2025 Annual Report of 2025

2025 Annual Report

Notice of 2026 Annual Meeting and Proxy Statement

An Energy Industry Leader

WEC Energy Group is one of the nation's leading energy companies, with the operational expertise and financial resources to meet the needs of customers across the Midwest.

We provide vital services to

customers in Wisconsin, Illinois, Michigan and Minnesota.

10-Year Total Shareholder Return

173%

174%

184%

WEC Energy Group consistently delivers among the best total returns in the industry. The illustration demonstrates our stock price appreciation plus the compound effect of dividend growth over the past decade. A $100 investment at the end of 2015 grew to a total value of $284, a 184% return.

$284

$300

$250

$200

$150

$100

Dividends

Philadelphia Utility S&P Utilities

WEC

Stock price

One-year Three-year Five-year Ten-year

10-year total cumulative shareholder return Dec. 31, 2015, through Dec. 31, 2025.

Financial Snapshot

(In millions, except per share data and percentages)

Earnings per share*

Annualized dividends per share

$5.50

$5.00

$4.00

$4.50

$3.50

$4.00

$3.00

$3.50

$2.50

$3.00

$2.00

$2.50

$1.50

′16 ′17 ′18 ′19 ′20 ′21 ′22 ′23 ′24 ′25 '16 '17 '18 '19 '20 '21 '22 '23 '24 '25

GAAP ADJUSTED

GAAP ADJUSTED

GAAP ADJUSTED

GAAP ADJUSTED

GAAP ADJUSTED

$4.81

$5.27

$3.57

*See Appendix A on page P-85 for reconciliation of non-GAAP measures.

As I look back over the past year, I feel more confident than ever in WEC Energy Group's position in our region and our industry.

Our company has a long history of supporting business growth and progress in the communities we serve. In the past few years, we have seen tremendous economic activity in our region, and we are poised

to supply the power needed to transform the future.

Laying the groundwork

In 2025, we continued our track record of strong performance, delivering solid net income and earnings per share. Once again, we returned more cash to shareholders than in any other year in company history. We also increased the dividend by 6.7%

in January 2026 - the 23rd consecutive year of dividend increases.

Our focus on the fundamentals of our business supported a range of achievements across our operations, as well. Overall, our employees recorded their safest year on record as measured by lost-time incidents and days away, restricted or transferred

(DART) incidents. And we continued work on essential system hardening and vegetation management to strengthen our infrastructure.

We executed on our capital plan to expand our generation fleet, delivering affordable, reliable power. In 2025, we brought online Wisconsin's first large-scale battery project, which has already served us well at times of high electric demand. We also received regulatory approval for a range of projects, including more than 1,200 megawatts of natural gas generation now under construction between two sites in Oak Creek and the Town of Paris, Wisconsin.

We look forward to building on that progress in the years ahead.

Powering transformative growth

Our capital plan now includes $37.5 billion of projected investment across our business between 2026 and 2030. This investment will be essential to meet the needs of our customers, including very large businesses bringing significant growth to Wisconsin.

Our time-tested strategy, focused on operational excellence, reliability

and customer service

- coupled with robust economic growth - has shaped our investment plan, setting us on a path toward a bright future.

Scott Lauber

President and Chief Executive Officer

Over the next five years, we expect to see electric demand rise by approximately 45% in our service area. This growth reflects the anticipated impact of local economic development, including major data center projects in Mount Pleasant and Port Washington, Wisconsin, as well as other industries.

This is an unprecedented forecast for our region.

We are prepared to deliver on it, with a strong labor force and supply chain lined up to bring new power generation into service.

An "all of the above" approach is helping us to build a generation fleet that is flexible and dispatchable throughout the year. Through our five-year plan, we expect to invest a total of $7.4 billion in modern,

efficient natural gas generation and liquefied natural gas storage. These projects would include combustion turbines, reciprocating internal combustion engine (RICE) units and upgrades to existing facilities. We also plan to invest $12.6 billion to add 6,500 megawatts of renewable generation and battery storage to our fleet.

American Transmission Co. (ATC) continues to invest in transmission capability to serve our region's economic growth, connect new generation and strengthen the system. We expect to invest approximately $4.1 billion in ATC projects between 2026 and 2030. This is driven by efforts to strengthen the grid, add new generation and facilitate large customer growth.

And to further improve safety and reliability, we're continuing to invest in our electric and natural gas distribution networks, with an expected total investment of $11.8 billion in the plan.

In light of the anticipated economic expansion ahead of us, we are taking steps to protect all of our customers and investors. Our proposed Very Large Customer tariff structure, now under review by the Public Service Commission of Wisconsin, is designed to meet the needs of our very large load customers while also making sure they pay for all power they use and the infrastructure built to serve them.

Over the next five years, we expect to see electric demand rise by approximately 45% in our service area.

Continuing a legacy of excellence

We remain committed to providing our shareholders with a meaningful total return value proposition. We expect our capital investment, along with our continued financial discipline, to support long-term earnings per share growth of 7% to 8% a year, on a compound annual basis, between 2026 and 2030. This is based on the midpoint of our 2025 adjusted guidance.

Our time-tested strategy, focused on operational excellence, reliability and customer service - coupled with robust economic growth - has shaped our investment plan, setting us on a path toward a bright future.

As we look forward, I want to thank Gale Klappa, who will be retiring from our board of directors following our upcoming annual meeting in May, for his 23 years of service to our company. His vision, dedication and leadership have been key in bringing WEC Energy Group to the strong position we are in today.

And on behalf of our entire management team, thank you all for your investment and confidence as we work to empower our region.

Respectfully,

Scott J. Lauber

President and Chief Executive Officer March 6, 2026

Modern, efficient natural gas generation is a key part of our strategy to deliver safe, reliable and affordable power. With plans approved last year, we are building 1,100 megawatts of natural gas capacity at our Oak Creek campus, as well as a liquefied natural gas storage facility and lateral to serve that site. We also are adding fuel flexibility to our Oak Creek "Power the Future" units to allow them to run on natural gas in the years ahead.

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

Bishop Hill III Bishop Hill Energy III LLC

Bluewater Bluewater Natural Gas Holding, LLC

Coyote Ridge Coyote Ridge Wind, LLC

Hardin III Hardin Solar Energy III LLC

Jayhawk Jayhawk Wind, LLC

MERC Minnesota Energy Resources Corporation

NSG North Shore Gas Company

PELLC Peoples Energy, LLC

Samson I Samson Solar Energy LLC

Tatanka Ridge Tatanka Ridge Wind, LLC

UMERC Upper Michigan Energy Resources Corporation

WBS WEC Business Services LLC

We Power W.E. Power, LLC

WECC Wisconsin Energy Capital Corporation

WECI Energy Holding III WEC Infrastructure Energy Holding III LLC

WECI Wind Holding II WEC Infrastructure Wind Holding II LLC

WG Wisconsin Gas LLC

Wisvest Wisvest LLC

WRPC Wisconsin River Power Company

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

ICC Illinois Commerce Commission

MPSC Michigan Public Service Commission

PSCW Public Service Commission of Wisconsin

USITC United States International Trade Commission

WDNR Wisconsin Department of Natural Resources

2024B Junior Notes

WEC Energy Group, Inc.'s Series 2024B 6.74% Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due June 15, 2055

Accounting Terms

AFUDC Allowance for Funds Used During Construction

ARO Asset Retirement Obligation

ASU Accounting Standards Update

FASB Financial Accounting Standards Board

LIFO Last-In, First-Out

VIE Variable Interest Entity

Environmental Terms

Act 141 2005 Wisconsin Act 141

BTA Best Technology Available

CCR Coal Combustion Residual

ELG Steam Electric Effluent Limitation Guidelines

GHG Power Plant Rule 2024 Greenhouse Gas Power Plant Rule

NAAQS National Ambient Air Quality Standards

PCB Polychlorinated Biphenyl

PM2.5 Particulates Less Than 2.5 Micrometers in Diameter

ZLD Zero Liquid Discharge

Measurements

Bcf Billion Cubic Feet

Dth Dekatherm

lb/MMBtu Pound Per Million British Thermal Unit

MW Megawatt

µg/m3 Micrograms Per Cubic Meter

Other Terms and Abbreviations

2007 Junior Notes WEC Energy Group, Inc.'s 2007 Junior Subordinated Notes Due 2067

2024A Junior Notes WEC Energy Group, Inc.'s Series 2024A 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

2028 Notes WEC Energy Group, Inc.'s 3.375% Convertible Senior Notes Due 2028

AD Antidumping

AOC Audit and Oversight Committee of the Board of Directors

ARR Auction Revenue Right

Badger Hollow II Badger Hollow Solar Park II

CABO Clean and Affordable Buildings Ordinance

CEO Chief Executive Officer

Chicago, IL-IN-WI Chicago, Illinois, Indiana, and Wisconsin

Columbia Columbia Energy Center

CSIRT Cybersecurity Incident Response Team

CVD Countervailing Duty

Darien Darien Solar Park

EDA Equity Distribution Agreement

Enterprise Security Director Director of Enterprise Security & Compliance

ERGS Elm Road Generating Station

ER 2 Elm Road Generating Station Unit 2

ETB Environmental Trust Bond

Forward Wind Forward Wind Energy Center

GCRM Gas Cost Recovery Mechanism

Holding Company Act Wisconsin Utility Holding Company Act

IT/OT Information Technology and Operational Technology

Koshkonong Koshkonong Solar Park

LMP Locational Marginal Price

MISO Midcontinent Independent System Operator, Inc.

MRP Main Replacement Program

OBBBA One Big Beautiful Bill Act

OMB Office of Management and Budget

Omnibus Stock Incentive Plan

WEC Energy Group Omnibus Stock Incentive Plan, Amended and Restated, Effective as of May 6, 2021

Paris Paris Solar-Battery Park

PIPP Presque Isle Power Plant

PPA Power Purchase Agreement

PTC Production Tax Credit

Pulliam J. P. Pulliam Generating Station

PWGS 1 Port Washington Generating Station Unit 1

QIP Qualifying Infrastructure Plant

Red Barn Red Barn Wind Park

RICE Reciprocating Internal Combustion Engine

ROE Return on Equity

RTO Regional Transmission Organization

Saratoga Saratoga Solar Electric Generation and BESS Facility

Supreme Court United States Supreme Court

TCR Transmission Congestion Right

Two Creeks Two Creeks Solar Park

UFLPA Uyghur Forced Labor Prevention Act

VLC Very Large Customer

Weston Weston Generating Station

Whitewater Whitewater Cogeneration Facility

WPL Wisconsin Power and Light Company

‌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 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 U.S. 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 U.S. exports, supply chain disruptions (including from rail congestion), inflation, and other factors;

• Risks related to providing service to our data center 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 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 center 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;

• 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.

  ‌BUSINESS OF THE COMPANY

  WEC Energy Group, Inc. was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys Energy Group and changed its name to WEC Energy Group, Inc.

  In this report, when we refer to "WEC Energy Group," "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group, Inc. and all of its subsidiaries. The term "utility" refers to the regulated activities of the electric and natural gas utility companies, while the term "non-utility" refers to the activities of the electric and natural gas companies that are not regulated, as well as We Power and Bluewater. The term "nonregulated" refers to activities at WECI, which holds interests in several renewable generating facilities, and our Corporate and Other Segment.

  Our wholly owned subsidiaries are primarily engaged in the business of providing regulated electricity service in Wisconsin and Michigan; regulated natural gas service in Wisconsin, Illinois, Michigan, and Minnesota; and nonregulated renewable energy. In addition, we have an approximate 60% equity interest in ATC, an electric transmission company operating primarily in four states. At December 31, 2025, we conducted our operations in the six reportable segments discussed below.

  WISCONSIN SEGMENT

  The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC. At December 31, 2025, these companies served approximately 1,696,600 electric customers and 1,545,000 natural gas customers. This segment also includes steam service to approximately 400 WE steam customers in metropolitan Milwaukee, Wisconsin.

  ILLINOIS SEGMENT

  The Illinois segment includes the natural gas utility operations of PGL and NSG. At December 31, 2025, these companies served approximately 1,064,000 natural gas customers located in Chicago and the northern suburbs of Chicago.

  OTHER STATES SEGMENT

  The other states segment includes the natural gas utility operations of MERC and MGU, as well as the non-utility operations of MERC related to servicing appliances for customers. At December 31, 2025, these companies served approximately 444,100 natural gas customers, with MERC serving customers in various cities and communities throughout Minnesota and MGU serving customers in southern and western Michigan.

  ELECTRIC TRANSMISSION SEGMENT

  The electric transmission segment includes our approximate 60% ownership interest in ATC, an electric transmission company regulated by the FERC and certain state regulatory commissions. ATC owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota.

  In addition, we 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.

  NON-UTILITY ENERGY INFRASTRUCTURE SEGMENT

  The non-utility energy infrastructure segment includes We Power, Bluewater, and WECI. We Power, through wholly owned subsidiaries, owns and leases certain generating facilities to WE. Bluewater owns natural gas storage facilities in southeastern Michigan and provides natural gas storage and hub services to WE, WPS, and WG. At December 31, 2025, WECI had controlling ownership interests in 12 non-utility renewable generating facilities, with a combined nameplate generating capacity of 2,654.2 MWs.

  CORPORATE AND OTHER SEGMENT

  The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, and the PELLC holding company, as well as the operations of Wispark and WBS. Wispark develops and invests in real estate, primarily in southeastern Wisconsin. WBS is a wholly owned centralized service company that provides administrative and general support services to our regulated entities, as well as certain administrative and support services to our nonregulated entities.

  Certain of our subsidiaries also hold investments in clean energy investment funds and have engaged in certain financing activities. In addition, this segment also includes Wisvest, WECC, and PDL, which no longer have significant operations.

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

  CORPORATE DEVELOPMENTS

  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 southern 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 plans 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. In 2025, we submitted a proposal to the PSCW for new VLC and Bespoke Resources tariffs. The proposed tariffs specifically address the unique needs of VLCs while protecting our other customers and shareholders. See Note 26, 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 RICE 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.

  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 CO2emissions 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. 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 PIPP, and the 2018 retirements of the Pleasant Prairie power

  plant, the Pulliam power plant, and the jointly-owned Edgewater 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. 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.

  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 examples of the 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 26, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Illinois Proceedings.

• Our capital plan includes $2.9 billion of investments in BESSs 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.

  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.

  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

  The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2025 with the year ended December 31, 2024. For a similar discussion that compares our results for the year ended

  December 31, 2024 with the year ended December 31, 2023, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations in Part II of our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 21, 2025.

  CONSOLIDATED EARNINGS

  The following table compares our consolidated results, including favorable or better, "B," and unfavorable or worse, "W," variances:

  Year Ended December 31

  (in millions, except per share data)	2025	2024	B (W)
  Wisconsin	$ 1,054.8	$ 863.1	$	191.7
  Illinois	122.1	252.1		(130.0)
  Other states	60.8	54.5		6.3
  Electric transmission	147.6	141.0		6.6
  Non-utility energy infrastructure	411.1	380.8		30.3
  Corporate and other	(238.9)	(164.3)		(74.6)
  Net income attributed to common shareholders $ 1,557.5 $ 1,527.2 $ 30.3

  Diluted EPS $ 4.81 $ 4.83 $ (0.02)

  2025 Compared with 2024

  Earnings increased $30.3 million during 2025, compared with 2024. The significant factors impacting the $30.3 million increase in earnings were:

• A $191.7 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, higher retail sales volumes, and an increase in certain income tax benefits. These positive impacts were partially offset by higher operating expenses, largely due to increases in depreciation and amortization expense, costs related to our power plants, transmission expense, and expense related to our earnings sharing mechanisms. Lower other income, driven by a negative impact from the non-service components of our net periodic pension and OPEB costs, also partially offset the positive impacts to earnings. See Note 26, Regulatory Environment, for more information on the Wisconsin rate orders.

• A $30.3 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities related to the acquisition of additional renewable generation facilities in the fourth quarter of 2024 and the first quarter of 2025. This increase was partially offset by higher interest expense due to the issuance of long-term debt at WECI Energy Holding III in December 2024.

  These increases in earnings were partially offset by:

• A $130.0 million decrease in net income attributed to common shareholders at the Illinois segment, driven by a $205.0 million pretax charge to income in 2025 due to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the UEA and QIP riders. Partially offsetting this decrease was a year-over-year positive impact from a $25.3 million pre-tax charge to income in 2024 related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation. See Note 26, Regulatory Environment, for more information.

• A $74.6 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense in 2025 and the year-over-year impact from the gain on debt extinguishment recorded in 2024. A net loss from our equity method investments in technology and energy-focused investment funds during 2025, compared to net earnings in 2024, also contributed to the higher net loss.

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 for the year ended December 31, 2025 was

$1,054.8 million, representing a $191.7 million, or 22.2%, increase over the prior year. The higher earnings were driven by an increase in margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, higher retail sales volumes, and an increase in certain income tax benefits. These positive impacts were partially offset by higher operating expenses, largely due to increases in depreciation and amortization expense, costs related to our power plants, transmission expense, and expense related to our earnings sharing mechanisms. Lower other income, driven by a negative impact from the non-service components of our net periodic pension and OPEB costs, also partially offset the positive impacts to earnings. See Note 26, Regulatory Environment, for more information on the Wisconsin rate orders.

(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 2025 and 2024, $618.5 million and

$565.3 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

(3) Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. During 2025 and 2024,

$125.1 million and $115.8 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(4) Represents operation and maintenance associated with the earnings mechanisms we have in place. See Note 26, Regulatory Environment, for more information.

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

Year Ended December 31

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

Year Ended December 31

Year Ended December 31

(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).

Year Ended December 31

(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 $310.2 million during 2025, compared with 2024, and utility margin (non-GAAP) increased $536.2 million during 2025, compared with 2024. Both measures were driven by:

• A $402.4 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025. See Note 26, Regulatory Environment, for more information.

• A $135.5 million increase in margins related to higher retail sales volumes, driven by the impact of favorable weather during 2025, compared with 2024. As measured by heating degree days, 2025 was 28.0% and 20.0% colder than 2024 in the Milwaukee area and Green Bay area, respectively. As measured by cooling degree days, 2025 was 7.4% warmer than 2024 in the WPS service area.

  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:

• An $88.2 million increase in depreciation and amortization expense;

• A $46.2 million increase in other operating and maintenance related to our power plants;

• A $41.6 million increase in transmission expense;

• A $32.2 million increase in electric and natural gas distribution expenses;

• A $10.0 million increase in expense related to the resolution of certain items in our rate orders; and

• A $9.1 million increase in property and revenues taxes.

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

  Other operating expenses at the Wisconsin segment increased $287.3 million during 2025, compared with 2024. The significant factors impacting the increase in other operating expenses were:

• An $88.2 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $46.2 million increase in other operating and maintenance related to our power plants, driven by the resolution of certain items as a result of the December 2024 Wisconsin rate orders approved by the PSCW, as well as new renewable generation facilities placed in service during 2025.

• A $41.6 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2025. See the notes under the other operation and maintenance table above for more information.

• A $32.9 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above. See Note 26, Regulatory Environment, for more information.

• A $32.2 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems.

• A $15.9 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $12.4 million increase in expense driven by higher commitments made in 2025 to fund our charitable foundations.

• A $10.0 million increase in expense, driven by the resolution of certain items as a result of the December 2024 Wisconsin rate orders approved by the PSCW, as well as the October 2024 UMERC rate order approved by the MPSC.

• A $9.1 million increase in property and revenue taxes during 2025, compared with 2024, driven by a 2024 adjustment related to a sales tax audit at WE.

• A $6.2 million increase in environmental costs.

  These increases in other operating expenses were partially offset by a $12.8 million decrease in benefit costs.

  Other Income, Net

  Other income, net at the Wisconsin segment decreased $50.1 million during 2025, compared with 2024, driven by an $83.6 million negative impact from the non-service components of our net periodic pension and OPEB costs. In accordance with our December 2024 PSCW rate orders, in 2025 we began amortizing our pension and OPEB costs that were previously deferred under escrow accounting. During 2025, we amortized $48.4 million of the previously deferred non-service costs as we are now collecting these costs in rates. See Note 20, Employee Benefits, for more information on our benefit costs. This decrease in other income, net was partially offset by a

  $39.5 million positive impact from higher AFUDC-Equity due to continued capital investment.

  Interest Expense

  Interest expense at the Wisconsin segment increased $1.4 million during 2025, compared with 2024. The increase was primarily due to the impact of long-term debt issuances in 2024 and 2025. Partially offsetting this increase was long-term debt maturities for WE, WPS, and WG in 2024 and 2025. See Note 14, Long-Term Debt, for more information. Also offsetting the increase was higher AFUDC-Debt due to continued capital investment, lower average short-term debt balances, and lower average short-term debt interest rates.

  Income Tax Expense

  Income tax expense at the Wisconsin segment increased $5.7 million during 2025, compared with 2024, driven by higher pre-tax income.

  This increase in income tax expense was partially offset by:

• A $23.3 million increase in PTCs; and

• A $20.4 million increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2025.

  See Note 16, Income Taxes, for more information.

  ILLINOIS SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

  The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2025 was

  $122.1 million, representing a $130.0 million, or 51.6%, decrease from the prior year. The decrease was driven by a $205.0 million pretax charge to income in 2025 due to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the UEA and QIP riders. Partially offsetting this decrease was a year-over-year positive impact from a $25.3 million pre-tax charge to income in 2024 related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation. See Note 26, Regulatory Environment, for more information.

  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.

  Year Ended December 31

  (in millions)	2025		2024		B (W)
  Operating revenues	$	1,683.6	$	1,602.4	$	81.2
  Operating expenses
  Cost of natural gas sold		508.0		376.7		(131.3)
  Other operation and maintenance		482.2		461.5		(20.7)
  Impairments		130.0		12.1		(117.9)
  Depreciation and amortization		259.7		255.4		(4.3)
  Property and revenue taxes		55.5		59.9		4.4
  Operating income		248.2		436.8		(188.6)
  Other income, net		8.6		7.6		1.0
  Interest expense		88.9		94.7		5.8
  Income before income taxes		167.9		349.7		(181.8)
  Income tax expense		45.8		97.6		51.8
  Net income attributed to common shareholders	$ 122.1		$ 252.1		$	(130.0)

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

  Year Ended December 31

  (in millions)	2025		2024		B (W)
  Operation and maintenance not included in the line items below	$	323.2	$	318.5	$	(4.7)
  Riders (1)		154.2		139.7		(14.5)
  Regulatory amortizations (1)		2.8		2.3		(0.5)
  Other		2.0		1.0		(1.0)
  Total other operation and maintenance	$ 482.2		$ 461.5		$	(20.7)

  (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:

  Year Ended December 31

  Natural Gas Sales Volumes (Therms - in millions)	2025		2024		B (W)
  Customer Class
  Residential		855.9		745.4		110.5
  Commercial and industrial		317.6		287.7		29.9
  Total retail		1,173.5		1,033.1		140.4
  Transportation		775.1		707.8		67.3
  Total sales in therms	1,948.6		1,740.9		207.7

  Year Ended December 31

  Weather (Degree Days) (1)

  2025

  2024

  B (W)

  Heating (5,895 Normal) 5,869 4,848 21.1 %

  (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).

  Year Ended December 31

  (in millions)	2025		2024		B (W)
  Operating revenues	$	1,683.6	$	1,602.4 $		81.2

  Operating expenses

  Cost of natural gas sold	(508.0)	(376.7)	(131.3)
  Other operation and maintenance (1)	(233.6)	(227.2)	(6.4)
  Depreciation and amortization	(259.7)	(255.4)	(4.3)
  Property and revenue taxes	(55.5)	(59.9)	4.4
  Gross margin (GAAP)	626.8	683.2	(56.4)
  Other operation and maintenance (1)	233.6	227.2	6.4
  Depreciation and amortization	259.7	255.4	4.3
  Property and revenue taxes	55.5	59.9	(4.4)
  Utility margin (non-GAAP)	$ 1,175.6	$ 1,225.7	$ (50.1)

  (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 $56.4 million during 2025, compared with 2024, and utility margin (non-GAAP) decreased $50.1 million during 2025, compared with 2024. Both measures were driven by a $75.0 million decrease in revenues due to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the QIP and UEA riders. See Note 26, Regulatory Environment, for more information.

  This decrease in gross margin (GAAP) and utility margin (non-GAAP) was partially offset by:

• A $14.5 million increase 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 $12.9 million increase in revenues driven by a disallowance recorded in 2024 related to an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which required refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs. See Note 26, Regulatory Environment, for more information.

• A $2.2 million increase in revenues related to the impact of the NSG rate order issued by the ICC, effective February 1, 2024.

  Additionally, the larger 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 $4.3 million increase in depreciation and amortization expense;

• A $3.7 million increase in costs associated with maintenance at the Manlove Gas Storage Field; and

• A partially offsetting $4.4 million decrease in property and revenue taxes.

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

  Other operating expenses at the Illinois segment increased $124.0 million, net of the $14.5 million impact of the riders referenced in the table above, during 2025, compared with 2024. The significant factors impacting the increase in other operating expenses were:

• A $130.0 million impairment related to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the QIP and UEA riders. See Note 26, Regulatory Environment, for more information.

• A $7.4 million increase in expense primarily associated with the favorable settlement of a legal claim during 2024.

• A $4.3 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $3.7 million increase in costs associated with maintenance at the Manlove Gas Storage Field.

  These increases in operating expenses were partially offset by:

• A $12.1 million impairment recorded in 2024 related to an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's QIP rider, which included a disallowance of certain capital costs. See Note 26, Regulatory Environment, for more information.

• A $4.4 million decrease in property and revenue taxes, driven by the invested capital tax.

  Interest Expense

  Interest expense at the Illinois segment decreased $5.8 million during 2025, compared with 2024, due to lower average short-term debt balances, lower average short-term debt interest rates, and the impact of a series of PGL's first mortgage bonds maturing in November 2024.

  Income Tax Expense

  Income tax expense at the Illinois segment decreased $51.8 million during 2025, compared with 2024, driven by a decrease in pre-tax income.

  OTHER STATES SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

  The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2025 was

  $60.8 million, representing a $6.3 million, or 11.6%, increase over the prior year. The increase was driven by higher margins related to positive impacts from MGU's rate increase that was effective January 1, 2025, MERC's rate increase that was effective March 1, 2024, and an increase in retail sales volumes. These increases in earnings were partially offset by higher operating expenses. See Note 26, Regulatory Environment, for more information on the MGU and MERC rate increases.

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

  Year Ended December 31
  (in millions)	2025		2024		B (W)
  Operating revenues	$	527.5 $		449.8 $		77.7
  Operating expenses
  Cost of natural gas sold 246.3			198.6				(47.7)
  Other operation and maintenance 104.6			93.9				(10.7)
  Depreciation and amortization 49.8			47.0				(2.8)
  Property and revenue taxes 26.2			21.0				(5.2)
  Operating income 100.6			89.3				11.3
  Other income, net 0.4			0.3				0.1
  Interest expense 19.2			16.4				(2.8)
  Income before income taxes 81.8			73.2				8.6
  Income tax expense 21.0			18.7				(2.3)
  Net income attributed to common shareholders $ 60.8			$ 54.5		$		6.3
  The following table shows a breakdown of other operation and maintenance:
  			Year Ended December 31
  (in millions)	2025		2024		B (W)
  Operation and maintenance not included in line item below	$	81.9	$	76.8	$	(5.1)
  Regulatory amortizations and other pass through expenses (1)		22.7		17.1		(5.6)
  Total other operation and maintenance	$ 104.6		$ 93.9		$	(10.7)

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

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

  Year Ended December 31

  Natural Gas Sales Volumes (Therms - in millions)	2025		2024		B (W)
  Customer Class
  Residential		325.9		285.2		40.7
  Commercial and industrial		209.2		179.9		29.3
  Total retail		535.1		465.1		70.0
  Transportation		759.3		828.5		(69.2)
  Total sales in therms 1,294.4			1,293.6		0.8

  Year Ended December 31

  Weather (Degree Days) (1)	2025		2024		B (W)
  MERC
  Heating (7,888 Normal)		7,714		6,792		13.6 %
  MGU
  Heating (6,095 Normal)		6,126		5,083		20.5 %

  (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.

  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).

  Year Ended December 31

  (in millions)	2025		2024		B (W)
  Operating revenues	$	527.5 $		449.8 $		77.7
  Operating expenses
  Cost of natural gas sold	(246.3)		(198.6)			(47.7)
  Other operation and maintenance (1)	(59.0)		(55.4)			(3.6)
  Depreciation and amortization	(49.8)		(47.0)			(2.8)
  Property and revenue taxes	(26.2)		(21.0)			(5.2)
  Gross margin (GAAP)	146.2		127.8			18.4
  Other operation and maintenance (1)	59.0		55.4			3.6
  Depreciation and amortization	49.8		47.0			2.8
  Property and revenue taxes	26.2		21.0			5.2
  Utility margin (non-GAAP)	$ 281.2		$ 251.2		$	30.0

  (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) increased $18.4 million during 2025, compared to 2024, and utility margin (non-GAAP) increased $30.0 million during 2025, compared to 2024. Both measures were driven by:

• A $10.5 million increase related to MGU's rate increase that was effective January 1, 2025, and MERC's rate increase that was effective March 1, 2024.

• A $10.3 million increase related to higher sales volumes, driven by colder weather during 2025, compared to 2024. As measured by heating degree days, 2025 was 13.6% and 20.5% colder than 2024 at MERC and MGU, respectively.

• A $5.3 million increase related to MERC CIP revenue, which was offset in operation and maintenance expense. Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

• A $3.3 million increase related to MGU's energy optimization program, which provides rebates, incentives, and energy efficiency education to customers.

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

• A $5.2 million increase in property and revenue taxes;

• A $3.6 million increase in natural gas operations and customer service expense; and

• A $2.8 million increase in depreciation and amortization.

  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 $18.7 million during 2025, compared with 2024. The significant factors impacting the increase in operating expenses were:

• A $5.3 million increase in operation and maintenance expense related to MERC's CIP program, which has an offsetting increase in margins.

• A $5.2 million increase in property and revenue taxes, driven by the year-over-year impact from a positive resolution of a use tax audit at MGU during 2024.

• A $3.6 million increase in natural gas operations and customer service expense, driven by higher metering costs and call center expense at MERC and MGU.

• A $2.8 million increase in depreciation and amortization related to continued capital investment.

• A $1.4 million increase in bad debt expense, primarily at MERC. MERC's bad debt expense was lower in 2024 due to reserve adjustments related to improved loss rates.

  Interest Expense

  Interest expense at the other states segment increased $2.8 million during 2025, compared with 2024, driven by the impact of MERC issuing long-term debt in April 2025 and MGU issuing long-term debt in October 2024 and April 2025. This increase was partially offset by lower average short-term debt interest rates.

  Income Tax Expense

  Income tax expense at the other states segment increased $2.3 million during 2025, compared with 2024, driven by an increase in pretax income.

  ELECTRIC TRANSMISSION SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

  Year Ended December 31

  (in millions)		2025			2024			B (W)
  Equity in earnings of transmission affiliates	$		215.8	$		207.5	$		8.3
  Interest expense			19.3			19.4			0.1
  Income before income taxes			196.5			188.1			8.4

  Income tax expense	48.9	47.1		(1.8)
  Net income attributed to common shareholders	$ 147.6	$ 141.0	$	6.6

  Equity in Earnings of Transmission Affiliates

  Equity in earnings of transmission affiliates increased $8.3 million during 2025, compared with 2024. This increase was primarily due to continued capital investment by ATC. A $3.6 million gain related to the sale of an investment at ATC Holdco in March 2025 also contributed to the increase. Partially offsetting these increases was a $20.1 million increase in equity earnings recognized in 2024 related to the impact of a FERC order issued in October 2024 that addressed complaints related to ATC's ROE. For information on this FERC order, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - American Transmission Company Allowed Return on Equity Complaints.

  Income Tax Expense

  Income tax expense at the electric transmission segment increased $1.8 million during 2025, compared with 2024, driven by an increase in pre-tax income.

  NON-UTILITY ENERGY INFRASTRUCTURE SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

  Year Ended December 31

  (in millions)	2025	2024			B (W)
  Operating income	$	405.3	$	393.0	$	12.3

  Other income, net	2.8	1.0		1.8
  Interest expense	123.1	99.7		(23.4)
  Income before income taxes	285.0	294.3		(9.3)
  Income tax benefit	(122.9)	(82.4)		40.5
  Net loss attributed to noncontrolling interests	3.2	4.1		(0.9)
  Net income attributed to common shareholders	$ 411.1	$ 380.8	$	30.3

  Operating Income

  Operating income at the non-utility energy infrastructure segment increased $12.3 million during 2025, compared with 2024, driven by these items at WECI:

• A $26.4 million increase in operating income from new investments in several WECI renewable generation facilities made in late 2024 and early 2025.

• A $7.5 million positive impact due to lower transmission congestion that increased energy market prices.

  These increases in operating income were partially offset by:

• A $15.9 million impairment loss recorded at Samson I, Delilah I, and Thunderhead related to storm damage.

• A $7.9 million increase in operation and maintenance expenses due primarily to a higher number of equipment repairs at our renewable generation facilities.

• A $2.2 million negative impact in 2025 related to the receipt of lower performance payments.

  In addition to the above items at WECI, there was a $4.5 million positive impact from We Power due to continued capital investment.

  Interest Expense

  Interest expense at the non-utility energy infrastructure segment increased $23.4 million during 2025, compared with 2024, driven by the impact of WECI Energy Holding III issuing long-term debt in December 2024.

  Income Tax Benefit

  The income tax benefit at the non-utility energy infrastructure segment increased $40.5 million during 2025, compared with 2024. The increase was primarily due to an increase in PTCs that was related to the acquisition of additional renewable generation facilities in the fourth quarter of 2024 and the first quarter of 2025, and an IRS approved PTC rate increase, partially offset by lower production volumes.

  CORPORATE AND OTHER SEGMENT CONTRIBUTION TO NET INCOME ATTRIBUTED TO COMMON SHAREHOLDERS

  Year Ended December 31

  (in millions)	2025		2024		B (W)
  Operating loss	$	(11.5)	$	(11.3)	$	(0.2)
  Other income, net		30.6		54.4		(23.8)
  Interest expense		359.0		310.0		(49.0)
  Gain on debt extinguishment		-		(23.1)		(23.1)
  Loss before income taxes		(339.9)		(243.8)		(96.1)
  Income tax benefit		(101.0)		(79.5)		21.5
  Net loss attributed to common shareholders	$ (238.9)		$ (164.3)		$	(74.6)

  Other Income, Net

  Other income, net at the corporate and other segment decreased $23.8 million during 2025, compared with 2024. The significant factors impacting the decrease in other income, net were:

• A $15.1 million decrease due to net losses of $12.8 million from our equity method investments in technology and energy-focused investment funds during 2025, compared with net earnings of $2.3 million during 2024.

• A $6.6 million decrease in interest income, driven by the year-over-year negative impact from a $3.5 million gain recorded in 2024 related to the redemption of a long-term intercompany note WECI issued to WEC Energy Group. This decrease in intercompany interest income was offset by lower intercompany interest expense at our non-utility energy infrastructure segment. Lower interest income on cash balances of $3.4 million also contributed to the decrease in interest income.

• A $3.6 million decrease due to lower net gains from the investments held in the Integrys rabbi trust. The gains from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Interest Expense

Interest expense at the corporate and other segment increased $49.0 million during 2025, compared with 2024, primarily due to the impact of long-term debt issuances in May and December 2024, as well as June and November 2025. This increase was partially offset by long-term debt maturities and redemptions. See Note 14, Long-Term Debt, for more information. Also partially offsetting the increase was lower than average short-term debt interest rates.

Gain on Debt Extinguishments

There was no gain on debt extinguishments during 2025, as we did not have an early settlement on any debt obligations. In 2024, the gain on debt extinguishments was driven by the early retirement of a portion of both our 5.60% Senior Notes due September 12, 2026 and our 1.80% Senior Notes due October 15, 2030. Also, during 2024, we recorded gains on redemptions and repurchases of our 2007 Junior Notes.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $21.5 million during 2025, compared with 2024, driven by an increase in pre-tax loss.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

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

The following discussion and analysis of our Liquidity and Capital Resources includes comparisons of our cash flows for the year ended December 31, 2025 with the year ended December 31, 2024. For a similar discussion that compares our cash flows for the year ended December 31, 2024 with the year ended December 31, 2023, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources in Part II of our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 21, 2025.

CASH FLOWS

The following table summarizes our cash flows during the years ended December 31: