense						13.7						11.9						(1.8)
Net income attributed to common shareholders						$	41.9					$	36.9					$	5.0

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $5.9 million during the first quarter of 2026, compared with the same quarter in 2025. This increase in earnings was primarily due to continued capital investment by ATC, partially offset by a $3.6 million gain recognized in March 2025 related to the sale of an investment at ATC Holdco.

Interest Expense

Interest expense at the electric transmission segment decreased $0.9 million during the first quarter of 2026, compared with the same quarter in 2025, due to the maturity of long-term debt.

Income Tax Expense

Income tax expense at the electric transmission segment increased $1.8 million during the first quarter of 2026, compared with the same quarter in 2025, driven by higher pre-tax income.

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

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operating income						$	119.7					$	104.1					$	15.6
Other income, net						0.5						0.7						(0.2)
Interest expense						29.7						30.6						0.9
Income before income taxes						90.5						74.2						16.3
Income tax benefit						(31.5)						(35.6)						(4.1)
Net income attributed to noncontrolling interests						(1.4)						(1.0)						(0.4)
Net income attributed to common shareholders						$	120.6					$	108.8					$	11.8

Operating Income

Operating income at the non-utility energy infrastructure segment increased $15.6 million during the first quarter of 2026, compared with the same quarter in 2025, driven by these items at WECI:

•A $10.1 million improvement in revenue related to lower congestion related costs.

•A $7.9 million positive impact related to the receipt of performance payments in the first quarter of 2026.

•A $2.2 million increase in operating income from a full quarter of operations at Hardin III, which was acquired in February 2025.

These increases in operating income were partially offset by a $5.4 million increase in operation and maintenance expenses due primarily to having higher fixed cost full service agreements in place in 2026 compared to the same period in 2025 when we performed less maintenance due to the cold weather.

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In addition to the above items at WECI, there was a $2.2 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment decreased $0.9 million during the first quarter of 2026, compared with the same quarter in 2025, primarily due to a lower principal balance, as a result of the semi-annual principal payments on long-term debt.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment decreased $4.1 million during the first quarter of 2026, compared with the same quarter in 2025, primarily due to higher pre-tax income.

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

						Three Months Ended March 31
(in millions)						2026						2025						B (W)
Operating loss						$	(1.1)					$	(2.3)					$	1.2
Other income, net						10.3						5.0						5.3
Interest expense						92.0						86.9						(5.1)
Loss before income taxes						(82.8)						(84.2)						1.4
Income tax benefit						(90.1)						(81.6)						8.5
Net income (loss) attributed to common shareholders						$	7.3					$	(2.6)					$	9.9

Other Income, Net

Other income, net at the corporate and other segment increased $5.3 million during the first quarter of 2026, compared with the same quarter in 2025, driven by $1.2 million of net earnings from our equity method investments in technology and energy-focused investment funds during the first quarter of 2026, compared with a $3.2 million net loss during the same quarter in 2025.

Interest Expense

Interest expense at the corporate and other segment increased $5.1 million during the first quarter of 2026, compared with the same quarter in 2025, due to higher average short-term debt balances.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $8.5 million during the first quarter of 2026, compared with the same quarter in 2025. This increase was driven by a $9.9 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 2026, compared with the same quarter in 2025. Partially offsetting this increase in the income tax benefit was a $1.1 million decrease in excess tax benefits recognized related to stock option exercises.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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Cash Flows

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

(in millions)						2026						2025						Change in 2026 Over 2025
Cash provided by (used in):
Operating activities						$	1,218.4					$	1,162.6					$	55.8
Investing activities						(886.4)						(1,101.8)						215.4
Financing activities						(295.6)						40.4						(336.0)

Operating Activities

Net cash provided by operating activities increased $55.8 million during the first quarter of 2026, compared with the same quarter in 2025, driven by:

•A $108.8 million increase in cash from higher overall collections from customers during the first quarter of 2026, compared with the same period in 2025. This increase was driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2026.

•A $19.2 million increase in cash from lower payments for environmental remediation related to work completed on former manufactured gas plant sites during the first quarter of 2026, compared with the same quarter in 2025.

•An $11.9 million increase in cash from lower interest payments during the first quarter of 2026, compared with the same quarter in 2025.

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

•A $50.7 million decrease in cash driven by lower collateral received from counterparties during the first quarter of 2026, compared with the same quarter in 2025.

•An $11.8 million decrease in cash from higher payments for operating and maintenance expenses. During the first quarter of 2026, our payments were higher due to increased transmission costs and operating and maintenance costs related to our We Power generating units, partially offset by a decrease in electric and natural gas distribution expenses.

•A $9.6 million decrease in cash from lower distributions from ATC during the first quarter of 2026, compared with the same quarter in 2025.

Investing Activities

Net cash used in investing activities decreased $215.4 million during the first quarter of 2026, compared with the same quarter in 2025, driven by:

•The acquisition of a 90% ownership interest in Hardin III in February 2025 for $406.1 million, net of cash acquired of $0.2 million. See Note 2, Acquisitions, for more information.

•Proceeds of $21.7 million received from the sale of assets during the first quarter of 2026. There were no proceeds received from the sale of assets during the same quarter in 2025. See Note 3, Disposition, for more information.

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

•A $116.8 million increase in cash paid for capital expenditures during the first quarter of 2026, which is discussed in more detail below.

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•Proceeds of $39.7 million received for the reimbursement of ATC's transmission infrastructure upgrades during the first quarter of 2025. There were no proceeds received for the reimbursement of ATC's transmission infrastructure upgrades during the same quarter in 2026. See Note 18, Investment in Transmission Affiliates, for more information.

•A $33.5 million increase in capital contributions paid to transmission affiliates during the first quarter of 2026, compared with the same quarter in 2025. See Note 18, Investment in Transmission Affiliates, for more information.

Capital Expenditures

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

Reportable Segment (in millions)						2026						2025						Change in 2026 Over 2025
Wisconsin						$	716.3					$	616.9					$	99.4
Illinois						55.9						53.8						2.1
Other states						12.2						17.8						(5.6)
Non-utility energy infrastructure						27.0						8.5						18.5
Corporate and other						6.5						4.1						2.4
Total capital expenditures						$	817.9					$	701.1					$	116.8

The increase in cash paid for capital expenditures at the Wisconsin segment during the first quarter of 2026, compared with the same quarter in 2025, was driven by an increase in capital expenditures for the CTs and LNG at OCPP and renewable energy projects at WE and WPS. These increases in capital expenditures at the Wisconsin segment were partially offset by a decrease in capital expenditures at UMERC for Renegade, which achieved commercial operation in March 2026.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during the first quarter of 2026, compared with the same quarter in 2025, was driven by an increase in capital expenditures related to fuel flexibility projects at ERGS.

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

Financing Activities

Net cash related to financing activities decreased $336.0 million during the first quarter of 2026, compared with the same quarter in 2025, driven by:

•A $1,101.0 million decrease in cash due to increased retirements of long-term debt during the first quarter of 2026, compared with the same quarter in 2025.

•A $104.3 million decrease in cash due to lower issuances of common stock during the first quarter of 2026, compared with the same quarter in 2025. See Note 8, Common Equity, for more information.

•A $90.3 million decrease in cash due to a decrease in net borrowings of commercial paper during the first quarter of 2026, compared with the same quarter in 2025.

•A $26.5 million decrease in cash due to higher dividends paid on our common stock during the first quarter of 2026, compared with the same quarter in 2025. In January 2026, our Board of Directors increased our quarterly dividend by $0.06 per share (6.7%) effective with the March 2026 dividend payment.

•A $13.8 million decrease in cash related to a lower number of stock options exercised during the first quarter of 2026, compared with the same quarter in 2025.

These decreases in cash related to financing activities were partially offset by a $1,005.2 million increase in cash due to the issuance of long-term debt during the first quarter of 2026. No long-term debt was issued during the same quarter in 2025.

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Other Significant Financing Activities

For more information on our other significant financing activities, see Note 8, Common Equity, Note 9, Short-Term Debt and Lines of Credit, and Note 10, Long-Term Debt.

Cash Requirements

We require funds to support and grow our businesses. Our significant cash requirements primarily consist of capital and investment expenditures, payments to retire and pay interest on long-term debt, the payment of common stock dividends to our shareholders, and the funding of our ongoing operations. See the discussion below and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements in our 2025 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects and acquisitions 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 and regulatory 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 21, Commitments and Contingencies.

(in millions)						2026 (1)						2027						2028
Wisconsin						$	4,223.0					$	5,952.5					$	5,949.7
Illinois						566.6						738.4						744.0
Other states						115.0						110.5						125.5
Non-utility energy infrastructure						98.2						132.5						125.0
Corporate and other						15.3						15.6						21.4
Total						$	5,018.1					$	6,949.5					$	6,965.6

(1)This includes actual capital expenditures incurred through March 31, 2026, as well as estimated capital expenditures for the remainder of the year.

We are committed to investing in solar, wind, battery storage, and natural gas-fired generation. In addition, our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability. Below are the anticipated amounts for the next three years for generation, LNG, and distribution projects that are proposed or currently underway.

(in millions)						2026						2027						2028
Generation:
Solar						$	734.3					$	1,693.6					$	1,713.1
Wind						160.9						311.7						654.3
Battery						258.4						413.1						253.5
Thermal						945.7						1,582.7						1,424.5
Other						481.8						309.0						365.8
LNG						178.0						82.0						112.0
Distribution:
Electric distribution						972.2						946.4						973.3
Gas distribution						1,286.8						1,611.0						1,469.1
Total						$	5,018.1					$	6,949.5					$	6,965.6

The DOC set duties on solar panels and cells imported from four southeast Asian countries as well as preliminary duties on imports from Laos, Indonesia, and India. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaints and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the duties set by the DOC and its current investigation, as well as CBP actions, respectively. The forecasted costs identified above already reflect some of these impacts.

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See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Renewable Energy Legislation for potential impacts to our capital projects as a result of the OBBBA.

In accordance with its November 2023 PGL rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and prudent investment level for replacing aging natural gas infrastructure. In February 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter of less than 36 inches by January 1, 2035. PGL is working on retiring this cast and ductile iron pipe through its PRP. Annual investment for pipe replacement is expected to ramp up to approximately $500 million in 2028. For more information on regulatory proceedings related to this matter, see Note 23, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceeding – Replacement of Aging Natural Gas Infrastructure.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $645 million from 2026 through 2028. We do not expect to make any contributions to ATC Holdco during that period. WEC's portion of the investment in MISO Tranche 1 and Tranche 2.1 is estimated to be approximately $700 million and $400 million, respectively, between 2026 and 2030, a portion of which will be funded by ATC's cash from operations. 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. Tranche 2.1 is the second phase of long range transmission planning and builds on the foundation of Tranche 1.

Long-Term Debt

See Note 10, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the three months ended March 31, 2026.

Common Stock Dividends

Our current quarterly dividend rate is $0.9525 per share, which equates to an annual dividend of $3.81 per share. For information related to our most recent common stock dividend declared, see Note 8, Common Equity.

Other Significant Cash Requirements

See Note 21, 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, 2026.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 9, Short-Term Debt and Lines of Credit, Note 15, Guarantees, and Note 20, 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, and common equity. Accessing the capital markets allows us to obtain external short-term borrowings, including commercial paper and term loans, and issue intermediate or long-term debt securities, as well as other types of securities. We also issue common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan, as well as through an at-the-market program.

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Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events. Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions.

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

The amount, type, and timing of any financings for the remainder of 2026, 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 2025 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, we, 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, 2026, our current liabilities exceeded our current assets by $1,408.4 million. We do not expect this to have an impact on our liquidity, as we currently believe that our available capacity under our 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, Common Equity, Note 9, Short-Term Debt and Lines of Credit, and Note 10, Long-Term Debt, for more information about our common stock activity, 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 2025 Annual Report on Form 10-K.

Capitalization Structure

The following table shows our capitalization structure as of March 31, 2026, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our Junior Notes:

(in millions)						Actual						Adjusted
Common shareholders' equity						$	14,131.0					$	14,806.0
Preferred stock of subsidiary						30.4						30.4
Long-term debt (including current portion)						19,902.2						19,227.2
Short-term debt						2,045.2						2,045.2
Total capitalization						$	36,108.8					$	36,108.8
Total debt						$	21,947.4					$	21,272.4
Ratio of debt to total capitalization						60.8		%				58.9		%

Included in long-term debt on our balance sheet as of March 31, 2026, was $600.0 million principal amount of WEC Energy Group's 2025 Junior Notes due 2056 and $750.0 million principal amount of WEC Energy Group's 2024 Junior Notes (2024A Junior Notes and

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2024B Junior Notes, collectively) due 2055. The adjusted presentation attributes $675.0 million of the Junior Notes to common shareholders' equity and $675.0 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 2025 Junior Notes and 2024 Junior Notes by the majority of rating agencies. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At March 31, 2026, 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 2025 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, 2026. 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, 2026, it could have been required to post $109 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 2025 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 and regulatory matters, critical accounting policies and estimates, and other matters.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities. See Note 23, Regulatory Environment, in this report, and Note 26, Regulatory

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Environment, in our 2025 Annual Report on Form 10-K for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Illinois Riders

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. As of March 31, 2026, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years will be deemed recoverable by the ICC. Future disallowances by the ICC could be material. 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. However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Qualifying Infrastructure Plant Rider

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 August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. In October 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order; however, in January 2026, PGL filed an unopposed motion to stay the appeal, which was granted by the court.

PGL's QIP reconciliations from 2017 through 2023 are still pending. Future disallowances by the ICC could be material. The aggregate capital costs included in the rider during the open reconciliation years, along with any previously recognized return on these investments, totaled approximately $3.0 billion as of March 31, 2026. However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement

In February 2026, PGL and NSG agreed on the terms of a proposed settlement with the Illinois Attorney General that, if approved by the ICC, would resolve all open proceedings related to the UEA and QIP riders. ICC staff and the Illinois Citizens Utility Board also subsequently agreed with the terms of the settlement. On April 28, 2026, we filed the settlement for approval by the ICC.

Under the terms of the proposed settlement, PGL and NSG agreed to refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a three year period between 2026 and 2028 to resolve the open UEA proceedings. In order to resolve the open QIP proceedings, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a three year period between 2026 and 2028. As a result of this agreement, we recorded a $205.0 million charge to income during the fourth quarter of 2025. The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $75.0 million reduction to revenues. The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at March 31, 2026 is $255.0 million. This includes the $205.0 million charge to income recorded during 2025 and a $50.0 million charge to income recorded in years prior to 2025. This proposed settlement is subject to ICC approval following a public review process.

Illinois Proceeding - Replacement of Aging Natural Gas Infrastructure

In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its projects to upgrade its natural gas delivery system until the ICC completed 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 in January 2024. In February 2025, the ICC issued an order setting expectations for PGL's prospective operations. The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute. PGL is working to retire this cast and ductile iron pipe through its PRP. Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases. In addition, the

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program will be overseen by a safety monitor hired by the ICC. PGL initiated a general rate case proceeding in January 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated with the PRP.

See Note 23, Regulatory Environment, for more information regarding the 2026 rate case filing and November 2023 ICC rate order.

Uyghur Forced Labor Prevention Act

In June 2022, the CBP implemented the UFLPA, which establishes a rebuttable presumption that certain silica-based products wholly or partially manufactured in the Xinjiang Uyghur Autonomous Region of China, such as polysilicon included in the manufacturing of solar panels, are prohibited from entering the United States. While our suppliers have been able to provide the CBP sufficient documentation to meet the UFLPA compliance requirements, and we expect the same will be true for subsequent projects, 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.

In 2025, the Department of Homeland Security announced the addition of more Chinese businesses to the UFLPA, including several solar supply chain providers. We are working with our contractors and developers to avoid doing business with these companies and remain in compliance with the UFLPA.

United States Department of Commerce Complaints

Starting in June 2024, the DOC began applying duties to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia, with the potential for enhanced duties in certain circumstances, based on final findings by both the DOC and the USITC in their AD/CVD investigations that Chinese manufacturers were shifting products to those four Southeast Asian countries to avoid tariffs on products imported from China.

In April 2025, based upon investigation in response to a new petition, the DOC reached affirmative findings that some Chinese companies had moved their solar operations to avoid penalties imposed in the first investigation, increasing tariff rates, in some cases significantly. These increased rates became effective and enforceable in May 2025 upon the USITC’s final affirmative determination. As a result of these duties, the cost and availability of solar panels in the United States has been impacted and the United States solar industry overall has experienced higher costs of materials as well as delays. Some of these impacts have already been reflected in the estimated cost and in-service dates for certain of our solar projects.

In August 2025, in response to another petition filed by a coalition of trade groups, the DOC and USITC initiated new AD/CVD investigations based on the coalition’s claims that Chinese-owned manufacturers in Laos and Indonesia, as well as India-headquartered companies, are benefiting from illegal subsidies and selling solar products below cost in the United States. In February 2026, the DOC reached affirmative findings in its CVD investigation and released preliminary tariff rates applicable to each country generally, as well as certain specific manufacturers from those countries. In addition, in response to a critical circumstances petition, the DOC further determined that there had been a surge in panels from certain producers in India and from most Indonesian producers prior to the determination, applying tariffs retroactively to imports by such producers that entered the United States up to 90 days before the announcement of the new CVD tariffs. In April 2026, the DOC also issued preliminary affirmative findings in its AD investigation, setting additional rates applicable to these countries. Final AD/CVD rates are scheduled to be released in the fall of 2026, at which time the DOC will begin collecting final tariff amounts. These new tariffs may cause further cost increases or delays in the United States solar industry generally. We are currently assessing these new tariffs for any potential impact on our solar projects.

Renewable Energy Legislation

Infrastructure Investment and Jobs Act

In November 2021, the Infrastructure Investment and Jobs Act was signed into law and provides for approximately $1.2 trillion of federal spending through 2026, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. Funding from this Act supports the work we are doing to reduce GHG emissions and to strengthen and protect the energy grid. In January 2025, disbursement of funds was paused until agency heads can determine whether grants, loans, contracts, and other disbursements are consistent with the current administration's energy policy. In some cases, the pause has disrupted, and could continue to disrupt, funding, temporarily or permanently, for infrastructure projects already in progress,

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may cause project delays and cancellations, and may impact continuing payment obligations for downstream contractors and suppliers.

Inflation Reduction Act

In August 2022, the IRA was signed into law and provides for $258 billion in energy-related provisions over a 10-year period. The IRA has helped reduce our cost of investing in projects that support our commitment to reduce emissions and provide affordable, reliable, and clean energy for our communities. We and our customers have benefited from the IRA’s provisions to extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and allow companies to transfer tax credits generated from renewable projects.

Under the IRA transferability option, we entered into agreements in April 2025 and September 2025 to sell the majority of the PTCs and ITCs we generated, or expect to generate, in 2026 to third parties. See Note 12, Income Taxes, for more information about these sales. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us.

One Big Beautiful Bill Act

In July 2025, the OBBBA was signed into law, enacting significant modifications to clean-energy tax credits previously provided under the IRA. The OBBBA provides companies the ability to earn solar and wind tax credits at current credit rates if construction of projects begins by July 4, 2026, and the projects are placed in-service within four years after beginning construction. However, wind and solar projects that begin construction more than one year after enactment of the OBBBA must be placed in service by December 31, 2027 to qualify for PTCs and ITCs. In addition, wind and solar projects that begin construction after December 31, 2025 must also satisfy prohibited foreign entity material assistance requirements, as defined through proposed guidance by the United States Treasury Department in February 2026. The incentives can also be denied for taxpayers that exceed certain thresholds of equity or debt held by specified foreign entities. The phase out of PTCs and ITCs does not apply to energy storage, hydroelectric facilities, nuclear, or any other zero emission technology. The OBBBA preserves the ability to transfer tax credits, with the exception of transfers to a prohibited foreign entity. In August 2025, the United States Treasury Department implemented new beginning-of-construction safe harbor rules that became effective in September 2025. The capital plan for 2026 through 2030 reflects the impacts of OBBBA, including the revised beginning-of-construction rules.

Environmental Matters

See Note 21, 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 risks described below. In addition, there is continuing uncertainty over the impact of increasing tensions between the United States and other countries and new, protracted or escalating regional and international conflicts 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 2025 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Changes to United States Trade Policy (Tariff Activity)

The United States continues to implement changes to its international trade policy including changes to tariffs, port fees and other policies relating to exports from and imports into the United States. In response to these changes, foreign governments also continue to adjust their trade policies, including the imposition of additional tariffs. There remains significant uncertainty as to the ultimate scope of the United States and foreign trade policies. Both the United States and foreign trade policy changes could increase the cost of materials or disrupt supply chains, which could impact our ability to repair or maintain our infrastructure; the timing, cost or completion of our infrastructure projects; and/or our ability to execute our capital plan. In addition, these changes, including any impact they may have to economic conditions, could lead to reduced energy demand by our customers. Consequently, these policy changes could have a material adverse effect on our business, results of operations and financial condition.

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In addition, we are in the process of evaluating whether we are eligible to seek refunds and/or require our contractors and developers to seek refunds of tariffs paid under the International Emergency Economic Powers Act and other tariff provisions.

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 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 2025 Annual Report on Form 10-K.

•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, inflation, and tariffs.

•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 – The fluctuation in demand for certain commodities and their respective 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 2025 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 13, Fair Value Measurements, Note 14, Derivative Instruments, and Note 15, 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 2026 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 2025 Annual Report on Form 10-K. See Note 21, Commitments and Contingencies, and Note 23, 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 21, Commitments and Contingencies, and Note 23, Regulatory Environment, we currently, and from time to time, are 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.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2025 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, 2026:

Issuer Purchases of Equity Securities
2026						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						16,036						$	105.85					—						$	—
February 1 – February 28						—						—						—						—
March 1 – March 31						—						—						—						—
Total (1)						16,036						$	105.85					—

(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, 2026, 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
4						Instruments Defining the Rights of Security Holders, Including Indentures
						4.1*			Securities Resolution No. 25 of WE, effective as of March 10, 2026, under the Indenture for Debt Securities, dated as of December 1, 1995, between WE and U.S. Bank Trust Company, National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to WE's Form 8-K filed March 13, 2026) (File No. 1-1245.)
						4.2*			Seventeenth Supplemental Indenture, dated as of January 8, 2026, by and between WPS and U.S. Bank Trust Company, National Association (successor to Firstar Bank, Milwaukee, N.A., National Association). (Exhibit 4.1 to Form 8-K filed January 8, 2026) (File No. 1-3016.)
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 7, 2026			William J. Guc
						Vice President and Controller
						(Duly Authorized Officer and Chief Accounting Officer)

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FAQ

How did WEC (WEC) perform financially in Q1 2026?

WEC Energy Group delivered higher earnings in Q1 2026. Operating revenues were $3,434.2 million and net income was $806.1 million, both above the prior year. Diluted EPS increased to $2.45, reflecting growth across electric and natural gas utility operations.

What were WEC (WEC) revenues by major business in Q1 2026?

Total operating revenues reached $3,434.2 million in Q1 2026. Electric utility revenues were $1,433.3 million and natural gas utility revenues were $1,857.8 million, with additional contributions from non‑utility energy infrastructure and other operating revenues across the group.

How strong was WEC (WEC) cash flow and capital spending in Q1 2026?

WEC Energy Group generated $1,218.4 million of net cash from operating activities in Q1 2026. The company invested $817.9 million in capital expenditures and asset acquisitions, mainly in regulated utilities and renewable projects, while modestly increasing cash balances over the period.

What is WEC (WEC) earning per share and dividend level?

For Q1 2026, WEC’s diluted EPS was $2.45, up from $2.27 a year earlier, based on 328.3 million diluted shares. The board declared a quarterly cash dividend of $0.9525 per share, payable June 1, 2026 to shareholders of record on May 14, 2026.

How leveraged is WEC (WEC) based on the March 31, 2026 balance sheet?

At March 31, 2026, WEC reported total assets of $51,734.0 million and long‑term debt, including current portion, of $19,902.2 million. Common shareholders’ equity was $14,131.0 million, reflecting continued infrastructure investment and retained earnings growth across its utility and energy businesses.

What notable financing and debt actions did WEC (WEC) take in early 2026?

In early 2026, WEC repaid $1,000.0 million of maturing 4.75% senior notes and issued $400.0 million of 4.75% senior notes due 2028. Subsidiaries issued new long‑term debt and redeemed certain mortgage bonds, while commercial paper outstanding was $2,040.5 million at March 31, 2026.