Wisconsin Electric (WELPM) details 2025 revenue, growth, and carbon goals

Rhea-AI Filing Summary

Wisconsin Electric Power Company files its 2025 Form 10-K, highlighting its regulated electric, natural gas, and steam operations in Wisconsin and wholesale electric sales under FERC regulation. Total utility operating revenues were $4,493.6 million in 2025, up from $3,979.9 million in 2024, driven mainly by electric utility revenues of $3,935.4 million and Wisconsin natural gas revenues of $558.2 million.

The company served 1,184.7 thousand electric customers and 519.5 thousand natural gas customers at December 31, 2025, and forecasts retail electric sales volumes to increase 2.3% in 2026 assuming normal weather. Its 2025 electric supply came 68.1% from company-owned or leased generation and 30.8% from power purchase contracts, with renewables contributing 7.6% from owned or leased units.

WEC Energy Group’s generation fleet, which includes Wisconsin Electric, has achieved a 53% reduction in carbon emissions from a 2005 baseline and targets net carbon-neutral electric generation by 2050, expecting to use coal only as backup by 2030 and eliminate coal as an energy source by 2032, subject to regulation and capital plan execution.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

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.

001-01245

WISCONSIN ELECTRIC POWER COMPANY

39-0476280

(A Wisconsin Corporation)

231 West Michigan Street

P.O. Box 2046

Milwaukee, WI 53201

(414) 221-2345

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Serial Preferred Stock, 3.60% Series, $100 Par Value

Six Per Cent. Preferred Stock, $100 Par Value

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☒    No ☐

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐    No ☒

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.     ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).  ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐    No ☒

As of June 30, 2025 (and currently), all of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.

None.

Number of shares outstanding of each class of common stock, as of

January 31, 2026

Common Stock, $10 par value, 33,289,327 shares outstanding

Documents incorporated by reference:

Portions of Wisconsin Electric Power Company's Definitive Information Statement on Schedule 14C for its Annual Meeting of Shareholders, to be held on April 30, 2026, are incorporated by reference into Part III hereof.

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2025

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

1

PART I

4

ITEM 1.

BUSINESS

4

A.

INTRODUCTION

4

B.

UTILITY SEGMENT

4

C.

REGULATION

12

D.

ENVIRONMENTAL COMPLIANCE

14

E.

HUMAN CAPITAL

14

ITEM 1A.

RISK FACTORS

16

ITEM 1B.

UNRESOLVED STAFF COMMENTS

28

ITEM 1C.

CYBERSECURITY

28

ITEM 2.

PROPERTIES

30

ITEM 3.

LEGAL PROCEEDINGS

31

ITEM 4.

MINE SAFETY DISCLOSURES

32

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

32

PART II

33

ITEM 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

33

ITEM 6.

RESERVED

33

ITEM 7.

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

33

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

53

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

54

A.

Report of Independent Registered Public Accounting Firm

54

B.

Consolidated Income Statements

56

C.

Consolidated Balance Sheets

57

D.

Consolidated Statements of Cash Flows

58

E.

Consolidated Statements of Equity

59

F.

Notes to Consolidated Financial Statements

60

Note 1

Summary of Significant Accounting Policies

60

Note 2

Acquisitions

68

Note 3

Disposition

69

Note 4

Related Parties

69

Note 5

Operating Revenues

71

Note 6

Credit Losses

72

Note 7

Regulatory Assets and Liabilities

73

Note 8

Property, Plant, and Equipment

75

Note 9

Jointly-Owned Utility Facilities

75

Note 10

Asset Retirement Obligations

76

Note 11

Common Equity

77

Note 12

Preferred Stock

79

Note 13

Short-Term Debt and Lines of Credit

79

Note 14

Long-Term Debt

80

Note 15

Leases

81

Note 16

Income Taxes

85

Note 17

Fair Value Measurements

87

Note 18

Derivative Instruments

88

Note 19

Employee Benefits

89

2025 Form 10-K i Wisconsin Electric Power Company

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Note 20

Segment Information

93

Note 21

Variable Interest Entities

94

Note 22

Commitments and Contingencies

95

Note 23

Supplemental Cash Flow Information

100

Note 24

Regulatory Environment

100

Note 25

Other Income, Net

103

Note 26

New Accounting Pronouncements

103

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

104

ITEM 9A.

CONTROLS AND PROCEDURES

104

ITEM 9B.

OTHER INFORMATION

104

ITEM 9C.

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

104

PART III

105

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

105

ITEM 11.

EXECUTIVE COMPENSATION

105

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

105

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

105

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

105

PART IV

106

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

106

ITEM 16.

FORM 10-K SUMMARY

109

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

110

SIGNATURES

111

2025 Form 10-K ii Wisconsin Electric Power Company

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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:

Subsidiaries and Affiliates
ATC						American Transmission Company LLC
Bluewater						Bluewater Natural Gas Holding, LLC
UMERC						Upper Michigan Energy Resources Corporation
WBS						WEC Business Services LLC
WE						Wisconsin Electric Power Company
We Power						W.E. Power, LLC
WEC Energy Group						WEC Energy Group, Inc.
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
DOE						United States Department of Energy
EPA						United States Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
IRS						United States Internal Revenue Service
PSCW						Public Service Commission of Wisconsin
SEC						Securities and Exchange Commission
USITC						United States International Trade Commission
WDNR						Wisconsin Department of Natural Resources
Accounting Terms
AFUDC						Allowance for Funds Used During Construction
ARO						Asset Retirement Obligation
ASC						Accounting Standards Codification
ASU						Accounting Standards Update
CWIP						Construction Work in Progress
FASB						Financial Accounting Standards Board
GAAP						Generally Accepted Accounting Principles
OPEB						Other Postretirement Employee Benefits
VIE						Variable Interest Entity
Environmental Terms
Act 141						2005 Wisconsin Act 141
BTA						Best Technology Available
CAA						Clean Air Act
CCR						Coal Combustion Residual
CO2						Carbon Dioxide
ELG						Steam Electric Effluent Limitation Guidelines
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
PM2.5						Particulates Less Than 2.5 Micrometers in Diameter
SO2						Sulfur Dioxide
ZLD						Zero Liquid Discharge

2025 Form 10-K iii Wisconsin Electric Power Company

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Measurements
Bcf						Billion Cubic Feet
Dth						Dekatherm
GW						Gigawatt
lb/MMBtu						Pound Per Million British Thermal Unit
MW						Megawatt
MWh						Megawatt-hour
µg/m3						Micrograms Per Cubic Meter
Other Terms and Abbreviations
AD						Antidumping
AI						Artificial Intelligence
AIA						Affiliated Interest Agreement
AOC						Audit and Oversight Committee of the Board of Directors of WEC Energy Group, Inc.
ARR						Auction Revenue Right
Badger Hollow II						Badger Hollow Solar Park II
BESS						Battery Energy Storage System
CAO						Chief Administrative Officer
CEO						Chief Executive Officer
CFR						Code of Federal Regulations
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
CODM						Chief Operating Decision Maker
Compensation Committee						Compensation Committee of the Board of Directors of WEC Energy Group, Inc.
CSIRT						Cybersecurity Incident Response Team
CT						Combustion Turbine
CVD						Countervailing Duty
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
Darien						Darien Solar Park
DER						Distributed Energy Resource
Enterprise Security Director						Director of Enterprise Security & Compliance
ERGS						Elm Road Generating Station
ER 1						Elm Road Generating Station Unit 1
ER 2						Elm Road Generating Station Unit 2
ERSC						Enterprise Risk Steering Committee
ETB						Environmental Trust Bond
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
GCRM						Gas Cost Recovery Mechanism
High Noon						High Noon Solar Energy Center
IRA						Inflation Reduction Act
IT/OT						Information Technology and Operational Technology
ITC						Investment Tax Credit
Koshkonong						Koshkonong Solar Park
LDC						Local Natural Gas Distribution Company
LMP						Locational Marginal Price
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.
MISO Energy Markets						MISO Energy and Operating Reserves Market
NYMEX						New York Mercantile Exchange
OCPP						Oak Creek Power Plant
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
PHMSA						Pipeline and Hazardous Materials Safety Administration
PIPP						Presque Isle Power Plant
Point Beach						Point Beach Nuclear Power Plant

2025 Form 10-K iv Wisconsin Electric Power Company

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PPA						Power Purchase Agreement
PTC						Production Tax Credit
PWGS						Port Washington Generating Station
PWGS 1						Port Washington Generating Station Unit 1
PWGS 2						Port Washington Generating Station Unit 2
RICE						Reciprocating Internal Combustion Engine
RNG						Renewable Natural Gas
ROE						Return on Equity
Rothschild						Rothschild Biomass Cogeneration Plant
RTO						Regional Transmission Organization
S&P						Standard & Poor's
Saratoga						Saratoga Solar Electric Generation and BESS Facility
SSR						System Support Resource
Supreme Court						United States Supreme Court
UFLPA						Uyghur Forced Labor Prevention Act
VAPP						Valley Power Plant
VLC						Very Large Customer
West Riverside						West Riverside Energy Center
Weston						Weston Generating Station
Whitetail						Whitetail Wind Energy Generation Facility
Whitewater						Whitewater Cogeneration Facility
WPL						Wisconsin Power and Light Company

2025 Form 10-K v Wisconsin Electric Power Company

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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, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, climate-related matters, the WEC Energy Group 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 Item 1A. Risk Factors and those identified below:

•Factors affecting utility 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;

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•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 WEC Energy Group's 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 the ability to execute the WEC Energy Group 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 or us;

•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;

•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 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;

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•The risk associated with the value of long-lived assets, including intangible assets, and their possible impairment;

•Potential business strategies to acquire and dispose of assets, which cannot be assured to be completed timely or within budgets;

•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.

2025 Form 10-K 3 Wisconsin Electric Power Company

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PART I

ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company. The term "utility" refers to our regulated activities, while the term "non-utility" refers to our activities that are not regulated. References to "Notes" are to the Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K.

We are a subsidiary of WEC Energy Group and were incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin and serve customers in Wisconsin. We conduct our business primarily through our utility reportable segment.

For more information about our utility operations, including financial and geographic information, see Note 20, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations. For information about our business strategy, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports are made available on WEC Energy Group's website, www.wecenergygroup.com, free of charge, as soon as reasonably practicable after they are filed with or furnished to the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

B. UTILITY SEGMENT

Electric Utility Operations

We generate and distribute electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin.

Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2025, 2024, and 2023, see Note 1(d), Operating Revenues, and Note 5, Operating Revenues.

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail, wholesale, and resale customers. In 2025, retail revenues accounted for 92.6% of total electric operating revenues, wholesale revenues accounted for 1.2% of total electric operating revenues, and resale revenues accounted for 5.3% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Net Income Attributed to Common Shareholder for information on MWh sales by customer class.

We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities.

We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers.

The majority of our sales for resale are conducted within an energy market operated by MISO at market rates based on the availability of our generation and market demand. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.

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We buy and sell electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the MISO Energy Markets compared to our competitors affects how often our generating units are dispatched and whether we buy or sell power. For more information on the MISO Energy Markets, see C. Regulation.

Steam Sales

We have a steam utility that generates, distributes, and sells steam supplied by the VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions.

Electric Sales Forecast

Our service territory experienced higher weather-normalized retail electric sales in 2025, compared with 2024, due to higher sales to commercial and industrial customers. We currently forecast retail electric sales volumes to increase 2.3% for 2026, compared with 2025, assuming normal weather. Excluding the very large data center customers, we currently forecast sales volumes to decrease slightly in 2026, assuming normal weather.

Customers

						Year Ended December 31
(in thousands)						2025						2024						2023
Electric customers – end of year
Residential						1,061.1						1,052.2						1,044.9
Small commercial and industrial						121.3						120.6						119.3
Large commercial and industrial						0.6						0.6						0.6
Wholesale and other						1.7						1.6						1.6
Total electric customers – end of year						1,184.7						1,175.0						1,166.4
Steam customers – end of year						0.4						0.4						0.4

Electric Commercial and Industrial Retail Customers

We provide electric utility service to a diversified base of customers in industries such as metals and other manufacturing, governmental, real estate, health services, and food manufacturing.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from a diverse generation portfolio that balances a stable, reliable, and affordable supply of electricity with environmental stewardship. Through our participation in the MISO Energy Markets, we supply a significant amount of electricity to our customers from generation that we own or lease from We Power. We supplement our internally generated power supply with long-term PPAs, including the Point Beach PPA discussed under the heading "Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess power supply into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power. On a real time basis, the MISO Energy Market continuously evaluates system load requirements and dispatches the lowest-cost generation resources, while respecting any limitations on the transmission system.

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The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2026:

						Estimate (1)						Actual
						2026						2025						2024						2023
Company-owned or leased generation units:
Coal						28.0		%				27.8		%				28.9		%				30.6		%
Natural gas:
Combined cycle						27.0		%				24.3		%				25.6		%				28.4		%
Steam turbine						0.7		%				1.2		%				1.5		%				1.2		%
Natural gas/oil peaking units						5.2		%				7.2		%				6.7		%				3.5		%
Renewables (2)						8.1		%				7.6		%				5.1		%				4.0		%
Total company-owned or leased generation units						69.0		%				68.1		%				67.8		%				67.7		%
Power purchase contracts:
Nuclear						28.7		%				30.1		%				30.6		%				30.0		%
Renewables (3)						0.6		%				0.7		%				0.7		%				0.8		%
Other						0.1		%				—		%				—		%				0.2		%
Total power purchase contracts						29.4		%				30.8		%				31.3		%				31.0		%
Purchased power from MISO						1.6		%				1.1		%				0.9		%				1.3		%
Total purchased power						31.0		%				31.9		%				32.2		%				32.3		%
Total electric utility supply						100.0		%				100.0		%				100.0		%				100.0		%

(1)    The values included in the estimate assume a natural gas price based on the December 2025 NYMEX.

(2)    Includes hydroelectric, biomass, solar, BESS, and wind generation.

(3)    Includes hydroelectric, wind, and customer-owned renewable generation.

Electric Generation Facilities

Our generation portfolio is a mix of energy resources having different operating characteristics and fuel sources. We own or lease 5,462 MWs of generation capacity, including wholly owned and jointly owned facilities. Our generation facilities include natural gas-fired plants, coal-fired plants, renewable generation, and BESSs. Certain of our natural gas-fired generation units have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our facilities, see Item 2. Properties.

We are engaged in discussions with a small number of customers to provide power to large-scale data centers being constructed in our service territories. We anticipate electric demand growth in the years ahead from these VLCs. Subject to pending regulatory approvals from the PSCW as discussed below, we are planning to make significant infrastructure investments in new natural gas-fired plants, wind, solar and battery projects, and other generation and distribution assets to power and serve these large-scale data centers and other projects. We are working closely with the new data center customers to provide bespoke resources, which are generation resources assigned to the VLCs that match their growing demand in order to minimize the impact on our other retail customers.

Generation from Leased W.E. Power, LLC Units

We supply electricity to our customers from power plants that we lease from We Power. These plants include the ERGS units and the PWGS units. Lease payments are billed from We Power to us and then recovered in our rates as authorized by the PSCW and the FERC. We operate the We Power units and are authorized by the PSCW and state law to fully recover prudently incurred operating and maintenance costs in our electric rates. As the operator of the units, we may request We Power to make capital improvements to, or further investments in, the units. Under the lease terms, these capital improvements or further investments will increase lease payments paid by us and should ultimately be recovered in our rates.

Supporting Economic Growth Within Our Communities

WEC Energy Group's capital plan reflects the planned retirement of older, fossil-fueled generation, which we expect to replace with natural gas-fired generation and zero-carbon-emitting renewables. These retirements are intended to address compliance with EPA regulations established under the CAA, as well as contribute to meeting WEC Energy Group's and our goal to reduce CO2 emissions

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from electric generation. When taken together, the retirements and new investments in natural gas generation and renewables discussed in more detail below should better balance WEC Energy Group's supply with its demand, while helping to address compliance and maintaining reliable, affordable energy for our customers. As described in the preceding section, we are planning to make significant investments in generation and distribution assets for the future demands of VLCs.

Environmental Goal

WEC Energy Group's long-term goal is to achieve net carbon neutral electric generation by the end of 2050. WEC Energy Group expects to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. WEC Energy Group expects 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 of the end of 2025, WEC Energy Group's electric generation fleet has achieved a 53% reduction in carbon emissions from the 2005 baseline.

As part of our path toward this goal, we have started implementing co-firing with natural gas at the ERGS coal-fired units. Additionally, WEC Energy Group has retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the 2024 retirement of OCPP Units 5 and 6, the 2019 retirement of the PIPP, and the 2018 retirement of the Pleasant Prairie power plant. See Note 7, Regulatory Assets and Liabilities, for more information related to certain of these power plant retirements. WEC Energy Group expects 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. See Note 8, Property, Plant, and Equipment, for more information.

See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments for more information on WEC Energy Group's capital plan.

Also see Item 1A. Risk Factors - Risks Related to Legislation and Regulation - Our operations, capital expenditures, and financial results may be affected by the impact of GHG legislation, regulation, and our emission reduction goal.

Renewable Generation

We meet a portion of our electric generation supply with various renewable energy resources, including wind, solar, hydroelectric, and biomass. This helps us work towards our goal of reducing carbon emissions while also maintaining compliance with renewable energy legislation. These renewable energy resources also help us maintain diversity in our generation portfolio, which effectively serves as a price hedge against future fuel costs, and will help mitigate the risk of potential unknown costs associated with any future carbon restrictions for electric generators.

Wind

We continue to invest in and upgrade our wind-powered generation systems to enhance reliability. We have received approval from the PSCW to acquire and construct 142 MWs of additional wind-powered generation. We will jointly own these generation facilities with WPS and an unaffiliated entity. See Note 9, Jointly-Owned Utility Facilities, for more information.

Solar and Battery Storage

In June 2025, the construction of the battery portion of Paris located in Kenosha County, Wisconsin was completed, and the facility became commercially operational. The solar portion of Paris was commercially operational in December 2024. Paris is owned by us, WPS, and an unaffiliated entity. We own 150 MWs of solar generation and 83 MWs of battery storage associated with this project.

In March 2025, the construction of the solar portion of Darien located in Rock and Walworth counties, Wisconsin was completed, and the facility became commercially operational. Darien is owned by us, WPS, and an unaffiliated entity. We own 188 MWs of solar generation and expect to own 57 MWs of battery storage associated with this project, with construction expected to be completed in 2027.

As part of our commitment to invest in additional zero-carbon generation, we have received approval from the PSCW to acquire and construct 730 MWs of additional solar-powered generation and 345 MWs of battery storage. See Note 9, Jointly-Owned Utility Facilities, for more information.

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We have also filed requests with the PSCW to acquire and construct 1,212 MWs of solar-powered generation and 212 MWs of battery storage.

Thermal Generation

As part of our commitment to invest in additional thermal generation, we have received approval from the PSCW to acquire and construct 1,228 MWs of additional natural gas-fired generation.

We have also filed requests with the PSCW to acquire and construct 1,660 MWs of additional natural gas-fired generation. Some of the generation projects pending approval are for bespoke resources to serve VLCs. See Note 24, Regulatory Environment, for more information on bespoke resources and the proposed VLC tariff.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO implemented seasonal requirements effective June 1, 2023. The installed capacity reserve margins for the planning year June 1, 2025 through May 31, 2026 are as follows: 15.7% summer (June – August); 25.3% fall (September – November); 38.6% winter (December – February); and 38.8% spring (March – May). MISO's short-term reserve margin requirements experience year-to-year and season-to-season fluctuations, primarily due to changes in the generation resource mix and average forced outage rate of generation within the MISO footprint.

We believe that we have adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during the current planning year. We also fully anticipate that we will have adequate capacity to meet the planning reserve margin requirements for the upcoming planning year.

Fuel and Purchased Power Costs

Our retail electric rates are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW generally allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rules, see C. Regulation.

Our average fuel and purchased power costs per MWh by fuel type, including delivery costs, were as follows for the years ended December 31:

						2025						2024						2023
Coal						$	28.15					$	25.12					$	25.68
Natural gas combined cycle						25.60						20.41						29.47
Natural gas/oil peaking units						65.39						44.76						68.56
Biomass						79.32						81.33						87.73
Purchased power						69.64						65.20						61.78

We purchase coal under long-term contracts, which helps with price stability. Coal and associated transportation services are exposed to volatility in pricing due to changing domestic and world-wide demand for coal and diesel fuel. To mitigate against this volatility risk, we have PSCW approval for a hedging program. This program allows us to hedge, over a 60-month period, up to 75% of our potential risks related to rail transportation fuel surcharge exposure. The results of this hedging program, when used, are reflected in the average costs of fuel and purchased power.

We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage. We also have PSCW approval for a hedging program to mitigate against volatility related to natural gas price risk. This program allows us to hedge, over a 60-month period, up to 75% of our estimated natural gas use for electric generation. The results of this hedging program are reflected in the average costs of natural gas.

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Coal Supply

We diversify the coal supply for our leased, owned, and jointly owned electric generating facilities by purchasing coal from several mines in Wyoming and Pennsylvania, as well as from various other states. For 2026, 54% of our projected coal requirements of 5.1 million tons are contracted under fixed-price contracts. See Note 22, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for the next three years are as follows:

(in thousands)						Annual Tonnage
2026						2,750
2027						575
2028						—

Coal Deliveries

All of our coal requirements are expected to be shipped by unit trains that we own or lease under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming and Pennsylvania. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities. For additional information concerning risks related to coal supply chain disruptions, see the risk factor below.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

Power Purchase Commitments

We enter into short- and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. Excluding planning capacity purchases, our power purchase commitments with unaffiliated parties consists of 1,033 MWs per year for 2026 through 2030 related to a long-term PPA for electricity generated by Point Beach. If necessary, we purchase planning capacity from the MISO annual auction to ensure that we maintain our compliance with planning reserve requirements as established by the PSCW and MISO.

Seasonality

Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. In 2025, our generating plants performed as expected during the most demanding periods of the year, and all power purchase commitments under firm contract were received. During this period, we did not make any public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs. We did have economic interruption events; however, service to customers was not curtailed. Economic interruptions are declared during times in which the price of electricity in the regional market exceeds the cost of operating our peaking generation. During this time, customers taking service under these interruptible programs can choose to continue using electricity at a price based on wholesale market prices or to reduce their load.

Competition

We face competition from various entities and other forms of energy sources available to customers, including self-generation by customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.

For more information on competition in our service territory, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.

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Natural Gas Utility Operations

We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We operate in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin.

We provide service to residential and commercial and industrial customers. In addition, we offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Major industries served include real estate, restaurants, governmental, food manufacturing, and metals manufacturing. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Net Income Attributed to Common Shareholder for information on natural gas sales volumes by customer class.

Operating Revenues

For information about our operating revenues disaggregated by customer class for the years ended December 31, 2025, 2024, and 2023, see Note 1(d), Operating Revenues, and Note 5, Operating Revenues.

Natural Gas Sales Forecast

Our service territory experienced lower weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2025 as compared to 2024. We currently forecast retail natural gas delivery volumes to decrease slightly in 2026, as compared to 2025, assuming normal weather.

Customers

						Year Ended December 31
(in thousands)						2025						2024						2023
Customers – end of year
Residential						476.6						472.0						468.9
Commercial and industrial						41.9						41.6						41.3
Transportation						1.0						1.0						1.0
Total customers						519.5						514.6						511.2

Natural Gas Supply, Pipeline Capacity and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns. For more information on our natural gas utility supply and transportation contracts, see Note 22, Commitments and Contingencies.

Pipeline Capacity and Storage

We have long-term firm capacity contracts with interstate pipelines that access supply from a variety of natural gas producing areas. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

Due to variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We have entered into a long-term service agreement for natural gas storage with a wholly owned subsidiary of Bluewater. Bluewater, a wholly owned subsidiary of WEC Energy Group, owns natural gas storage facilities in Michigan and provides approximately one-third of our current storage needs. We target storage inventory levels at approximately 40% of forecasted demand for November through March. Diversity of natural gas supply enables us to manage significant changes in demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months and withdraw it in the winter months.

We contract with interstate pipeline companies, as well as other service providers, to purchase firm transportation and storage services under varied-length long-term contracts. We believe that having diverse capacity and storage benefits our customers.

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Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 12.4 million therms for the 2025 through 2026 heating season. Our peak daily send-out during 2025 was 7.3 million therms on January 21, 2025. Peak or near-peak demand generally occurs only a few times each year. Natural gas pipeline capacity and storage and natural gas supplies under contract can be resold in secondary markets. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRM. For information on our GCRM, see Note 1(d), Operating Revenues.

To ensure a reliable supply of natural gas during peak winter conditions, we have LNG facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers. We have an LNG facility, which provides approximately one Bcf of natural gas supply. The PSCW approved our request to construct an additional LNG facility with a storage capacity of two Bcf. The construction of additional LNG facilities in Wisconsin has been proposed as part of WEC Energy Group's 2026-2030 capital plan, which includes us. The facilities would provide another approximately four Bcf of natural gas supply (of which our portion is expected to be approximately two Bcf). The use of LNG allows us to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity.

Natural Gas Supply

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

Hedging Natural Gas Supply Prices

As part of our hedging programs, we further reduce our supply cost volatility through the use of a mix of financial instruments, such as NYMEX-based natural gas options and futures contracts. We have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand. This approval allows us to pass 100% of the hedging costs (premiums, brokerage fees and losses) and proceeds (gains) to customers through our GCRM.

Seasonality

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather.

Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of our winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

We face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternative fuels. Electrification initiatives or mandates are being considered or proposed by certain states and municipalities near our service territory. In addition, all of our customers have the opportunity to choose a natural gas supplier other than us. We offer natural gas transportation services for customers that elect to purchase natural gas directly from a third-party supplier. We continue to earn distribution revenues from these transportation customers for their use of our distribution system to transport natural gas to their facilities. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs.

For more information on competition in our service territory, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.

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Methane Emission Reductions

We plan to achieve methane emission reductions through continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility system. The RNG supplied will directly replace higher emission methane from natural gas that would have entered our pipes.

C. REGULATION

In addition to the specific regulations noted below, we are also subject to various other regulations, which primarily consist of regulations, where applicable, of the EPA, the WDNR, and the United States Army Corps of Engineers.

Rates

Our retail electric, natural gas, and steam rates are regulated by the PSCW, and the FERC regulates our wholesale electric rates. Decisions by these regulators can significantly impact our liquidity, financial condition, and results of operations. The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:

						2025												2024												2023
(in millions)						Amount						Percent						Amount						Percent						Amount						Percent
Electric
Wisconsin						$	3,682.0					93.6		%				$	3,345.0					94.6		%				$	3,338.6					94.0		%
FERC – Wholesale						253.4						6.4		%				191.2						5.4		%				214.9						6.0		%
Total						3,935.4						100.0		%				3,536.2						100.0		%				3,553.5						100.0		%
Natural Gas – Wisconsin						558.2						100.0		%				443.7						100.0		%				491.5						100.0		%
Total utility operating revenues						$	4,493.6											$	3,979.9											$	4,045.0

Retail Rates

The PSCW has general supervisory and regulatory powers over public utilities in its jurisdiction including, but not limited to, approval of retail utility rates and standards of service, security issuances, mergers, affiliate transactions, location and construction of electric generating units and natural gas facilities, and certain other additions and extensions to utility facilities.

Historically, retail rates approved by the PSCW have been designed to provide utilities the opportunity to generate revenues to recover all prudently-incurred costs, along with a return on investment sufficient to pay interest on debt and provide a reasonable ROE. Rates charged to customers vary according to customer class and rate jurisdiction. We are subject to an earnings sharing mechanism in which a portion of our earnings are required to be refunded to customers if we earn above our authorized ROE. See Note 24, Regulatory Environment, for more information on our earnings sharing mechanism. The table below reflects our approved ROE and capital structure during 2025.

Regulated Retail Rates

Regulatory Commission

Authorized ROE

Average Common Equity Component

Electric, natural gas, and steam (1)

PSCW

9.80%

53.0%

(1)    As currently proposed, the ROE for VLCs will range from 10.48% to 10.98%, as agreed upon with the customer, and the average common equity ratio will be 57.0%. See Note 24, Regulatory Environment, for more information.

In addition to amounts collected from customers through approved base rates, we have certain recovery mechanisms in place that allow us to recover or refund prudently incurred costs that differ from those approved in base rates.

Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount.

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Our natural gas utility operates under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar-for-dollar recovery of prudently incurred natural gas costs.

See Note 1(d), Operating Revenues, for more information on the significant mechanisms we had in place during 2025 that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts.

We file periodic requests with the PSCW for changes in retail rates. Our rate requests are based on forward looking test years, which reflect additions to infrastructure and changes in costs incurred or expected to be incurred. For information on our regulatory proceedings, see Note 24, Regulatory Environment. Orders from the PSCW can be viewed at https://psc.wi.gov/. The material and information contained on this website are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.

Wholesale Rates

The FERC regulates our wholesale sales of electric energy, capacity, and ancillary services. We have received market-based rate authority from the FERC. Market-based rate authority allows wholesale electric sales to be made in the MISO market and directly to third parties based on the negotiated market value of the transaction. We also make wholesale sales pursuant to cost-based formula rates. Cost-based formula rates provide for recovery of our costs and an approved rate of return. The predetermined formula is initially based on our expenses from the previous year, but is eventually trued up to reflect actual, current-year costs.

Electric Transmission, Capacity, and Energy Markets

In connection with its status as a FERC-approved RTO, MISO operates an energy and ancillary services market and manages the flow of high-voltage electricity across the transmission system in its region. MISO is responsible for monitoring and ensuring equal access to the electric transmission system in its footprint.

In MISO, transmission costs are allocated in accordance with the MISO tariff, which is reviewed and approved by the FERC. Base transmission costs are paid by load-serving entities located in the service territories of each MISO transmission owner. Costs for new regional transmission projects are allocated to load-serving entities throughout the MISO footprint, while the costs for new generation interconnections are allocated to the interconnection customer.

Within MISO, transmission congestion is monetized and included within an LMP that is established through the energy market. The LMP system includes the ability to hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction was completed for the period of June 1, 2025, through May 31, 2026. The resulting ARR allocation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

MISO has seasonal zonal resource adequacy requirements to ensure there is sufficient generation capacity to serve load within each zone and the MISO footprint. To meet this requirement, load-serving entities can own generation and demand response resources, acquire generation capacity through MISO's annual capacity auction, or acquire generation capacity through bilateral contracts. The zone in which our load resides, along with the MISO North region as a whole, has sufficient generation capacity resources to meet their respective planning reserve margins for the period between June 1, 2025 and May 31, 2026.

We manage our electric generation portfolio to minimize our exposure within MISO’s annual capacity auction. This includes managing the retirement of existing generation resources and the addition of new generation resources to maintain a diversified portfolio to help avoid a significant short position.

Other Electric Regulations

We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. Among other things, the Federal Power Act makes electric utility industry consolidation more feasible and authorizes the FERC to review proposed mergers and the acquisition of generation facilities. The FERC also oversees the Electric Reliability Organization, which establishes mandatory electric reliability standards and has the authority to levy monetary sanctions for failure to comply with these standards.

We are subject to Act 141 in Wisconsin which contains certain minimum requirements for renewable energy generation.

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Other Natural Gas Regulations

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the PHMSA and the PSCW are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 CFR Part 191 (Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports), 49 CFR Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards), and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We also continue to monitor the progress of the PHMSA’s proposed rulemaking titled "Gas Pipeline Leak Detection and Repair," which could have a significant impact on us.

We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.

Compliance Costs

The regulations and oversight described above significantly influence our operating environment, and may cause us to incur compliance and other related costs and may affect our ability to recover these costs from our utility customers. Any anticipated capital expenditures for compliance with government regulations for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements.

D. ENVIRONMENTAL COMPLIANCE

Our operations, especially as they relate to our coal-fired generating facilities, are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation related to GHG emissions, coal combustion products, air emissions, water use, or wastewater discharges and other climate change issues, could significantly increase these environmental compliance costs.

Anticipated expenditures for environmental compliance and certain remediation issues for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements. For a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change, see Note 22, Commitments and Contingencies.

E. HUMAN CAPITAL

We believe our employees are among our most important resources, so investing in human capital is critical to our success. We strive to attract, retain, and develop talented personnel and keep our employees safe, healthy, and engaged.

WEC Energy Group's Board of Directors retains collective responsibility for comprehensive risk oversight of WEC Energy Group and its subsidiaries, including critical areas that could impact our sustainability, such as human capital. Management regularly reports to WEC Energy Group's Board of Directors on human capital management topics, including corporate culture, succession planning, training and employee development, and safety and health. WEC Energy Group's Board of Directors delegates specified duties to its committees. In addition to its responsibilities relative to executive compensation, the Compensation Committee has oversight responsibility for reviewing organizational matters that could significantly impact us. The Compensation Committee reviews recruiting and development programs and priorities, receives updates on key talent, and assesses workforce composition across WEC Energy Group and its subsidiaries.

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Workforce

As of December 31, 2025, we had 2,565 employees, including 1,963 that are represented under union agreements. We believe we have very good overall relations with our workforce. In order to attract and retain talent, we provide competitive wages and benefits to our employees based on their performance, role, location, and market data. Our compensation package also includes a 401(k) savings plan with an employer match, an annual incentive plan based on meeting company goals, healthcare and insurance benefits, vacation and paid time off days, as well as other benefits.

Engagement

We are committed to ensuring a fair workplace and an engaged workforce. Our commitment is a core strategic competency and an integral part of our culture, with longstanding programs for individual development, reinforcement of core values, and a recruitment strategy that is focused on building a deep talent pipeline to support our business needs. During 2025, we demonstrated this commitment through training and development of employees at all levels of the organization, our comprehensive merit review and succession planning processes, and a range of community partnerships. In addition, WEC Energy Group has a number of initiatives that promote workforce contributions and participation and ensure its companies, including us, are attractive employers for persons of all backgrounds. These initiatives include nine business resource groups (voluntary, employee-led groups organized around a particular shared background or interest), mentoring programs, and education and training for all employees in order to develop and support inclusive teams. We are committed to a workplace free from bias and harassment. We also support external leadership and educational programs that support, train, and promote individuals in the communities we serve.

Safety and Health

WEC Energy Group's Executive Safety Committee directs our safety and health strategy, works to ensure consistency across groups, and reinforces our ongoing safety commitment that we refer to as “Target Zero.” Under our Target Zero commitment, we have an ultimate goal of zero incidents, accidents, and injuries. 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. We monitor and set goals for days away, restricted or transferred metrics, and measurable leading indicators, which together raise awareness about employee safety and guide injury-prevention activities.

We also provide employees various benefits and resources designed to promote healthy living, both at work and at home. We encourage employees to receive preventive examinations and to proactively care for their health through free health screenings, wellness challenges, and other resources.

Development and Training

Employee training and development of both technical and leadership skills are integral aspects of our human capital strategy. We provide employees with a wide range of development opportunities, including online training, simulations, live classes, and mentoring to assist with their career advancement. These programs include safety and technical job skill training as well as soft-skill programs focused on relevant subjects, including communication and change management. Development of leadership skills remains a top priority and is specialized for all levels of employees. We have specific leadership programs for aspiring leaders and new supervisors, managers, and directors. This development of our employees is an integral part of our succession planning and provides continuity for our senior leadership.

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ITEM 1A. RISK FACTORS

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental legislation, regulation, and oversight.

We are subject to significant state, local, and federal governmental legislation and regulations, including regulations by the PSCW and the FERC. Legislation and regulation significantly influence our operating environment, may affect our ability to recover costs from utility customers, affect our ability to implement WEC Energy Group's corporate strategy, and cause us to incur substantial compliance and other costs. Changes in legislation or regulations, their interpretation, or the imposition of new legislation or regulations could also significantly impact our business operations. Many aspects of our operations are impacted by government legislation and regulations, including, but not limited to: the rates we charge our retail electric, natural gas, and steam customers; our authorized rate of return; construction and operation of electric generating facilities and electric and natural gas distribution systems, including the ability to recover such costs; decommissioning generating facilities, the ability to recover the related costs, and continuing to recover the return on the net book value of these facilities; wholesale power service practices; electric reliability requirements; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of debt securities; short-term debt obligations; transactions with affiliates; and billing practices. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties, and other payments, which could materially and adversely affect our results of operations and financial condition.

The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation provides us an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent upon regulatory action, the outcome of which can be influenced by the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; and changes in the political, regulatory, or legislative environments. There is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery from or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is subject to review and approval by our regulators. If recovery is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.

Changes in the local and national political, regulatory, and economic environment, including significant attention on energy affordability concerns, have had, and may in the future have, an adverse effect on regulatory decisions, which could impair our ability to recover costs historically collected from customers. These decisions, which may come from any level of government, may cause us to cancel or delay current or planned projects, to reduce or delay other planned capital expenditures, or to pay for investments or otherwise incur costs that we may not be able to recover through rates or otherwise.

We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied in all material respects with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility and may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies.

If we are unable to recover regulatory compliance costs or other associated costs in customer rates in a timely manner, or if we are unable to obtain, renew, or comply with governmental permits, approvals, authorizations, certificates, or licenses, our results of operations and financial condition could be materially and adversely affected.

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We face significant costs to comply with existing and future environmental laws and regulations.

Our operations are subject to extensive and evolving federal, state, and local environmental laws, regulations, and permit requirements related to, among other things, air emissions (including, but not limited to: CO2, methane, mercury, SO2, NOx, ozone and other pollutants), protection of natural resources, water quality, wastewater discharges, management of hazardous and toxic substances and solid wastes and soils, and climate change. Many of these rules are now the subject of a large deregulatory effort by the EPA and have resulted, and are expected to continue to result in, the adoption of new federal, state, and/or local level laws and regulations. Any EPA actions will require formal rulemaking proceedings and are likely to be subject to legal challenges. In addition, at the end of 2025, the President issued executive orders directing the DOE to issue orders keeping certain coal plants running for grid reliability despite utilities' plans to retire them. Future orders impacting our planned retirements of coal plants could impact our ability to execute on our capital plan and to meet our environmental goal. We continue to monitor the evolving regulatory landscape and standards for impacts on our business operations and financial condition.

Certain of our service territory is located in areas that, in December 2024, were determined to be in "serious" nonattainment status under the EPA's ozone standard. In February 2025, the State of Wisconsin filed a petition for review of this classification in the U.S. 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. As a result, southeast Wisconsin has returned to "moderate" status while the underlying lawsuit proceeds. A nonattainment status of "serious" could affect future permitting activities for our facilities, including additional costs associated with more strenuous emission control requirements or the need to purchase emission reduction credits. In addition, economic growth in these areas may be constrained by the inability to obtain the required permits, limiting investment and expansion over the coming years, impacting our ability to execute on our capital plan.

We incur significant capital costs and expend operating resources to comply with environmental laws, regulations, and requirements, including costs associated with the installation of pollution control equipment; operating restrictions on our facilities; and environmental monitoring, emissions fees, and permits at our facilities. The operation of emission control equipment and compliance with rules regulating our intake and discharge of water could also increase our operating costs and reduce the generating capacity of our power plants. These regulations may create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels and our ability to continue operating certain generating units. Failure to comply with these laws, regulations, and requirements, even if caused by factors beyond our control, may result in the assessment of civil or criminal penalties and fines. We continue to assess the cost of compliance, and to explore different compliance alternatives with these and other environmental regulations. The cost of compliance with these regulations, and other factors, has resulted in certain of our coal-fired electric generating facilities being retired or converted to an alternative type of fuel, and may impact the future operations of our existing fossil-fueled generation.

We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation and related legal expenses, and are net of amounts recovered (or that may be recovered) from insurance or other third parties. Due to the potential for the imposition of stricter standards and greater regulation in the future, the possibility that other potentially responsible parties may not be willing or financially able to contribute to cleanup costs, a change in conditions or the discovery of additional contamination, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, occurs frequently throughout the United States. This litigation has included claims for damages alleged to have been caused by GHG and other emissions and exposure to regulated substances and/or requests for injunctive relief in connection with such matters. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a material adverse effect on our results of operations and financial condition.

In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could

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contribute to reduced demand for electricity and natural gas, which could adversely affect our results of operations, cash flows, and financial condition.

Our operations, capital expenditures, and financial results may be affected by the impact of greenhouse gas legislation, regulation, and our emission reduction goal.

There has been significant attention to issues concerning climate change as well as activism from certain stakeholders, including institutional investors and other sources of financing, to accelerate the transition to limit GHG emissions. Although the EPA is pursuing a large deregulatory effort of GHG laws and regulations, significant laws and regulations restricting emissions of GHGs continue to impact our current and planned operations. Costs associated with such legislation, regulation, and our emission reduction goal could be significant within our electric and natural gas operations. New or additional restrictive GHG legislation or regulations may cause our environmental compliance spending to differ materially from the amounts currently estimated. There is no guarantee that we will be allowed to fully recover compliance costs of these and other federal and state regulations, or that cost recovery will not be delayed or otherwise conditioned. GHG legislation, regulation, or the emission reduction goal, as well as changes in the fuel markets and advances in technology could make electric generating units uneconomic to maintain, may impact how we operate our existing fossil-fueled power plants and biomass facility, and could cause us to retire and replace units earlier than planned under the WEC Energy Group capital plan, which could lead to a possible loss on abandonment and reduced revenues.

In a movement toward electrification, certain states and municipalities near our service territory have passed legislation or are considering ordinances banning natural gas used in new construction in order to limit GHG emissions. There have also been efforts to restrict residential natural gas-fired appliances. Future actions like these to regulate GHG emissions in our service territories could increase the price of natural gas resulting in reduced demand for, and revenues from, natural gas, cause us to accelerate the replacement and/or updating of our natural gas delivery system, and adversely affect our ability to operate our natural gas facilities. The adoption of electrification initiatives and/or mandates could also result in an increase in electrical demand and increased investment costs for existing or new electrical systems. These types of initiatives and/or mandates could result in increased costs associated with permitting and siting of new technologies and delayed installation and start-up timelines. In addition, financial investments in older carbon-intensive technologies may not be fully realized.

WEC Energy Group has set a goal for its generation fleet, which includes us, to be net carbon neutral by the end of 2050. WEC Energy Group expects to be in a position to eliminate coal as an energy source by the end of 2032. In addition, we continue to monitor the financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases. The ability to achieve this goal depends on many external factors, including the ability to make operating refinements, the retirement of less efficient generating units, the development of relevant energy technologies, the use of RNG throughout our natural gas utility system, the ability to procure renewable thermal credits, legislative and regulatory support for renewable generation, the ability to maintain reliability with demand growth, and the ability of WEC Energy Group to execute its capital plan.

Changes in tax legislation, IRS audits, or our inability to use certain tax benefits and carryforwards, may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings.

Tax legislation and regulations can adversely affect, among other things, our financial condition, results of operations, cash flows, liquidity, and credit ratings. 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 under new beginning of construction rules. Solar and wind tax incentives can be denied for energy projects that use equipment beyond statutory guidelines from prohibited foreign entities or for taxpayers that exceed certain thresholds of equity or debt held by prohibited foreign entities.

Future changes to corporate tax rates or policies, including under Treasury Regulations and guidance issued in connection with the IRA and OBBBA, could require us to take material charges against earnings. Such changes include, among other things, increasing the federal corporate income tax rate, disallowing or limiting the use of solar and wind tax incentives and other tax benefits and carryforwards, limiting interest deductions, and altering the expensing of capital expenditures. Our inability to manage these changes, an adverse determination by one of the applicable taxing jurisdictions, or additional interpretations, implementing regulations, amendments, or technical corrections by the Treasury Department, the IRS, or state income tax authorities, could significantly impact our financial results and cash flows.

We have significantly reduced our federal and state income tax liabilities in the past through tax credits, net operating losses, and charitable contribution deductions. A reduction in or disallowance of these tax benefits could adversely affect our earnings and cash

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flows. We have not fully used these allowed tax benefits in our previous tax filings and have carried them forward to use against future taxable income. Our inability to generate sufficient taxable income in the future to fully use these tax carryforwards before they expire, or to transfer future tax credits as discussed below, could significantly affect our tax obligations and financial results.

In addition, we have invested, and plan to continue to invest, in renewable energy generating facilities. These facilities generate PTCs or ITCs that we can use to reduce our federal tax obligations. Under the IRA, a transferability option also allows us to sell these tax credits to third parties. The amount of tax credits we earn depends on available government incentives and policies, the amount of electricity produced, the applicable tax credit rate, or the amount of the investment in qualifying property. Reductions or eliminations of tax credits or other governmental incentives that promote renewable energy generating facilities, or the imposition of additional taxes, tariffs, or other assessments related to renewable energy projects or the equipment necessary to generate or deliver it, may limit our ability to make further investments in renewable energy generating facilities or reduce the returns on our existing investments. In addition, a variety of operating and economic factors, including transmission constraints, adverse weather conditions, and breakdown or failure of equipment, could significantly reduce the PTCs generated by the renewable projects we have invested in, any of which could result in a material adverse impact on our financial condition and results of operations.

We are also uncertain as to how credit rating agencies, capital markets, the FERC, or state public utility commissions will treat any future changes to federal or state tax legislation. These impacts could subject us to credit rating downgrades. In addition, certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted by changes in federal or state income tax legislation.

We could be subject to higher costs and penalties as a result of mandatory reliability standards.

We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cybersecurity assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. Noncompliance with the mandatory reliability standards could result in sanctions, including substantial monetary penalties, or damage to our reputation.

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.

Public health crises, including epidemics and pandemics, and any related government responses may adversely impact the economy and financial markets and could have a variety of adverse impacts on us, including a decrease in revenues; increased bad debt expense; increases in past due accounts receivable balances; and access to the capital markets at unreasonable terms or rates. These crises and any related government responses could also impair our ability to develop, construct, and operate facilities. Risks include extended disruptions to supply chains and inflation, resulting in increased costs for labor, materials, and services, which could adversely impact WEC Energy Group's ability to implement its corporate strategy. We may also be adversely impacted by labor disruptions and productivity as a result of infections, employee attrition, or the inability to replace or maintain appropriate staffing. The extent to which future public health crises may affect us depends on factors beyond our knowledge or control. As a result, we are unable to determine the potential impact any such public health crises may have on our business plans and operations, liquidity, financial condition, and results of operations.

Our operations are subject to risks arising from the reliability and safety of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, renewable energy facilities, and other facilities, as well as the reliability of third-party transmission providers.

Our financial performance depends on the successful operation of our electric generation and transmission, natural gas and electric distribution facilities, and renewable energy facilities. Inherent in electric generation and distribution and natural gas transportation and distribution activities are a variety of hazards and operational risks, including accidents, operator error, and the breakdown or failure of equipment or processes including leaks, accidental explosions, mechanical problems, fires, discharges or releases of toxic or hazardous substances or gases, and other environmental risks. Potential breakdown or failure may occur due to severe weather (i.e., storms, tornadoes, floods, droughts, etc.); catastrophic events (i.e., fires, earthquakes, and explosions); public health crises; significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; delays in the replacement of aging infrastructure; shortages of or delays in obtaining

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equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist or other physical attacks; or cybersecurity intrusions.

The location of natural gas pipelines near populated areas could increase the level of damages resulting from these risks. Unplanned outages at our power plants may cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations. Because our electric generation and renewable energy facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems.

These hazards and operational risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of operations. They may also subject us to litigation and/or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms. Any of these events could lead to substantial financial losses, including increased maintenance costs, and unanticipated capital expenditures, and a reduction of revenues, which could materially and adversely affect our results of operations, financial condition, and cash flows.

Our natural gas operations depend upon the availability of adequate interstate pipeline transportation capacity and natural gas.

We purchase almost all of our natural gas supply from interstate sources that must be transported to our service territory. Interstate pipeline companies transport the natural gas to our natural gas systems under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to interstate pipelines capacity or reduction in natural gas supply due to events including, but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze-off of natural gas wells, terrorist or physical attacks, cyberattacks, other acts of war, or legislative or regulatory actions or requirements, including remediation related to integrity inspections or regulations and laws enacted to address climate change or other environmental matters, could reduce the normal interstate supply of natural gas and thereby significantly disrupt our operations and/or reduce earnings.

Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including fluctuations in customer growth and general economic conditions in our service area, varying weather conditions, and energy conservation efforts.

Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:

•Fluctuations in customer growth and general economic conditions in our service area. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territory, including workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. Our electric and natural gas operations are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

•Weather conditions. Demand for electricity is greater in the summer and winter months when cooling and heating is necessary. Demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate on a seasonal basis and could be negatively impacted by milder temperatures during the summer cooling season and winter heating season.

•Our customers' continued focus on energy conservation. Our customers' use of electricity and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies, and could be further reduced by new building codes, DERs, energy storage technology, and private solar. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. For example, several states, including Wisconsin, have adopted energy efficiency targets to reduce energy consumption.

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of fluctuations in energy demand or the adoption of new technologies, could adversely impact our results of operations and financial condition. In addition, elimination or reduced financial support of programs that provide energy assistance

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to our customers, including the Low Income Home Energy Assistance Program, could impact the demand for energy and/or adversely impact our liquidity.

Our operations are subject to the effects of global climate change.

A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territory. If climate changes occur that result in extreme temperatures in our service territory, our financial results could be adversely impacted by lower electric and natural gas usage and higher natural gas costs. Our operations could be adversely affected and our facilities placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, which could result in more intense, frequent and extreme weather events, such as storms, including derecho events, with high winds, lightning, and hail, floods, drought, wild fires, tornadoes, snow and ice storms, or abnormal levels of precipitation. An extreme weather event could result in damage to distribution and transmission infrastructure, wind and solar generation facilities, or other operating equipment. This could result in us incurring significant restoration costs and foregoing sales of energy and lost revenues. Extreme weather in summer could cause electric load to be interrupted or certain customers to be curtailed who participate in load management programs. Additionally, an extreme weather event could also cause the cost of natural gas purchased for our natural gas utility customers and for the use of fuel at our generation facilities to be temporarily driven significantly higher than our normal winter weather expectations. Although we have a regulatory mechanism in place for recovering all prudently incurred natural gas costs, our regulators could disallow recovery or order the refund of any costs determined to be imprudent.

Extreme weather may also result in unexpected increases in customer load, requiring us to procure additional power at wholesale prices for our retail operations, unpredictable curtailment of customer load by MISO to maintain grid reliability, or other grid reliability issues. Any of these events could lead to substantial financial losses including increased maintenance costs or unanticipated capital expenditures. The cost of storm restoration efforts may also not be fully recoverable through the regulatory process.

Changes in WEC Energy Group's corporate strategy to combat climate change, including mitigation and adaptation efforts and technology advancement, may materially adversely impact our results of operations and cash flows.

Our operations and future results may be impacted by changing expectations and demands of our customers, regulators, investors, and other stakeholders.

Our ability to execute WEC Energy Group's corporate strategy and achieve anticipated financial outcomes are influenced by the expectations of our customers, regulators, investors, and other stakeholders. Those expectations are based in part on the core fundamentals of affordability and reliability but are also increasingly focused on our ability to meet rapidly changing demands for new and varied products, services, and offerings. Efforts to roll back certain environmental rules and social policies and programs may conflict with the expectations of our customers, regulators, or investors, creating additional uncertainty as we look to balance our stakeholders' competing priorities, and could lead to litigation and government investigations. Failure to meet these expectations or to adequately address the risks and external pressures may impact our reputation and affect our ability to achieve favorable outcomes in future rate cases or our results of operations. Furthermore, the increasing use of social media may accelerate and increase the potential scope of negative publicity we might receive and could increase the negative impact on our reputation, business, results of operations, and financial condition.

Our operations and WEC Energy Group's corporate strategy may be adversely affected by supply chain disruptions, inflation, and tariffs.

Our business is dependent on the global supply chain to ensure that equipment, materials, and other resources are available to both expand and maintain services in a safe and reliable manner. Increased tensions between the United States and other countries, as well as new, protracted, or escalating regional or international conflicts, could result in domestic and global supply chain disruptions that delay the delivery, or result in shortages of, materials, equipment, and other resources that are critical to our business operations. Failure to eliminate or manage the constraints in the supply chain may eventually impact the availability of items that are necessary to support normal operations as well as materials that are required to implement WEC Energy Group's corporate strategy for continued utility and infrastructure growth, including our renewable energy projects.

Prices of equipment, materials, and other resources have increased and may continue to increase in the future, as a result of supply chain disruptions, inflation, and tariffs. Further governmental actions related to trade policy could exacerbate global supply chain disruptions and/or inflation. Increased costs for labor, materials, and services, as a result of supply chain disruptions, inflation, or

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tariffs, and failure to secure these resources on economically acceptable terms, as well as any regulatory delay in adjusting rates to account for increased costs, may adversely impact our business operations, financial condition, and/or capital plan.

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.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, LNG storage, and other projects, including projects for environmental compliance. We also expect to continue constructing and investing in renewable energy and natural gas generating facilities as part of the WEC Energy Group capital plan and its goal to be net carbon neutral by the end of 2050. In addition, we continue to invest in technology and the development of software applications to support our business.

Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. Supply chain disruptions, including solar panel shortages and delays, increasing material costs, government regulations and tariffs, and other factors, could impact the timing of completion of our renewable projects. Additional risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; rising interest rates; inflation; tariffs; the impact of public health crises; other governmental actions; continued public and policymaker support for such projects; and events in the global economy.

Certain of these projects require the approval of the PSCW. If construction of PSCW-approved projects should materially and adversely deviate from the schedules, estimates, and/or projections on which the approval was based, the PSCW may deem the additional capital costs as imprudent and disallow recovery of them through rates, and otherwise available PTCs and ITCs for renewable energy projects could be lost or lose value. Efforts to pause approvals related to wind development could threaten our ability to execute our capital plan. Other renewable energy sources, including solar developments, could also be at risk. In addition, the PSCW, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed.

To the extent that delays occur, costs become unrecoverable, tax credits are lost or lose value, or we or third parties with whom we invest and/or partner otherwise become unable to effectively manage and complete capital projects, our results of operations, cash flows, and financial condition may be adversely affected.

We face risks related to providing service to our large-scale customers, including potential customers under our proposed VLC and Bespoke Resources Tariffs, which could impact our business, results of operations, and financial condition.

We are engaged in discussions with a small number of customers to provide power to large-scale data centers being constructed to support AI and other technology capabilities. Because of the significant demand and energy needs associated with these facilities, extending service to these facilities requires investment in incremental electric infrastructure. Subject to pending regulatory approvals from the PSCW, we have made and will continue to make significant infrastructure investments in new solar and battery projects, natural gas power plants, and other generation and distribution assets to power and serve these large-scale data centers and other projects. Our transmission affiliate, ATC, also has made and will continue to make significant investments in additional transmission infrastructure to serve the increased customer load.

In March 2025, we filed an application with the PSCW requesting approval to implement a VLC Tariff and a Bespoke Resources Tariff. Under these proposed inter-connected tariffs, VLCs directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them and transmission costs allocated to their usage. The proposed tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or other business customers. We are incurring significant engineering, design, and equipment costs in advance of receiving approval of the tariffs as well as necessary regulatory and other approvals for the needed generation, distribution, and transmission projects. If any of these projects are canceled for any reason, including due to lower than forecasted demand or for failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur. In addition, if any construction work or investments have already been recorded as an asset, an impairment loss may need to be recorded. We may not be allowed to recover these penalties, other costs incurred, or impairment losses in customer rates, which could have a material adverse effect on our results of operations. We require VLCs to enter into payment and cancellation agreements which obligate the VLC to reimburse us for all costs associated with projects requested by the customer until service agreements are executed under the approved tariffs. Reimbursement is also 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

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project. Despite these risk mitigating efforts, we may still experience significant losses or delayed recovery of these costs. In addition, the ability to obtain regulatory approval of one or more projects and/or the VLC and Bespoke Resources Tariffs may affect our ability to recover costs with acceptable conditions for these large-scale customers.

The ability to complete large capital projects is dependent upon a number of factors, including the ability to obtain financing of such projects on satisfactory terms and conditions. Along with the significant capital spend, a portion of the expected earnings growth from these projects will result in an increase in AFUDC as part of CWIP, with recovery of these costs delayed until the capital project is placed in service. As a result of this delay in receiving cash proceeds, we may be required to issue additional debt to support these projects, which could negatively impact our earnings, balance sheet, and/or credit metrics. Other dependent factors include the ability to secure regulatory permits, secure sufficient land for the siting of power generation facilities, obtain necessary interconnection or transmission service in MISO, garner public support for these projects, and the ability of suppliers and contractors to fulfill their obligations under contracts. Successful completion of these projects may be further influenced by changes in law or regulation, such as new legislation or regulation impacting large data center cost allocation or environmental compliance requirements, trade and tariff issues, including those associated with imported solar panels, as well as supply chain delays or disruptions, workforce challenges, and other events beyond our control. If these projects are significantly delayed or become subject to cost overruns or cancellation due to these or other factors, we could incur additional costs and termination payments or face increased risk of potential write-offs of our investments in these projects. The occurrence of any of these events may materially affect the schedule, cost, and performance of these projects.

This concentration of business with a small number of customers in an industry based on emerging technologies, including AI and machine learning, presents several risks. We cannot predict the rate at which or the extent to which these emerging technologies will be broadly adopted and successful as business models. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers. Significant capital spend to build out required infrastructure or a downturn in business could cause the loss of these customers or may weaken their financial condition, liquidity and/or creditworthiness, including their ability to satisfy their reimbursement obligations to us. Similarly, customers may reduce their investment in these new technologies or abandon them entirely.

Any of these situations may result in the early termination or non-renewal of these customers’ electric service agreements or renewal on terms less favorable to us. Electric service agreements with these customers include provisions for early termination payments, but they may not fully protect against all risks. While the assets constructed to serve these customers may otherwise be useful in our utility operations, there is a risk that we may not be able to fully recover our investment in or a return on those assets.

Our business, results of operations, and financial condition could be materially adversely affected as a result of any or all of these factors.

Our operations are subject to risks beyond our control, including but not limited to, cybersecurity intrusions, terrorist or other physical attacks, acts of war, or unauthorized access to personally identifiable information.

We have been subject to attempted cyber attacks from time to time, and will likely continue to be subject to such attempted attacks; however, these prior attacks have not had a material impact on our system or business operations. All of our assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to physical or cybersecurity intrusions caused by human error, vendor bugs, terrorist or other physical attacks (including potential attacks on our substations and other electric distribution equipment), acts of war, or other malicious acts. Cybersecurity threats could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. If our assets or systems were to fail, be physically damaged, or be breached, and were not recovered in a timely manner, we may be unable to perform critical business functions, and data, including sensitive information, could be compromised. Cybersecurity attacks, including attacks targeting utility systems and other critical infrastructure, may increase during periods of heightened or escalating geopolitical tensions.

We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which in turn control an interconnected network of generation, distribution, and transmission systems shared with third parties. A successful physical or cybersecurity intrusion may occur despite our security measures or those we require of our vendors, including compliance with reliability and critical infrastructure protection standards. Successful cybersecurity intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission, distribution, and LNG storage systems, could disrupt our operations and result in loss of service to customers. Attacks may come through ransomware, software updates or patches, or firmware that hackers can manipulate. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher

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cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

Our continued efforts to integrate, consolidate, and streamline our operations with those of WEC Energy Group's other subsidiaries have also resulted in increased reliance on current and recently completed projects for technology systems. The failure to enhance existing information technology systems and adopt or successfully implement new technology could adversely affect our operations. Cybersecurity threats, including those leveraging AI, continue to increase, and the security measures and preventative actions we take to reduce the risk of cybersecurity incidents and protect our systems against unauthorized access to secured data and systems may be insufficient to safeguard against all security breaches. The failure of any of these important technologies, or our inability to support, update, expand, and/or integrate these technologies with those of our affiliates, could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks, and subject us to possible financial liability or increased regulation or litigation.

Our business requires the collection and retention of personally identifiable information of our customers and employees, who expect that we will adequately protect such information. In some cases, we rely on third-party hosted services to support our business operations. Malicious actors may target these providers to disrupt the services they provide to us, or to use those third parties to attack us. Security breaches of our or our third-party service providers' systems may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.

Threats to our systems and operations continue to emerge as new ways to compromise components into our systems or networks are developed. Any operational disruption or environmental repercussions caused by on-going or future threats to our assets and technology systems could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows. The costs of repairing damage to our facilities, operational disruptions, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may also not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

Adoption of AI technologies could adversely affect our business, reputation, or financial results.

We are using AI primarily through services provided by our third party vendors. In addition, we are exploring the use of AI, including generative AI, and its ability to enhance the services we offer. There are significant risks involved in developing and deploying AI, and there can be no assurance that the use of AI will enhance our services or be beneficial to our business, including with respect to the efficiency and resiliency of our systems. Our AI-related efforts may give rise to risks related to accuracy, bias, discrimination, intellectual property infringement or misappropriation, data privacy, and cybersecurity, among others. In addition, the adoption of AI may subject us to new or enhanced governmental or regulatory scrutiny, laws, rules, directives, or regulations governing the use of AI, as well as litigation, ethical concerns, negative customer perceptions as to automation and AI, legal liability or other complications that could adversely affect our business, reputation, or financial results. We may not be able to recover our investments in AI technology through our regulatory proceedings. Similarly, as AI continues to evolve, we may not be able to adopt and implement AI as quickly as our customers or communities desire or regulators may require. AI is a relatively new and rapidly evolving technology, and we are unable to predict all of the risks that may result from our and our vendors' adoption of AI initiatives.

Advances in technology, and legislation or regulations supporting such technology, could make our electric generating facilities less competitive and may impact the demand for natural gas.

Advances in new technologies that produce or store power or reduce power consumption are ongoing and include renewable energy technologies, customer-oriented generation, energy storage devices, and energy efficiency technologies. We generate power at central station power plants and utility-scale renewable generation facilities to achieve economies of scale and produce power at a competitive cost. Distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, solar cells, and related energy storage devices, have technologically improved and have become more cost competitive than they were in the past.

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Legislation, including the IRA and the Infrastructure Investment and Jobs Act, has promoted the construction and cost-effectiveness of renewable energy generation, including distributed generation technologies for self-supply of electricity by our customers and third parties. Increased use of technologies such as private solar and battery storage in our service territories could reduce our recovery of fixed costs, could result in customers leaving the electric distribution system, and could cause an increase in customer net energy metering, which allows customers with private solar to receive bill credits for surplus power at the full retail amount. Over time, customer adoption of these technologies could result in us not being able to fully recover the costs and investment in generation.

Federal and state regulations and other efforts designed to promote and expand the use of distributed generation technologies also incentivize modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity and increase the grid's capacity to interconnect to these distributed generation technologies. Other legislation or regulations could be adopted supporting the use of these technologies at below cost or that permit third-party sales from such facilities, and allow these facilities to interconnect to our distribution system. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station and utility-scale renewable power production. In addition, regulatory support of co-locating generation near data centers could impact our generation planning and its related cost recovery and could cause our generation to be less cost effective.

We also cannot predict the effect that development of alternative energy sources or new technology may have on our natural gas operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for natural gas.

If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities and natural gas distribution systems could be reduced. Advances in technology, or changes in legislation or regulations, could also change the channels through which our customers purchase or use power and natural gas, which could reduce our sales and revenues or increase our expenses.

We may fail to attract and retain an appropriately qualified workforce.

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

Our counterparties may fail to meet their obligations, including obligations under power purchase, natural gas supply, natural gas pipeline capacity, and transportation agreements.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform or if capacity is inadequate, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.

We have entered into several power purchase, natural gas supply, natural gas pipeline capacity, and transportation agreements with non-affiliated companies. Revenues are dependent on the continued performance by the counterparties of their obligations under these agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations. If this were to occur, we generally would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase, natural gas supply, natural gas pipeline capacity, or transportation agreement would be reallocated among our retail customers. To the extent these costs are not allowed to be reallocated by our regulators or there is any regulatory delay in adjusting rates, a counterparty default under these agreements could have a negative impact on our results of operations and cash flows.

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Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access credit and capital markets on competitive terms and rates.

We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets. The availability of credit depends upon the ability of banks providing commitments under the facility to provide funds when their obligations to do so arise. Systemic risk of the banking system and the financial markets could prevent a bank from meeting its obligations under the credit agreement.

Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. An increase in interest rates may adversely affect our results of operations and our ability to earn our approved rate of return. High interest rates may also impair our ability to cost-effectively finance capital expenditures and to refinance maturing debt.

Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:

•A rating downgrade;

•Failure to comply with debt covenants;

•An economic downturn or uncertainty;

•Prevailing market conditions and rules;

•Political tensions, including civil unrest and election volatility;

•Concerns over foreign economic conditions;

•Changes in tax policy;

•Changes in investment criteria of institutional investors or banks;

•War or the threat of war;

•Growth in AFUDC during periods of significant construction; and

•The overall health and view of the utility and financial institution industries.

If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, and financial condition.

A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.

There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in ratings if the rating agencies determine that our level of business or financial risk, or that of the utility industry, has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. Any downgrade by the rating agencies could increase borrowing costs under our existing credit facility or future financings, decrease funding sources, limit the availability of adequate credit support for our operations, and trigger collateral requirements in various contracts.

The fluctuation in demand for certain commodities and their respective prices could negatively impact our operations.

Our operating and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.

We burn natural gas in several of our electric generation plants and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations and/or other government action affecting its accessibility. We also burn coal at certain of our electric generation facilities. We may be obligated to pay for coal deliveries under our contracts even if our coal-fired generating facilities do not operate enough to fully utilize the amounts of coal covered by the contracts.

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For Wisconsin retail electric customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our wholesale electric customers. We receive dollar-for-dollar recovery of prudently incurred natural gas costs from our natural gas customers.

Changes in the demand for commodities and their respective prices could result in:

•Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;

•Reduced profitability to the extent that lower revenues, higher fuel costs, increased bad debt, and higher interest expense are not recovered through rates;

•Higher rates charged to our customers, which could impact our competitive position;

•Reduced demand for energy, which could impact revenues and operating expenses; and

•Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

We own, lease, and operate several coal-fired electric generating units. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. Coal deliveries may occasionally be restricted because of rail congestion and maintenance, derailments, weather, public health crises, and supplier financial hardship as a result of decreased demand for coal. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units, which could lead to increased fuel costs. The increase in fuel costs could result in either reduced margins on net sales into the MISO Energy Markets, a reduction in the volume of net sales into the MISO Energy Markets, and/or an increase in net power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our results of operations and cash flows.

Our use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Restructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business and revenues.

The regulated energy industry continues to experience significant structural changes. Deregulation or other changes in law in Wisconsin could allow third-party suppliers to contract directly with customers for their natural gas and electric supply requirements. Increased competition in these markets could have a material adverse financial impact on us.

The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC-approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. MISO also implemented an ancillary services market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market. These market designs have the potential to increase costs related to transmission, inefficient generation dispatching, participation in the MISO Energy Markets, and estimated payment settlements.

The FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to

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wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.

Volatility in the securities markets, interest rates, changes in assumptions, market conditions, and other factors may impact the performance of our benefit plan holdings and other investment funds.

We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted. Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements), or changes in life expectancy assumptions.

General Risks

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers and our contractors that are required to acquire and maintain insurance for our benefit. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

As a wholly-owned subsidiary of WEC Energy Group, our cybersecurity-related risks are managed by WEC Energy Group's cybersecurity risk management program.

WEC Energy Group's Board of Directors is responsible for general oversight of the risk environment and associated management policies and practices of WEC Energy Group and its subsidiaries, including us. The WEC Energy Group Board of Directors has delegated to its AOC the responsibility for oversight of our major risk categories and exposures, including with respect to cybersecurity, and management's processes to monitor and control them. The AOC meets regularly throughout the year and receives and reviews various risk management reports about IT/OT cybersecurity, data security, and physical security risks, and discusses these matters with appropriate management and other personnel. WEC Energy Group's CEO (who also serves as our CEO) and its CAO regularly report to the AOC and the WEC Energy Group Board of Directors about cybersecurity matters and risks as well as the adequacy and effectiveness of the cybersecurity risk management program.

To foster an enterprise-wide approach to risk management, WEC Energy Group has established an ERSC chaired by its CEO and comprised of a cross-functional group of senior leaders from across WEC Energy Group's organization. The ERSC regularly reviews key risk areas and oversees the development and implementation of effective compliance and risk management practices, including the use of internal and external audits. WEC Energy Group's Board of Directors and the AOC receive reports regarding the same. Governance of WEC Energy Group's cybersecurity risk management program is overseen by the ERSC, along with steering

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committees for information security, operational technology security, third-party vendor security controls, Sarbanes-Oxley security controls, and North American Electric Reliability Corporation Critical Infrastructure Protection compliance.

WEC Energy Group's CAO is responsible for enterprise-wide information technology services and cybersecurity system strategy. In this capacity, the CAO oversees the cybersecurity risk management program, which is maintained and implemented by the Enterprise Security Director. WEC Energy Group's CAO has 26 years of experience at the company, during which time she has held a number of management and leadership positions, including Chief Information Officer, through which she has developed expertise in WEC Energy Group's IT/OT cybersecurity, data security, and physical security environment and risk profile.

The Enterprise Security Director, in collaboration with her team, is responsible for IT/OT cybersecurity, data security, and physical security. The Enterprise Security Director identifies, evaluates, and facilitates mitigation of cyber, data, and physical security risks and reports on cybersecurity matters and risks to the ERSC and the AOC. The Enterprise Security Director has over 28 years of experience in IT/OT cybersecurity, data security and physical security, and is a certified information system security professional. She is also a member of numerous state and national cybersecurity organizations.

Cybersecurity Risk Management Program

Our cybersecurity-related risks are managed through monitoring, defense and response tools, audits and assessments of the program’s effectiveness, industry collaboration, and employee training and awareness. WEC Energy Group's cybersecurity risk management program utilizes the cybersecurity framework and maturity models from the National Institute of Standards and Technology and the DOE to continually assess its maturity. This includes regular internal security audits and vulnerability assessments, as well as regular engagement with third-party security experts for external assessments of WEC Energy Group's security controls, including technical, physical, and social aspects. To better comprehend the scope and magnitude of any active threats to our industry and nation and their potential impact on our IT/OT systems, we communicate with other utility companies, government agencies, and other sectors of the economy concerning cybersecurity incidents. All employees are required to complete training annually regarding information security and acceptable use of corporate electronic resources. Annual role-based cybersecurity training as well as ongoing participation in a corporate phishing campaign program, is also required of employees and contractors. In addition, as part of the cybersecurity program, WEC Energy Group has established controls and procedures to assess the adequacy of controls in place at third-party vendors to protect corporate information, including restricted and confidential restricted information we provide to third-party vendors, their employees, or authorized agents. These third-party vendors are also subject to a background investigation prior to being granted physical or electronic access to the company's private property, or physical access to customer premises on behalf of the company.

As part of the cybersecurity program, WEC Energy Group has adopted a cybersecurity incident response plan (the “Plan”) designed to identify, evaluate, respond to, and resolve cybersecurity incidents impacting IT/OT systems. Pursuant to the terms of the Plan, WEC Energy Group has established a CSIRT Steering Committee which includes, among others, WEC Energy Group's Chief Financial Officer (who also serves as our Chief Financial Officer), CAO, and the Enterprise Security Director. The CSIRT Steering Committee is responsible for overseeing and implementing the Plan in the event of a cybersecurity threat or incident and provides updates regarding the status of the response to senior management, including WEC Energy Group's CEO, who provides updates and reports regarding cybersecurity incidents to the AOC and/or the WEC Energy Group Board of Directors at regularly scheduled meetings or more frequently, as needed.

In response to an identified cybersecurity incident, or as it deems appropriate, the CSIRT Steering Committee will assemble and oversee a CSIRT, comprised of appropriate personnel and subject matter experts depending on the scope and severity of the incident, relevant or impacted business units and entities, and type of information or systems potentially compromised by the cybersecurity incident. When assembled, the CSIRT is responsible for developing and implementing an overall response strategy to contain, control, and remediate the cybersecurity incident, including securing affected systems and/or information, mitigating harmful effects of the incident, preventing further compromises, and communicating information to affected parties, regulatory agencies and law enforcement, as necessary. The CSIRT may seek assistance from or engage external support providers including legal counsel, outside technology or forensic experts, investigation service providers, and others, as appropriate, to assist in the response to the incident, based on its nature and scope. Pursuant to the Plan and at the direction of WEC Energy Group's CAO, the Enterprise Security Director will conduct a post-incident remediation analysis and report findings to the CSIRT Steering Committee. The Plan is tested and reviewed at least annually.

We have been subject to attempted cybersecurity attacks from time to time, and will likely continue to be subject to such attempted attacks; however, these prior attacks have not had a material impact on our system or business operations. For information about

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cybersecurity risks to our business, see Item 1A. Risk Factors and the risk factor titled "Our operations are subject to risks beyond our control, including but not limited to, cybersecurity intrusions, terrorist or other physical attacks, acts of war, or unauthorized access to personally identifiable information."

ITEM 2. PROPERTIES

We own our principal properties outright. However, the major portion of our electric utility distribution lines, steam utility distribution mains and natural gas utility distribution mains and services are located on or under streets and highways, on land owned by others, and are generally subject to granted easements, consents, or permits. In addition, we lease the ERGS and PWGS generating units from We Power.

Electric Facilities

The following table summarizes information on generating assets we owned or leased from We Power as of December 31, 2025:

Name						Location						Fuel						Number of Generating Units						Capacity In MW (1)
Natural gas-fired plants
PWGS						Port Washington, WI						Natural Gas						2						1,210
Paris						Union Grove, WI						Natural Gas/Oil						4						360
Concord Generating Station						Watertown, WI						Natural Gas/Oil						4						367
VAPP						Milwaukee, WI						Natural Gas						2						278
Germantown Power Plant						Germantown, WI						Natural Gas/Oil						5						261
West Riverside						Beloit, WI						Natural Gas						1						190			(2)
Whitewater						Whitewater, WI						Natural Gas/Oil						1						117			(2)
Weston						Rothschild, WI						Natural Gas						7						65			(2)
Total natural gas-fired plants																		26						2,848
Coal-fired plants
ERGS						Oak Creek, WI						Coal						2						1,083
OCPP						Oak Creek, WI						Coal						2						607			(5)
Total coal-fired plants																		4						1,690
Wind facilities
Glacier Hills Wind Park						Cambria, WI						Wind						90						162
Blue Sky Green Field Wind Park						Fond du Lac, WI						Wind						88						145
Montfort Wind Energy Center						Montfort, WI						Wind						20						30
Total wind facilities																		198						337
Solar facilities
Darien						Rock and Walworth counties, WI						Solar						65						188			(2)
Paris						Kenosha County, WI						Solar						53						150			(2)
Badger Hollow II						Iowa County, WI						Solar						40						100			(2)
DER Facilities (4 in number)						Wisconsin						Solar						12						30			(6)
Solar Now						Wisconsin						Solar						28						30
Total solar facilities																		198						498
Other renewable facilities
Hydro plants (9 in number)						WI and MI						Hydro						30						43			(3)
Rothschild						Rothschild, WI						Biomass						1						46			(4)
Total other renewable facilities																		31						89
Total system																		457						5,462

(1)    Capacity for our electric generation facilities, other than wind and solar generating facilities, is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2026 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

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(2)    We jointly own these facilities with various other affiliated and unaffiliated entities. The capacity indicated for each of these units is equal to our portion of total plant capacity based on our percent of ownership. See Note 9, Jointly-Owned Utility Facilities, for more information.

(3)     All of our hydroelectric facilities follow FERC guidelines and/or regulations.

(4)    We have a biomass power plant that uses wood waste and wood shavings to produce electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers. The plant also has the ability to burn natural gas if wood waste and wood shavings are not available.

(5)    WEC Energy Group expects to retire approximately 900 MWs of additional coal-fired generation, which includes the planned retirement of OCPP Units 7-8. See Note 8, Property, Plant, and Equipment, for more information

(6)    DER facilities are distribution system interconnected solar projects that are typically 5-10 MWs each.

As of December 31, 2025, we operated approximately 19,400 miles of overhead distribution lines and approximately 27,000 miles of underground distribution cable, as well as approximately 300 electric distribution substations and approximately 315,200 line transformers.

Battery Energy Storage Systems

We also own 82.5 MWs of BESS at Paris located in Kenosha County, Wisconsin which was completed in June 2025.

Natural Gas Facilities

At December 31, 2025, our natural gas properties were located in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin, and consisted of the following:

•Approximately 9,700 miles of natural gas distribution mains,

•Approximately 230 miles of natural gas transmission mains,

•Approximately 430,400 natural gas lateral services,

•Approximately 30 natural gas distribution and transmission gate stations,

•A 1.0 Bcf LNG plant located in southern Wisconsin, and

•LNG storage plants with a total send-out capability of 170,000 Dth per day.

Our natural gas distribution and gas storage systems included distribution and transmission mains connected to the pipeline transmission systems of ANR Pipeline Company, Great Lakes Transmission Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Gas Company, and Vector Pipeline. Our LNG storage plant converts and stores, in liquefied form, natural gas received during periods of low consumption.

We also own office buildings, natural gas regulating and metering stations, and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and natural gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

Steam Facilities

As of December 31, 2025, the steam system supplied by the VAPP consisted of approximately 40 miles of both high pressure and low pressure steam piping, approximately four miles of walkable tunnels, and other pressure regulating equipment.

ITEM 3. LEGAL PROCEEDINGS

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

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The names, ages, and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until their resignation, death, or removal pursuant to our Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.

Robert M. Garvin. Age 59.

•WEC Energy Group — Executive Vice President - External Affairs since June 2015.

•WBS (a centralized service company of WEC Energy Group) – Executive Vice President - External Affairs since January 2019.

William J. Guc. Age 56.

•WEC Energy Group — Controller since October 2015. Vice President since June 2015.

•WE — Vice President and Controller since October 2015. Assistant Corporate Secretary from January 2020 to December 2024.

Michael W. Hooper. Age 52.

•WEC Energy Group — Executive Vice President and Chief Operating Officer since May 2025.

•WE — President since April 2024. Director since April 2024.

•NiSource, Inc. — Senior Vice President and President, NIPSCO from May 2020 to March 2024. NiSource is a public utility holding company whose operating subsidiaries provide natural gas and electric service to customers across Indiana, Kentucky, Maryland, Ohio, Pennsylvania, and Virginia. NIPSCO is a public natural gas and electric utility company in Indiana.

Margaret C. Kelsey. Age 61.

•WEC Energy Group — Executive Vice President, Corporate Secretary and General Counsel since January 2018.

•WE — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Director since January 2018.

Scott J. Lauber. Age 60.

•WEC Energy Group — President and Chief Executive Officer since February 2022. Senior Executive Vice President and Chief Operating Officer from June 2020 to January 2022. Director since February 2022.

•WE — Chairman of the Board and Chief Executive Officer since February 2022. President from January 2022 to April 2024. Executive Vice President from June 2020 to December 2021. Director since April 2016.

Xia Liu. Age 56.

•WEC Energy Group — Executive Vice President and Chief Financial Officer since June 2020.

•WE — Executive Vice President and Chief Financial Officer since June 2020. Director since June 2020.

Anthony L. Reese. Age 44.

•WEC Energy Group — Vice President and Treasurer since October 2019.

•WE — Vice President and Treasurer since October 2019.

Certain executive officers also hold officer and/or director positions at WEC Energy Group's other significant subsidiaries.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our common stock, as WEC Energy Group owns all of our outstanding common stock. See Note 11, Common Equity, for more information.

ITEM 6. RESERVED

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We also provide wholesale electric service to numerous utilities and cooperatives for resale. We conduct our business primarily through our utility reportable segment. See Note 20, Segment Information, for more information on our reportable business segments.

Corporate Strategy

We are working to build and sustain long-term value for our customers and WEC Energy Group's shareholders 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. WEC Energy Group's capital plan provides a roadmap to achieve this goal. It is a plan premised upon maintaining superior reliability, delivering savings for customers, and growing WEC Energy Group's and our investment in the future of energy.

Throughout its strategic planning process, WEC Energy Group takes 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 service territory. Companies are investing in major projects, including data centers and modern manufacturing facilities. WEC Energy Group anticipates 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 WEC Energy Group's shareholders. See Note 24, 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. WEC Energy Group's capital plan addresses that demand with a range of planned investments in natural gas-fired generation, renewables, and battery storage. WEC Energy Group plans 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.

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WEC Energy Group expects to invest approximately $12.6 billion from 2026 to 2030 in regulated renewable energy in Wisconsin. WEC Energy Group's plan is to build and own zero-carbon-emitting renewable generation facilities that are anticipated to include the following investments to be made by either us or WPS based on specific customer needs:

•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.

WEC Energy Group's capital plan also reflects the planned retirement of older, fossil-fueled generation, which it expects 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 WEC Energy Group's and our goal to reduce CO2 emissions from our electric generation. Over the long-term, the goal is to achieve net carbon neutral electric generation by the end of 2050. WEC Energy Group expects to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. WEC Energy Group expects 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. Additionally, WEC Energy Group has 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 retirement of the Pleasant Prairie power plant. WEC Energy Group expects 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. See Note 8, 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 WEC Energy Group's supply with its demand, while helping to address compliance and maintaining reliable, affordable energy for our customers.

WEC Energy Group also continues to focus on methane emission reductions by improving and upgrading its natural gas distribution systems and using RNG throughout its natural gas utility systems. The RNG supplied is replacing higher-emission methane from natural gas that would have entered the pipes.

Reliability

We have made significant reliability-related investments in recent years, and in accordance with the WEC Energy Group 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 our 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 WEC Energy Group's capital plan, which includes us. The facilities would provide another approximately four Bcf of natural gas supply (of which our portion is expected to be approximately two Bcf) and are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

•The WEC Energy Group 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.

•We continue to upgrade our electric and natural gas distribution systems to enhance reliability and storm hardening.

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WEC Energy Group expects 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 the WEC Energy Group 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 us and our customers. This program reduces the manual effort for customer connections and enhances outage management capabilities.

Through WEC Energy Group's 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.

WEC Energy Group continues to focus on integrating the resources of all its businesses and improving its business processes to find the best and most efficient processes possible, including evaluating the use of AI tools. WEC Energy Group expects these efforts to continue to drive operational efficiency and to put it 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, and quality credit ratings. We work to earn allowed rates of return through a focus on cost control and strategic investment.

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, and equipment, 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 more information.

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 all of the WEC Energy Group companies. It has moved all utilities, including us, 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 the WEC Energy Group companies.

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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

Our earnings for the year ended December 31, 2025 were $626.8 million, compared with $513.2 million for the year ended December 31, 2024. See below for additional information on the $113.6 million increase in earnings.

Non-GAAP Financial Measures

The discussion below addresses the contribution of our utility segment to net income attributed to common shareholder. The discussion includes 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 segment as this measure excludes 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. Our utility segment discussion below includes 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.

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Utility Segment Contribution to Net Income Attributed to Common Shareholder

						Year Ended December 31
(in millions)						2025						2024						B (W)
Operating revenues						$	4,493.6					$	3,979.9					$	513.7
Operating expenses
Cost of sales (1)						1,498.8						1,300.3						(198.5)
Other operation and maintenance						1,073.9						937.9						(136.0)
Depreciation and amortization						629.9						573.7						(56.2)
Property and revenue taxes						120.2						106.8						(13.4)
Operating income						1,170.8						1,061.2						109.6
Other income, net						62.9						79.0						(16.1)
Interest expense						490.7						489.4						(1.3)
Income before income taxes						743.0						650.8						92.2
Income tax expense						115.0						136.4						21.4
Preferred stock dividend requirements						1.2						1.2						—
Net income attributed to common shareholder						$	626.8					$	513.2					$	113.6

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

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 items below						$	398.8					$	347.5					$	(51.3)
Transmission (1)						377.9						357.7						(20.2)
Regulatory amortizations and other pass through expenses (2)						134.7						101.1						(33.6)
We Power (3)						128.7						131.4						2.7
Earnings sharing mechanism (4)						23.8						(1.8)						(25.6)
Other						10.0						2.0						(8.0)
Total other operation and maintenance						$	1,073.9					$	937.9					$	(136.0)

(1)    Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses. As a result, we 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, $403.2 million and $366.8 million, respectively, of costs were billed to us 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 we recognized. During 2025 and 2024, $125.1 million and $115.8 million, respectively, of costs were billed to or incurred by us 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 sharing mechanism we have in place. See Note 24, Regulatory Environment, for more information.

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

						Year Ended December 31
Electric Sales Volumes (MWh - in thousands)						2025						2024						B (W)
Customer class
Residential						8,107.8						7,861.1						246.7
Small commercial and industrial						8,794.4						8,630.2						164.2
Large commercial and industrial						6,575.1						6,497.5						77.6
Other						94.7						101.3						(6.6)
Total retail						23,572.0						23,090.1						481.9
Wholesale						667.6						574.4						93.2
Resale						4,778.5						5,108.4						(329.9)
Total sales in MWh						29,018.1						28,772.9						245.2

						Year Ended December 31
Natural Gas Sales Volumes (Therms - in millions)						2025						2024						B (W)
Customer class
Residential						382.0						326.4						55.6
Commercial and industrial						226.1						189.3						36.8
Total retail						608.1						515.7						92.4
Transportation						263.4						247.7						15.7
Total sales in therms						871.5						763.4						108.1

						Year Ended December 31
Weather (Degree Days) (1)						2025						2024						B (W)
Heating (6,351 Normal)						6,641						5,190						28.0		%
Cooling (723 Normal)						789						831						(5.1)		%

(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 our service territory.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our utility 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)
Electric revenues						$	3,935.4					$	3,536.2					$	399.2
Natural gas revenues						558.2						443.7						114.5
Operating revenues						4,493.6						3,979.9						513.7
Operating expenses
Fuel and purchased power						(1,217.7)						(1,088.6)						(129.1)
Cost of natural gas sold						(281.1)						(211.7)						(69.4)
Other operation and maintenance (1)						(779.8)						(719.8)						(60.0)
Depreciation and amortization						(629.9)						(573.7)						(56.2)
Property and revenue taxes						(120.2)						(106.8)						(13.4)
Gross margin (GAAP)						1,464.9						1,279.3						185.6
Other operation and maintenance (1)						779.8						719.8						60.0
Depreciation and amortization						629.9						573.7						56.2
Property and revenue taxes						120.2						106.8						13.4
Utility margin (non-GAAP)						$	2,994.8					$	2,679.6					$	315.2

(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 utility segment increased $185.6 million during 2025, compared with 2024, and utility margin (non-GAAP) increased $315.2 million during 2025, compared with 2024. Both measures were driven by:

•A $260.4 million increase in margins driven by the impact of our rate order approved by the PSCW, effective January 1, 2025. See Note 24, Regulatory Environment, for more information.

•A $64.1 million increase in margins related to higher retail sales volumes, driven by the impact of colder weather during 2025, compared with 2024. As measured by heating degree days, 2025 was 28.0% colder than 2024.

These increases in margins were partially offset by:

•A $6.0 million decrease in revenues primarily related to third-party use of our assets.

•A $5.1 million decrease in margins driven by higher ash removal costs at certain of our plants.

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 $56.2 million increase in depreciation and amortization expense;

•A $22.8 million increase in other operating and maintenance related to our power plants;

•A $20.2 million increase in transmission expense.

•A $19.2 million increase in electric and natural gas distribution expenses; and

•A $13.4 million increase in property and revenue taxes.

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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 utility segment increased $205.6 million during 2025, compared with 2024. The significant factors impacting the increase in other operating expenses were:

•A $56.2 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on WEC Energy Group's capital plan.

•A $33.6 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $25.6 million increase in expense related to the earnings sharing mechanism in place, as discussed in the notes under the other operation and maintenance table above. See Note 24, Regulatory Environment, for more information.

•A $22.8 million increase in other operating and maintenance related to our power plants, driven by the resolution of certain items as a result of our December 2024 rate order approved by the PSCW, as well as new renewable generation facilities placed in service during 2025.

•A $20.2 million increase in transmission expense as approved by the PSCW in our rate order, effective January 1, 2025. See the notes under the other operation and maintenance table above for more information.

•A $19.2 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems, partially offset by lower costs for storm restoration.

•A $13.4 million increase in property and revenue taxes during 2025, compared with 2024, driven by a 2024 adjustment related to a sales tax audit.

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

Other Income, Net

Other income, net decreased $16.1 million during 2025, compared with 2024. The significant factors impacting the decrease in other income, net were:

•A $44.2 million negative impact from the non-service components of our net periodic pension and OPEB costs. In accordance with our December 2024 PSCW rate order, in 2025 we began amortizing our pension and OPEB costs that were previously deferred under escrow accounting. During 2025, we amortized $21.0 million of the previously deferred non-service costs as we are now collecting these costs in rates. See Note 19, Employee Benefits, for more information on our benefit costs.

•A $6.9 million decrease in interest income, driven by lower interest income earned on amounts due from ATC for the construction of transmission infrastructure upgrades needed for new generation projects and lower interest income earned on cash balances. See Note 4, Related Parties, for more information on amounts due from ATC.

These decreases in other income, net were partially offset by a $32.9 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense increased $1.3 million during 2025, compared with 2024, driven by the impact of our long-term debt issuances in May and September 2024, as well as September and December 2025. Partially offsetting this increase was the impact of our long-term debt maturities in December 2024 and June 2025. See Note 14, Long-Term Debt, for more information. This increase was also partially offset by higher AFUDC-Debt due to continued capital investment. Lower interest expense on finance lease liabilities, primarily related to the We Power leases, also contributed to the offset in interest expense, as finance lease liabilities decrease each year as payments are made.

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Income Tax Expense

Income tax expense decreased $21.4 million during 2025, compared with 2024. This decrease was driven by:

•A $20.3 million increase in the benefit from the flow through of tax repairs in connection with our rate order approved by the PSCW, effective January 1, 2025; and

•A $20.0 million increase in PTCs.

Partially offsetting these decreases in income tax expense was higher pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We expect to maintain adequate liquidity to meet our cash requirements for operation of our business 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:

(in millions)						2025						2024						Change in 2025 Over 2024
Cash provided by (used in):
Operating activities						$	1,127.8					$	1,264.5					$	(136.7)
Investing activities						(2,704.5)						(1,537.7)						(1,166.8)
Financing activities						1,576.8						268.2						1,308.6

Operating Activities

Net cash provided by operating activities decreased $136.7 million during 2025, compared with 2024, driven by a $163.5 million decrease in cash related to higher payments for other operation and maintenance expenses. During 2025, our payments were higher due to increased transmission costs, operating and maintenance costs related to our plants, and electric and natural gas distribution costs, as well as the timing of payments for accounts payable.

This decrease in net cash provided by operating activities was partially offset by a $26.2 million increase in cash from higher overall collections from customers during 2025, compared with 2024. This increase was driven by the impact of our rate order approved by the PSCW, effective January 1, 2025 and higher sales volumes from the impact of colder weather during 2025, compared with 2024.

Investing Activities

Net cash used in investing activities increased $1,166.8 million during 2025, compared with 2024, driven by:

•A $1,300.2 million increase in cash paid for capital expenditures during 2025, which is discussed in more detail below.

•A $14.8 million increase in cash paid for transmission infrastructure upgrades during 2025, compared with 2024, which are reimbursable by ATC. See Note 4, Related Parties, for more information.

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

•The acquisition of an additional 13.7% ownership interest in West Riverside in May 2024 for $97.9 million. See Note 2, Acquisitions, for more information.

•A $25.5 million increase in cash received from ATC during 2025, compared with 2024, for the reimbursement of transmission infrastructure upgrades. See Note 4, Related Parties, for more information.

Capital Expenditures

Capital expenditures for the years ended December 31 were as follows:

(in millions)						2025						2024						Change in 2025 Over 2024
Capital expenditures						$	2,742.9					$	1,442.7					$	1,300.2

The increase in cash paid for capital expenditures during 2025, compared with 2024, was driven by higher payments for renewable energy projects, CTs and an LNG facility at OCPP, and for our electric distribution systems.

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

Financing Activities

Net cash provided by financing activities increased $1,308.6 million during 2025, compared with 2024, driven by:

•A $1,095.0 million increase in equity contributions received from our parent during 2025, compared with 2024, to balance our capital structure.

•A $681.6 million increase in cash due to $500.7 million of net borrowings of commercial paper during 2025, compared with $180.9 million of net repayments of commercial paper during 2024.

•A $49.8 million increase in cash due to lower retirements of long-term debt during 2025, compared with 2024.

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

•A $360.0 million decrease in cash due to higher dividends paid to our parent during 2025, compared with 2024, to balance our capital structure.

•A $147.9 million decrease in cash due to lower issuances of long-term debt during 2025, compared with 2024.

•A $12.4 million decrease in cash due to higher payments for finance lease obligations during 2025, compared with 2024.

Significant Financing Activities

For more information on our financing activities, see Note 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt.

Cash Requirements

We require funds to support and grow our business. 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 parent, and the funding of our ongoing operations. Our significant cash requirements are discussed in further detail below.

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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 22, Commitments and Contingencies.

(in millions)
2026						$	3,212.1
2027						4,670.5
2028						4,666.0
Total						$	12,548.6

WEC Energy Group is committed to investing in solar, wind, battery storage, and natural gas-fired generation. In addition, we continue to upgrade our 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						$	596.6					$	1,458.3					$	1,542.9
Wind						143.0						277.1						581.7
Battery						215.5						370.8						251.4
Thermal						878.8						1,345.6						1,206.6
Other						270.0						141.6						189.8
LNG						177.3						81.5						61.8
Distribution:
Electric distribution						702.5						655.6						643.2
Gas distribution						228.4						340.0						188.6
Total						$	3,212.1					$	4,670.5					$	4,666.0

The DOC set duties on solar panels and cells imported from four southeast Asian countries and is investigating additional AD/CVD allegations relating to Chinese-owned manufacturers in Laos and Indonesia, as well as India-headquartered companies. 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 expected in-service dates and costs identified above already reflect some of these impacts.

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.

Long-Term Debt

A significant amount of cash is required to retire and pay interest on our long-term debt obligations. See Note 14, Long-Term Debt, for more information on our outstanding long-term debt, including a schedule of our long-term debt maturities over the next five years. The following table summarizes our required interest payments on long-term debt as of December 31, 2025:

						Interest Payments Due by Period
(in millions)						Total						Less Than 1 Year						1-3 Years						3-5 Years						More Than 5 Years
Interest payments due on long-term debt						$	2,620.0					$	205.1					$	401.2					$	325.6					$	1,688.1

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Common Stock Dividends

During the years ended December 31, 2025, 2024, and 2023, we paid common stock dividends of $600.0 million, $240.0 million, and $370.0 million, respectively, to the sole holder of our common stock, WEC Energy Group. Any payment of future dividends is subject to approval by our Board of Directors and is dependent upon future earnings, capital requirements, and financial and other business conditions. In addition, various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. See Note 11, Common Equity, for more information related to these restrictions and our other common stock matters.

Other Significant Cash Requirements

Our utility operations have purchase obligations under various contracts for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. These costs are a significant component of funding our ongoing operations. See Note 22, Commitments and Contingencies, for more information, including our minimum future commitments related to these purchase obligations.

In addition to our energy-related purchase obligations, we have commitments for other costs incurred in the normal course of business, including costs related to information technology services, meter reading services, maintenance and other service agreements for certain generating facilities, and various engineering agreements. Our estimated future cash requirements related to these purchase obligations, excluding energy-related obligations, are reflected below.

						Payments Due by Period
(in millions)						Total						Less Than 1 Year						1-3 Years						3-5 Years						More Than 5 Years
Purchase orders						$	156.7					$	78.9					$	53.8					$	14.9					$	9.1

We have various finance and operating lease obligations. Our finance lease obligations primarily relate to land leases for renewable generation projects. Our operating lease obligations are for office space and land. See Note 15, Leases, for more information, including an analysis of our minimum lease payments due in future years.

We make contributions to our pension and OPEB plans based upon various factors affecting us, including our liquidity position and tax law changes. See Note 19, Employee Benefits, for our expected contributions in 2026 and our expected pension and OPEB payments for the next 10 years. We expect the majority of these future pension and OPEB payments to be paid from our outside trusts. See Sources of Cash–Investments in Outside Trusts below for more information.

In addition to the above, our balance sheet at December 31, 2025 included various other liabilities that, due to the nature of the liabilities, the amount and timing of future payments cannot be determined with certainty. These liabilities include AROs, liabilities for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes. For additional information on these liabilities, see Note 10, Asset Retirement Obligations, Note 16, Income Taxes, and Note 22, Commitments and Contingencies, respectively.

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 letters of credit that primarily support our commodity contracts. 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. See Note 1(q), Guarantees, Note 13, Short-Term Debt and Lines of Credit, and Note 21, Variable Interest Entities, for more information.

Sources of Cash

Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our business and implement our corporate strategy through internal generation of cash from operations, equity contributions from our parent, and access to the capital

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

We maintain a bank back-up credit facility, which provides liquidity support for our 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 in 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, and other factors. We plan to maintain a capital structure consistent with that approved by the PSCW. For more information on our approved capital structure, see Item 1. Business – C. Regulation.

The issuance of our securities is subject to the approval of the PSCW. Additionally, with respect to the public offering of securities, we file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the PSCW, 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 December 31, 2025, our current liabilities exceeded our current assets by $425.5 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 facility, 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 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information about our commercial paper, credit facility, 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. As of December 31, 2025, these trusts had investments of approximately $1.1 billion, consisting of fixed income and equity securities, that are subject to the volatility of the stock market and interest rates. The performance of existing plan assets, long-term discount rates, changes in assumptions, and other factors could affect our future contributions to the plans, our financial position if our accumulated benefit obligation exceeds the fair value of the plan assets, and future results of operations related to changes in pension and OPEB expense and the assumed rate of return. For additional information, see Note 19, Employee Benefits.

Debt Covenants

Our credit facility contains financial covenants that we must satisfy, including a debt to capitalization ratio. At December 31, 2025, we were in compliance with all such covenants. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information.

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 December 31, 2025. 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 December 31, 2025, we could have been required to post $106 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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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

Competitive Markets

Electric Utility Industry

The FERC supports large RTOs, which directly impacts the structure of the wholesale electric market. Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMPs to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.

Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date, and it is uncertain when, if at all, retail choice might be implemented in Wisconsin.

Natural Gas Utility Industry

We offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.

Due to the PSCW's previous proceedings on natural gas industry regulation in a competitive environment, the PSCW currently provides all Wisconsin customer classes with competitive markets the option to choose a third-party natural gas supplier. All of our Wisconsin non-residential customer classes have competitive market choices and, therefore, can purchase natural gas directly from either a third-party supplier or us. Since third-party suppliers can be used in Wisconsin, the PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates.

We offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is substantially offset by an equal reduction to natural gas costs.

We are currently unable to predict the impact, if any, of potential future industry restructuring on our results of operations or financial position.

Regulatory, Legislative, and Legal Matters

Regulatory Recovery

We account for our regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by the PSCW and the FERC. See Item 1. Business – C. Regulation for more information on these commissions. See Note 24, Regulatory Environment, for additional information regarding recent rate proceedings and orders.

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 our regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs 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

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previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 7, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

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 our solar projects included in WEC Energy Group's 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 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 required 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 U.S. has been impacted and the U.S. 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 US. Affirmative findings in these investigations could cause further strain on the solar panel industry. We are monitoring the status of these petitions.

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, 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.

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Under the IRA transferability option, WEC Energy Group entered into agreements in October 2024, April 2025, and September 2025 to sell the majority of the PTCs and ITCs we generated, or expect to generate, in 2025 and 2026, respectively, to third parties. In May 2025, WEC Energy Group entered into an agreement to sell the majority of our remaining unsold PTCs we generated in 2024 to a third party. See Note 1(n), Income Taxes, for more information about the impact of these sales. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us.

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. 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 U.S. Treasury Department implemented new beginning-of-construction safe harbor rules that became effective in September 2025. WEC Energy Group's capital plan for 2026 through 2030 reflects the impacts of OBBBA, including the revised beginning-of-construction rules.

Environmental Matters

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

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 include, but are not limited to, the risks described below. In addition, there is continuing uncertainty over the impact of increasing tensions between the U.S. and other countries and new, protracted or escalating regional and international conflicts on the global economy, supply chains, and fuel prices.

Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

Embedded within our rates are amounts to recover fuel, natural gas, and purchased power costs. We have recovery mechanisms in place that generally allow us to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – C. Regulation for more information on these mechanisms.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 6, Credit Losses, for more information on our mechanism that allows for cost recovery or refund of uncollectible expense.

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Weather

Our utility rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. The fixed charge included in our natural gas rates helps to mitigate the impacts of weather. A summary of actual weather information in our service territory, as measured by degree days, can be found in Results of Operations.

Our operations, primarily our electric operations, can be negatively impacted from storms. High wind conditions, lightning, hail, and flooding from storms can result in downed wires and poles, as well as damage to wind and solar generation facilities and other operating equipment. This can result in us incurring significant restoration costs and lost revenue to our customers. Our rates include a fixed amount for expected storm restoration costs. To the extent actual storm restoration costs are above what is included in these rates, our earnings are negatively impacted and it becomes more difficult to achieve our authorized ROE.

Interest Rates

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.

Based on our variable rate debt outstanding at December 31, 2025 and 2024, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $6.8 million and $1.8 million in 2025 and 2024, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

Marketable Securities Return

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. The financial risks associated with investment returns are mitigated through the requirement that we implement escrow accounting treatment for pension and OPEB costs in 2023 through 2026, as required by the December 2022 and December 2024 rate orders issued by the PSCW. As a result, we defer as a regulatory asset or liability, the difference between actual pension and OPEB costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

The fair value of our trust fund assets and expected long-term returns were approximately:

(in millions)						As of December 31, 2025						Expected Return on Assets in 2026
Pension trust funds						$	905.2					6.50		%
OPEB trust funds						$	175.4					6.50		%

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

WEC Energy Group consults with its investment advisors on an annual basis to help it forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

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Economic Conditions

Our service territories are within the state of Wisconsin. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

Changes to United States Trade Policy (Tariff Activity)

The U.S. 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 U.S. and foreign trade policies. Both the U.S. 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 on our projects included in WEC Energy Group's 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.

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 WEC Energy Group's capital plan, which includes us. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below.

•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 WEC Energy Group's 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 and Item 1A. Risk Factors.

Critical Accounting Policies and Estimates

The preparation of financial statements in compliance with GAAP requires the application of accounting policies, as well as the use of estimates, assumptions, and judgments that could have a material impact on our financial statements and related disclosures. Judgments regarding future events may include the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. Actual results may differ significantly from estimated amounts based on varying assumptions.

Our significant accounting policies are described in Note 1, Summary of Significant Accounting Policies. The following is a list of accounting policies and estimates that require management's most difficult, subjective, or complex judgments and may change in subsequent periods.

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Regulatory Accounting

Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC (Topic 980). Our financial statements reflect the effects of the ratemaking principles followed by the jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.

Future recovery of regulatory assets, including the timeliness of recovery and our ability to earn a reasonable return, is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery or refund period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. See Note 7, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

Long-Lived Assets

In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, a regulatory decision related to recovery of assets from customers, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold or abandoned. See Note 1(j), Asset Impairment, for our policy on accounting for abandonments and recently completed plant subject to disallowance.

Performing an impairment evaluation involves a significant degree of estimation and judgment by management in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted future cash flows. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. The fair value of the asset is assessed using various methods, including internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

See Note 8, Property, Plant, and Equipment, for more information on our generating units probable of being retired. See Note 7, Regulatory Assets and Liabilities, for more information on our retired generating units.

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 19, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. Changes in benefit costs are mitigated through the requirement that we implement escrow accounting treatment for pension and OPEB costs, as required by rate orders issued by the PSCW. See Note 24, Regulatory Environment, for more information on our rates.

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The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost (including amounts capitalized to our balance sheets). Each factor below reflects an evaluation of the change based on a change in that assumption only.

Actuarial Assumption (in millions, except percentages)						Percentage-Point Change in Assumption						Impact on Projected Benefit Obligation						Impact on 2025 Pension Cost
Discount rate						(0.5)						$	30.6					$	2.0
Discount rate						0.5						(28.1)						(1.9)
Rate of return on plan assets						(0.5)						N/A						4.6
Rate of return on plan assets						0.5						N/A						(4.6)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost (including amounts capitalized to our balance sheets). Each factor below reflects an evaluation of the change based on a change in that assumption only.

Actuarial Assumption (in millions, except percentages)						Percentage-Point Change in Assumption						Impact on Postretirement Benefit Obligation						Impact on 2025 Postretirement Benefit Cost
Discount rate						(0.5)						$	9.9					$	1.6
Discount rate						0.5						(8.9)						(1.4)
Health care cost trend rate						(0.5)						(5.2)						(1.4)
Health care cost trend rate						0.5						6.0						1.6
Rate of return on plan assets						(0.5)						N/A						0.8
Rate of return on plan assets						0.5						N/A						(0.8)

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable, high-quality corporate bonds across the full maturity spectrum. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 6.50% in 2025, 2024, and 2023, respectively. The actual rate of return on pension plan assets, net of fees, was 8.93%, 5.20%, and 8.09%, in 2025, 2024, and 2023, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 19, Employee Benefits.

Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated.

Unbilled revenues are estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Energy demand for the unbilled period or changes in rate mix due to fluctuations in usage patterns of customer classes could impact the accuracy of the unbilled revenue estimate. Total unbilled utility revenues were $219.0 million and $192.1 million as of December 31, 2025 and 2024, respectively. The changes in unbilled revenues are primarily due to changes in the cost of natural gas, weather, and customer rates.

Income Tax Expense

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our

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financial condition and results of operations. See Note 1(n), Income Taxes, and Note 16, Income Taxes, for a discussion of accounting for income taxes.

We are required to estimate income taxes for each of our applicable tax jurisdictions as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.

Uncertainty associated with the application of tax statutes and regulations, the outcomes of tax audits and appeals, changes in income tax law, enacted tax rates or amounts subject to income tax, and changes in the regulatory treatment of any tax reform benefits requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

We expect our 2026 annual effective tax rate to be between 11% and 12%. 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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, as well as Note 1(o), Fair Value Measurements, Note 1(p), Derivative Instruments, and Note 1(q), Guarantees, for information concerning potential market risks to which we are exposed.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Wisconsin Electric Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Wisconsin Electric Power Company and subsidiary (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of rate regulation on financial statements — Refer to Notes 7 and 24 to the financial statements

Critical Audit Matter Description

The Company is subject to regulation by state and federal regulatory bodies (collectively the “Commissions”) which have jurisdiction with respect to the rates of electric and gas utilities. Management has determined the Company meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the Regulated Operations Topic of the Financial Accounting Standards Board’s Accounting Standard Codification.

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Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered through rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by the Company’s regulators. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment or (3) timely recovery of costs incurred.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the impacted account balances and disclosures and the subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and/or (2) a refund to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following procedures, among others:

•We tested the effectiveness of management’s controls over regulatory assets and liabilities, including management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred reported as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We inquired of Company management and independently obtained and read: (1) relevant regulatory orders issued by the Commissions for the Company, (2) Company filings with the Commissions, (3) filings made by intervenors and (4) other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. To assess completeness, we evaluated the information obtained and compared it to management’s recorded regulatory asset and liability balances.

•For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•We evaluated management’s conclusions regarding the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 20, 2026

We have served as the Company's auditor since 2002.

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B. CONSOLIDATED INCOME STATEMENTS

Year Ended December 31
(in millions)						2025						2024						2023
Operating revenues						$	4,493.6					$	3,979.9					$	4,045.0
Operating expenses
Cost of sales						1,498.8						1,300.3						1,451.4
Other operation and maintenance						1,073.9						937.9						931.1
Depreciation and amortization						629.9						573.7						525.0
Property and revenue taxes						120.2						106.8						115.3
Total operating expenses						3,322.8						2,918.7						3,022.8
Operating income						1,170.8						1,061.2						1,022.2
Other income, net						62.9						79.0						68.8
Interest expense						490.7						489.4						466.5
Other expense						(427.8)						(410.4)						(397.7)
Income before income taxes						743.0						650.8						624.5
Income tax expense						115.0						136.4						142.7
Net income						628.0						514.4						481.8
Preferred stock dividend requirements						1.2						1.2						1.2
Net income attributed to common shareholder						$	626.8					$	513.2					$	480.6

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

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C. CONSOLIDATED BALANCE SHEETS

At December 31
(in millions, except share and per share amounts)						2025						2024
Assets
Current assets
Cash and cash equivalents						$	—					$	0.4
Accounts receivable and unbilled revenues, net of reserves of $39.7 and $46.9, respectively						742.2						601.2
Accounts receivable from related parties						120.5						128.6
Materials, supplies, and inventories						322.7						354.8
Prepaid taxes						115.8						139.8
Other prepayments						30.1						24.9
Other						24.3						23.2
Current assets						1,355.6						1,272.9
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $6,373.9 and $5,952.3, respectively						15,208.6						12,810.7
Regulatory assets (December 31, 2025 and December 31, 2024 include $67.5 and $76.5, respectively, related to WEPCo Environmental Trust)						2,941.0						2,946.3
Pension and OPEB assets						105.8						79.2
Other						85.4						90.5
Long-term assets						18,340.8						15,926.7
Total assets						$	19,696.4					$	17,199.6
Liabilities and Equity
Current liabilities
Short-term debt						$	680.6					$	179.9
Current portion of long-term debt (December 31, 2025 and December 31, 2024 include $9.3 and $9.2, respectively, related to WEPCo Environmental Trust)						9.3						259.2
Current portion of finance lease obligations						113.4						99.3
Accounts payable						530.8						529.3
Accounts payable to related parties						214.7						206.1
Other						232.3						184.6
Current liabilities						1,781.1						1,458.4
Long-term liabilities
Long-term debt (December 31, 2025 and December 31, 2024 include $67.4 and $76.4, respectively, related to WEPCo Environmental Trust)						4,516.0						3,728.0
Finance lease obligations						2,715.4						2,742.9
Deferred income taxes						1,666.6						1,655.7
Regulatory liabilities						1,759.0						1,758.8
Other						478.7						348.6
Long-term liabilities						11,135.7						10,234.0
Commitments and contingencies (Note 22)
Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding						332.9						332.9
Additional paid in capital						3,948.6						2,703.0
Retained earnings						2,467.7						2,440.9
Common shareholder's equity						6,749.2						5,476.8
Preferred stock						30.4						30.4
Total liabilities and equity						$	19,696.4					$	17,199.6

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

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D. CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31
(in millions)						2025						2024						2023
Operating activities
Net income						$	628.0					$	514.4					$	481.8
Reconciliation to cash provided by operating activities
Depreciation and amortization						629.9						573.7						525.0
Deferred income taxes and ITCs, net						20.2						109.7						20.7
Net change in transmission regulatory asset and liability						(25.3)						(9.0)						18.4
Change in –
Accounts receivable and unbilled revenues, net						(149.4)						(18.9)						(4.6)
Materials, supplies, and inventories						32.1						(44.2)						(12.8)
Prepaid taxes						24.0						(27.1)						0.4
Collateral on deposit						(7.3)						21.8						20.0
Other current assets						(5.2)						(2.7)						(5.2)
Accounts payable						(3.1)						92.3						(41.3)
Other current liabilities						40.4						13.8						(8.2)
Other, net						(56.5)						40.7						(55.1)
Net cash provided by operating activities						1,127.8						1,264.5						939.1
Investing activities
Capital expenditures						(2,742.9)						(1,442.7)						(1,094.6)
Acquisition of West Riverside						—						(97.9)						(95.3)
Acquisition of Whitewater						—						—						(38.0)
Proceeds from the sale of assets						0.2						1.3						24.3
Reimbursement for ATC's transmission infrastructure upgrades						33.1						7.6						—
Payments for ATC's transmission infrastructure upgrades that will be reimbursed						(16.4)						(1.6)						(16.5)
Other, net						21.5						(4.4)						(7.2)
Net cash used in investing activities						(2,704.5)						(1,537.7)						(1,227.3)
Financing activities
Change in short-term debt						500.7						(180.9)						(99.9)
Issuance of long-term debt						799.5						947.4						—
Retirement of long-term debt						(259.2)						(309.0)						(8.9)
Payments for finance lease obligations						(100.3)						(87.9)						(77.0)
Equity contribution from parent						1,245.0						150.0						805.0
Payment of dividends to parent						(600.0)						(240.0)						(370.0)
Other, net						(8.9)						(11.4)						(1.2)
Net cash provided by financing activities						1,576.8						268.2						248.0
Net change in cash, cash equivalents, and restricted cash						0.1						(5.0)						(40.2)
Cash, cash equivalents, and restricted cash at beginning of year						2.5						7.5						47.7
Cash, cash equivalents, and restricted cash at end of year						$	2.6					$	2.5					$	7.5

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

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E. CONSOLIDATED STATEMENTS OF EQUITY

						Wisconsin Electric Power Company Common Shareholder's Equity
						Common Stock						Additional Paid In Capital						Retained Earnings						Total Common Shareholder's Equity						Preferred Stock						Total Equity
(in millions)
Balance at December 31, 2022						$	332.9					$	1,746.8					$	2,057.1					$	4,136.8					$	30.4					$	4,167.2
Net income attributed to common shareholder						—						—						480.6						480.6						—						480.6
Payment of dividends to parent						—						—						(370.0)						(370.0)						—						(370.0)
Equity contribution from parent						—						805.0						—						805.0						—						805.0
Stock-based compensation and other						—						0.6						0.1						0.7						—						0.7
Balance at December 31, 2023						$	332.9					$	2,552.4					$	2,167.8					$	5,053.1					$	30.4					$	5,083.5
Net income attributed to common shareholder						—						—						513.2						513.2						—						513.2
Payment of dividends to parent						—						—						(240.0)						(240.0)						—						(240.0)
Equity contribution from parent						—						150.0						—						150.0						—						150.0
Stock-based compensation and other						—						0.6						(0.1)						0.5						—						0.5
Balance at December 31, 2024						$	332.9					$	2,703.0					$	2,440.9					$	5,476.8					$	30.4					$	5,507.2
Net income attributed to common shareholder						—						—						626.8						626.8						—						626.8
Payment of dividends to parent						—						—						(600.0)						(600.0)						—						(600.0)
Equity contribution from parent						—						1,245.0						—						1,245.0						—						1,245.0
Stock-based compensation and other						—						0.6						—						0.6						—						0.6
Balance at December 31, 2025						$	332.9					$	3,948.6					$	2,467.7					$	6,749.2					$	30.4					$	6,779.6

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

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F. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of Operations—We are an electric, natural gas, and steam utility company that serves electric and natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. WEC Energy Group owns all of our outstanding common stock.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate VIEs of which we are the primary beneficiary.

These financial statements reflect our proportionate interests in certain jointly owned utility facilities. See Note 9, Jointly-Owned Utility Facilities, for more information.

(b) Basis of Presentation—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

(d) Operating Revenues—The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 5, Operating Revenues.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity.

The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance

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obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Natural Gas Utility Operating Revenues

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In Wisconsin, our customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include a one-for-one recovery mechanism for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

In addition, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

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Other Operating Revenues

Bespoke Resources Current Return

We recognize revenues monthly associated with carrying costs, including financing costs, during the construction period of bespoke resources assigned to our very large utility customers under payment and cancellation agreements. These amounts are not considered revenues from contracts with customers as electricity is not yet being provided. Consistent with the timing of when we recognize revenue, customer billings for the bespoke resources that are subject to current return (as opposed to AFUDC) occur on a monthly basis, with payments typically due in full within 45 days.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

(e) Credit Losses—The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 6, Credit Losses.

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at December 31, 2025 and 2024.

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 the PSCW, 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.

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(f) Materials, Supplies, and Inventories—Our inventories as of December 31 consisted of:

(in millions)						2025						2024
Materials and supplies						$	225.2					$	252.1
Fossil fuel						53.3						60.0
Natural gas in storage						44.2						42.7
Total						$	322.7					$	354.8

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

(g) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 7, Regulatory Assets and Liabilities, for more information.

(h) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW that include estimates for salvage value and removal costs. Annual utility composite depreciation rates were 3.07%, 3.03%, and 3.03% in 2025, 2024, and 2023, respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.

See Note 8, Property, Plant, and Equipment, for more information.

(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC-Debt) used during plant construction, and a return on shareholders' capital (AFUDC-Equity) used for construction purposes. AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.65%, 8.45%, and 8.45% for 2025, 2024, and 2023, respectively. Our average AFUDC wholesale rates were 7.51%, 7.11%, and 6.70% for 2025, 2024, and 2023, respectively.

We recorded the following AFUDC for the years ended December 31:

(in millions)						2025						2024						2023
AFUDC-Debt						$	29.8					$	14.6					$	13.0
AFUDC-Equity						78.9						46.0						41.0

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See Note 16, Income Taxes, for more information on how AFUDC-Equity is treated for tax purposes and the related impact on total WEC Energy Group income tax expense.

(j) Asset Impairment—Intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. At December 31, 2025 and 2024, we had $12.4 million and $12.1 million, respectively, of indefinite-lived intangible assets included in other long-term assets on our balance sheets, which largely consist of spectrum frequencies. The spectrum frequencies enable us to transmit data and voice communications over a wavelength dedicated to us throughout our service territory. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. An impairment loss is measured as the excess of the carrying amount of the intangible asset over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2025, 2024, and 2023.

We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 7, Regulatory Assets and Liabilities, and Note 8, Property, Plant, and Equipment, for more information.

(k) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 10, Asset Retirement Obligations, for more information.

(l) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. In addition to those shares of WEC Energy Group common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders, 9.0 million shares of WEC Energy Group common stock were reserved for issuance under the plan.

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Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur.

Stock Options

Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in connection with certain termination of employment events following a change in control. Options expire no later than 10 years from the date of grant.

WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models:

						2025						2024						2023
Stock options granted						41,084						44,202						30,495
Estimated weighted-average fair value per stock option						$	18.23					$	16.13					$	19.58
Assumptions used to value the options:
Risk-free interest rate						4.2% – 4.6%						3.9% – 5.4%						3.8% – 4.8%
Dividend yield						4.1		%				3.8		%				3.2		%
Expected volatility						22.0		%				22.0		%				22.0		%
Expected life (years)						8.3						8.4						8.3

The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience.

Restricted Shares

WEC Energy Group restricted shares granted to our employees have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.

Pursuant to the terms of the WEC Energy Group Performance Unit Plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout of the performance unit awards. The ultimate number of units that will be paid out will be based on WEC Energy Group's total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and WEC Energy Group's performance against the weighted average authorized ROE of all of its utility subsidiaries (45%). In addition, the Compensation Committee selected the level of WEC Energy Group's stock price to earnings ratio compared to its peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award.

See Note 11, Common Equity, for more information on WEC Energy Group's stock-based compensation plans.

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(m) Leases—We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year. As a policy election, we account for each lease component separately from the nonlease components of a contract.

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our renewable generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

See Note 15, Leases, for more information.

(n) Income Taxes—In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. We adopted ASU No. 2023-09 on January 1, 2025, on a retroactive basis, with the required disclosures first included in our 2025 Annual Report on Form 10-K.

We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

ITCs associated with regulated operations are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We are included in WEC Energy Group's consolidated federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon the benefit for loss method, where attributes are realized when WEC Energy Group is able to realize them.

We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements.

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, WEC Energy Group entered into agreements to sell the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties. See Note 16, Income Taxes, for more information on the PTCs that were sold. WEC Energy Group has 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.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We adopted the safe harbor method of accounting on our 2023 tax return, which increased our deferred tax liabilities.

See Note 16, Income Taxes, for more information.

(o) 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 derivative 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, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our FTRs are valued using MISO auction prices.

See Note 17, Fair Value Measurements, for more information.

(p) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

We record derivative instruments on our balance sheets as assets or liabilities 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, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information.

(q) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. As of December 31, 2025, we had $27.5 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, of which $27.4 million automatically renews each year unless proper termination notice is given and $0.1 million expires in less than one year. These amounts are not reflected on our balance sheets.

(r) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial

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calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 19, Employee Benefits, for more information.

(s) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

(t) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including CCR landfills and manufactured gas plant sites. See Note 10, Asset Retirement Obligations, for more information regarding CCR landfills and Note 22, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable, and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and CCR landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(u) Customer Concentrations of Credit Risk—The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations, and we could recognize financial losses as a result. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed in Note 1(d), Operating Revenues. There were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2025.

As a result, we did not have any significant concentrations of credit risk at December 31, 2025. However, we have contracts with a small number of customers to provide power to large-scale data centers to support AI and other technology capabilities. This concentration of business with a small number of customers in an industry based on emerging technologies presents several risks. We are incurring significant costs to construct bespoke resources to serve these customers. Although we require these customers to enter into payment and cancellation agreements, we may still experience significant losses or delayed recovery of these costs. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers, which would reduce our forecasted revenues. Significant capital spend to build out required infrastructure or a downturn in business could weaken their financial condition, liquidity and/or creditworthiness, including their ability to satisfy their reimbursement obligations to us.

NOTE 2—ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions.

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Acquisitions of Electric Generation Facilities in Wisconsin

In December 2025, we, along with WPS and an unaffiliated utility, signed an agreement to acquire Whitetail, a wind-powered electric generation project with a total capacity of 67.2 MW. This project will be located in Grant County, Wisconsin. We will own 80% and our portion of the purchase price is expected to be approximately $178 million. The project is expected to close in late 2027 and it is expected to qualify for PTCs.

In May 2024, we completed the acquisition of an additional 100 MWs of West Riverside's nameplate capacity for $97.9 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. In June 2023, we completed the first acquisition of 100 MWs for $95.3 million. After the second acquisition, we own 200 MWs, or 27.5%, of West Riverside at a total cost of $193.2 million.

In January 2023, we, along with WPS, completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electric generation facility in Whitewater, Wisconsin. Our share of the cost of this facility was $38.0 million for 50% of the capacity.

NOTE 3—DISPOSITION

Sale of Real Estate

In June 2023, we sold approximately 192 acres of real estate at our former Pleasant Prairie power plant site that was no longer being utilized in our operations, for $23.0 million, which is net of closing costs. As a result of the sale, a pre-tax gain in the amount of $22.2 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

NOTE 4—RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group pursuant to an AIA that became effective in 2017. The AIA was approved by the appropriate regulators, including the PSCW. In accordance with the AIA, WBS provides several categories of services to us (including financial, human resource, and administrative services). As required by FERC regulations for centralized service companies, WBS renders services at cost. Services provided by any regulated subsidiary of WEC Energy Group to another regulated subsidiary or WBS are provided at cost, and any services provided by a regulated subsidiary to a nonregulated subsidiary of WEC Energy Group are provided at the greater of cost or fair market value.

We pay ATC for 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. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. 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. We have also entered into agreements with ATC for transmission infrastructure projects associated with providing service to VLCs. These agreements obligate us to reimburse ATC for costs associated with the projects if we cancel or terminate the projects at the request of the VLC. In these circumstances, we have payment and cancellation agreements with VLCs which obligate the VLC to reimburse us for all costs, inclusive of ATC’s costs, if the costs associated with the cancelled or terminated projects cannot be repurposed.

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

(in millions)						December 31, 2025						December 31, 2024
Accounts receivable
Services provided to ATC						$	0.7					$	0.9
Amounts due from ATC for transmission infrastructure upgrades (1)						17.6						39.3
Accounts payable
Services received from ATC						25.5						22.6

(1)     The transmission infrastructure upgrades were primarily related to the construction of our renewable energy projects.

The following table shows activity associated with our related party transactions for the years ended December 31:

(in millions)						2025						2024						2023
Transactions with WPS
Natural gas related purchases from WPS (1)						$	2.5					$	1.0					$	1.3
Charges to WPS for services and other items (2)						46.4						18.6						16.2
Charges from WPS for services and other items (2)						34.4						12.8						11.3
Transactions with WG
Natural gas related purchases from WG (1)						43.2						33.9						19.7
Natural gas related sales to WG (1)						—						0.2						0.3
Electric related sales to WG						2.5						2.6						0.6
Charges to WG for services and other items (2)						50.1						40.9						38.3
Charges from WG for services and other items (2)						31.9						27.0						27.9
Transactions with UMERC
Charges to UMERC for services and other items (2)						14.8						11.9						11.8
Charges from UMERC for services and other items (2)						1.4						1.1						2.0
Transactions with Bluewater
Charges from Bluewater for storage service fees (3)						17.3						20.1						17.2
Charges from Bluewater for other operating fees (3)						1.6						3.9						4.1
Natural gas related sales to Bluewater (1)						2.7						2.8						2.8
Charges to Bluewater for services and other items (2)						3.1						2.8						2.7
Transactions with We Power
Lease payments and other lease-related charges from We Power (4)						433.0						427.2						422.0
Charges to We Power for services and other items (2)						15.3						8.0						7.8
Transactions with WBS
Charges to WBS for services and other items (2)						40.1						26.4						41.1
Charges from WBS for services and other items (2)						144.7						129.3						113.3
Transactions with ATC
Charges to ATC for services and construction						9.3						12.4						8.1
Charges from ATC for network transmission services						307.8						271.2						248.8
Net refund from ATC related to FERC ROE orders						3.5						—						—

(1)    Includes amounts related to the purchase or sale of natural gas and/or pipeline capacity.

(2)    Includes amounts charged for services, pass through costs, asset and liability transfers, and other items in accordance with the approved AIA.

(3)    We have a long-term service agreement with a wholly owned subsidiary of Bluewater that was previously approved by the PSCW. Bluewater owns natural gas storage facilities in Michigan and provides a portion of our current storage needs.

(4)    We make lease payments to We Power for PWGS Units 1 and 2 and ERGS Units 1 and 2. See Note 15, Leases, for more information.

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NOTE 5—OPERATING REVENUES

For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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.

						Year Ended December 31
(in millions)						2025						2024						2023
Wisconsin Electric Power Company
Electric utility						$	3,920.5					$	3,522.7					$	3,540.2
Natural gas utility						556.8						442.4						489.8
Total revenues from contracts with customers						4,477.3						3,965.1						4,030.0
Other operating revenues						16.3						14.8						15.0
Total operating revenues						$	4,493.6					$	3,979.9					$	4,045.0

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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

						Year Ended December 31
(in millions)						2025						2024						2023
Residential						$	1,679.3					$	1,503.3					$	1,480.6
Small commercial and industrial						1,272.5						1,175.5						1,177.2
Large commercial and industrial						656.7						598.4						616.0
Other						21.4						21.0						21.1
Total retail revenues						3,629.9						3,298.2						3,294.9
Wholesale						47.8						45.5						40.9
Resale						206.1						144.3						173.7
Steam						28.4						23.5						25.2
Other utility revenues						8.3						11.2						5.5
Total electric utility operating revenues						$	3,920.5					$	3,522.7					$	3,540.2

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

						Year Ended December 31
(in millions)						2025						2024						2023
Residential						$	372.6					$	292.5					$	323.3
Commercial and industrial						171.0						124.3						148.2
Total retail revenues						543.6						416.8						471.5
Transportation						24.4						24.1						21.6
Other utility revenues (1)						(11.2)						1.5						(3.3)
Total natural gas utility operating revenues						$	556.8					$	442.4					$	489.8

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

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Other Operating Revenues

Other operating revenues consist of the following:

						Year Ended December 31
(in millions)						2025						2024						2023
Late payment charges						$	10.9					$	11.3					$	12.2
Bespoke resources current return (1)						4.1						—						—
Rental revenues						2.2						2.6						2.5
Alternative revenues (2)						(0.9)						0.9						0.3
Total other operating revenues						$	16.3					$	14.8					$	15.0

(1)    Bespoke resources current return consists of carrying costs earned during the construction of bespoke resources assigned to our VLCs. See Note 1(d), Operating Revenues, for more information.

(2)    Alternative revenues consist of amounts to be recovered or refunded to customers subject to wholesale true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues.

NOTE 6—CREDIT LOSSES

The table below shows our gross third-party receivable balances and related allowance for credit losses.

(in millions)						December 31, 2025						December 31, 2024
Accounts receivable and unbilled revenues						$	781.9					$	648.1
Allowance for credit losses						39.7						46.9
Accounts receivable and unbilled revenues, net (1)						$	742.2					$	601.2
Total accounts receivable, net – past due greater than 90 days (1)						$	33.0					$	38.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						94.5		%				93.8		%

(1)    Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at December 31, 2025, $424.0 million, or 57.1%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

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

						Year Ended December 31
(in millions)						2025						2024						2023
Balance at January 1						$	46.9					$	44.5					$	49.7
Provision for credit losses						66.0						32.8						23.8
Provision for credit losses deferred for future recovery or refund						6.3						46.3						45.7
Write-offs charged against the allowance						(110.3)						(102.5)						(94.1)
Recoveries of amounts previously written off						30.8						25.8						19.4
Balance at December 31						$	39.7					$	46.9					$	44.5

The allowance for credit losses decreased during the year ended December 31, 2025, largely driven by customer write-offs in addition to a decrease in past due account balances that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.

The allowance for credit losses increased during the year ended December 31, 2024, primarily related to an increase in reserve percentages associated with the higher write-offs we saw during the year.

The allowance for credit losses decreased during the year ended December 31, 2023, primarily related to lower customer energy costs (driven by the warmer weather during the fourth quarter of 2023 when compared to the same quarter in 2022 and lower

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natural gas prices), which contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. Customer write-offs also contributed to the decrease in the allowance for credit losses.

NOTE 7—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:

(in millions)						2025						2024						See Note
Regulatory assets (1) (2)
We Power finance leases						$	1,158.6					$	1,139.1					15
Plant retirement related items (3)						634.3						655.1
Income tax related items						413.3						364.6						16
Pension and OPEB costs (4)						289.0						343.1						19, 24
Uncollectible expense						114.7						108.4						6
SSR (5)						92.6						102.9
Securitization						67.5						76.5						21
AROs						59.7						52.8						1(k), 10
Other finance and operating leases						25.2						15.1						15
Bluewater (6)						13.9						21.1
Other, net						72.2						67.6
Total regulatory assets						$	2,941.0					$	2,946.3

(1)    Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $15.3 million and $18.1 million at December 31, 2025 and 2024, respectively.

(2)    As of December 31, 2025, we had $15.5 million of regulatory assets not earning a return and $106.1 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to electric transmission costs. The other regulatory assets in the table either earn a return at our weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.

(3)    Primarily represents the net book value of power plants we have both abandoned and retired. For all of these plants, we have approval to collect a return of their remaining net book value. We also have approval to collect a return on all but $100 million of their remaining net book value. For information on the securitization of this $100 million, see Note 21, Variable Interest Entities. These regulatory assets are amortized on a straight-line basis, using the composite depreciation rates approved before the plants were retired, and the amortization is included in depreciation and amortization in the income statement.

(4)    Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(5)    This regulatory asset relates to our 2014 announcement to retire the PIPP. Despite our intent to retire the PIPP, MISO designated the PIPP as an SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for our SSR revenues because of the fluctuations in the actual revenues we received under the PIPP SSR agreements. The rate order we received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020.

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

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The following regulatory liabilities were reflected on our balance sheets as of December 31:

(in millions)						2025						2024						See Note
Regulatory liabilities
Removal costs (1)						$	862.1					$	809.2
Income tax related items						663.5						653.9						16
Pension and OPEB benefits (2)						114.6						118.5						19, 24
Energy costs refundable through rate adjustments						47.2						70.7						1(d)
Earnings sharing mechanism						29.3						5.6						24
Revenue requirements of renewable generation facilities (3)						13.0						37.9
Electric transmission costs (4)						—						19.7
Other, net						44.9						47.3
Total regulatory liabilities						$	1,774.6					$	1,762.8
Balance sheet presentation
Other current liabilities						$	15.6					$	4.0
Regulatory liabilities						1,759.0						1,758.8
Total regulatory liabilities						$	1,774.6					$	1,762.8

(1)    Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 10, Asset Retirement Obligations, for more information on our legal obligations.

(2)    Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.

(3)    These amounts represent the deferral of the incremental revenue requirement impact from the delayed in-service date of certain renewable generation facilities we constructed.

(4)    In accordance with the PSCW's approval of escrow accounting for our ATC and MISO network transmission expenses, we 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.

Oak Creek Power Plant Units 5-6

In May 2024, OCPP Units 5 and 6 were retired. Due to the retirement of these units and the determination that recovery was probable, their net book value of $68.3 million at December 31, 2025 was classified as a regulatory asset. In addition, a $45.0 million cost of removal reserve related to the units continued to be classified as a regulatory liability at December 31, 2025. Not included in these amounts was $6.3 million of deferred tax liabilities previously recorded for the retired units. Effective with our rate order issued by the PSCW in December 2022, we received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. We also have FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

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NOTE 8—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following at December 31:

(in millions)						2025						2024
Electric – generation						$	3,977.8					$	3,251.3
Electric – distribution						7,050.2						6,537.6
Natural gas – distribution, storage, and transmission						2,286.9						2,174.1
Property, plant, and equipment to be retired						621.7						657.4
Other						1,095.4						1,102.3
Less: Accumulated depreciation						3,990.7						3,728.2
Net						11,041.3						9,994.5
CWIP						2,522.1						1,128.3
Net property, plant, and equipment						13,563.4						11,122.8
Property under finance leases						3,372.6						3,291.8
Less: Accumulated amortization						1,727.4						1,603.9
Net leased facilities						1,645.2						1,687.9
Total property, plant, and equipment						$	15,208.6					$	12,810.7

Severance Liability for Plant Retirements

We have severance liabilities related to past and future plant retirements recorded in other current and other long-term liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows:

(in millions)						2025						2024						2023
Severance liability at January 1						$	11.2					$	15.1					$	13.5
Severance expense						—						(3.5)			(1)			1.6
Severance payments						(0.7)						(0.4)						—
Total severance liability at December 31						$	10.5					$	11.2					$	15.1

(1)    The severance accrual was lowered in 2024 due to workforce realignment efforts.

Plant to be Retired

Oak Creek Power Plant Units 7 and 8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for several other renewable and other projects and have also acquired additional projects. On June 25, 2025, we announced plans to extend the lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through the end of 2026. These units were originally scheduled to be retired at the end of 2025. The total net book value of our ownership share of OCPP Units 7 and 8 was $621.7 million at December 31, 2025, 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 continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

NOTE 9—JOINTLY-OWNED UTILITY FACILITIES

We hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We have supplied our own financing for all jointly owned projects. We pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our

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proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

Information related to jointly owned utility facilities in-service at December 31, 2025 was as follows:

Jointly-Owned Utility Facilities												Ownership						Share of Capacity (MW)						In-Service /Acquisition Date						Operating Owner						Property, Plant, and Equipment						Accumulated Depreciation						CWIP
(in millions, except for percentages and MW)
West Riverside (1) (3)												27.5		%				190.2						2023 & 2024						WPL						$	223.6					$	(36.7)					$	2.2
Badger Hollow II (2)												66.7		%				100.0						2023						WE						179.3						(11.8)						—
Weston RICE units (1)												50.0		%				65.0						2023						WPS						93.3						(7.4)						—
Whitewater (1)												50.0		%				117.2						2023						WE						126.4						(98.1)						12.9
Paris Solar (2)												75.0		%				150.0						2024						WE						300.3						(9.2)						—
Paris Battery												75.0		%				82.5						2025						WE						197.8						(4.6)						—
Darien Solar (2)												75.0		%				187.5						2025						WE						384.2						(8.9)						—

(1)    Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2026 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(2)     Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(3)    We acquired a 13.8% ownership interest in June 2023 and acquired an additional 13.7% ownership interest in May 2024. See Note 2, Acquisitions, for more information.

Information related to jointly owned utility facilities approved by the PSCW at December 31, 2025 was as follows:

Jointly-Owned Utility Facilities												Ownership						Share of Capacity (MW)						Date of Expected In-Service						CWIP
(in millions, except for percentages and MW)
Koshkonong Solar												75.0		%				225.0						2026						$	384.2
Koshkonong Battery												75.0		%				124.2						2027						125.6
Darien Battery												75.0		%				56.7						2027						56.9
High Noon Solar												75.0		%				225.0						2027						337.1
High Noon Battery												75.0		%				124.2						2027						125.7
Ursa Solar Electric Generation Facility												80.0		%				160.0						2027						50.8
Saratoga Solar												80.0		%				120.0						2028						34.8
Saratoga Battery												80.0		%				40.0						2028						47.2
Badger Hollow Wind Energy Generation Facility												80.0		%				88.9						2027						44.4
Whitetail												80.0		%				53.3						2027						8.0

NOTE 10—ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; the removal and dismantlement of a battery storage facility; and the closure of CCR landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the PSCW.

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On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31:

(in millions)						2025						2024						2023
Balance as of January 1						$	120.6					$	73.1					$	71.7
Accretion						5.2						2.9						1.8
Additions						21.7			(1)			44.8			(2)			4.4
Revisions to estimated cash flows						(1.9)						—						(4.5)
Liabilities settled						(0.7)						(0.2)						(0.3)
Balance as of December 31						$	144.9					$	120.6					$	73.1

(1)    AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, renewable generation projects.

(2)    AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 22, Commitments and Contingencies, for more information.

NOTE 11—COMMON EQUITY

Stock-Based Compensation

The following table summarizes our pre-tax stock-based compensation expense, including amounts allocated from WBS, and the related tax benefit recognized in income for the years ended December 31:

(in millions)						2025						2024						2023
Stock options						$	1.6					$	1.8					$	1.9
Restricted stock						2.3						2.7						2.3
Performance units						15.1						11.3						(0.9)			(1)
Stock-based compensation expense						$	19.0					$	15.8					$	3.3
Related tax benefit						$	5.2					$	4.3					$	0.9

(1)    The reduction in expense was due to a decrease in the fair value of the outstanding performance units.

Stock-based compensation costs capitalized during 2025, 2024, and 2023 were not significant.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2025:

Stock Options						Number of Options						Weighted-Average Exercise Price						Weighted-Average Remaining Contractual Life (in years)						Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2025						433,270						$	78.74
Granted						41,084						94.55
Exercised						(78,705)						63.55
Transferred						(21,990)						88.03
Outstanding as of December 31, 2025						373,659						83.13						4.8						$	8.3
Exercisable as of December 31, 2025						321,656						81.85						4.3						$	7.6

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2025. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2025, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2025, 2024, and 2023 was $3.4 million, $2.0 million, and $2.5 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $5.0 million, $3.5 million, and $2.5 million during the years ended December 31, 2025, 2024, and 2023, respectively. The tax benefit from option exercises for the same years was approximately $0.9 million, $0.5 million, and

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$0.7 million, respectively. These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, we expected to recognize approximately $0.5 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, the Compensation Committee awarded 24,036 non-qualified WEC Energy Group stock options with an exercise price of $106.09 and a weighted-average grant date fair value of $21.20 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following is a summary of our employees' WEC Energy Group restricted stock activity during 2025:

Restricted Shares						Number of Shares						Weighted-Average Grant Date Fair Value
Outstanding and unvested as of January 1, 2025						14,159						$	87.11
Granted						10,162						94.55
Released						(5,103)						90.14
Transferred						(5,398)						88.09
Forfeited						(5,593)						90.84
Outstanding and unvested as of December 31, 2025						8,227						91.24

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.5 million for the year ended December 31, 2025 and $0.3 million for each of the years ended December 31, 2024 and 2023. The tax benefit from released restricted shares was $0.1 million for each of the years ended December 31, 2025, 2024, and 2023. These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, we expected to recognize approximately $1.7 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, the Compensation Committee awarded 4,990 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $106.09 per share.

Performance Units

During 2025, 2024, and 2023, the Compensation Committee awarded 33,070; 34,037; and 19,780 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $2.9 million, $0.3 million, and $1.2 million were settled during 2025, 2024, and 2023, respectively. The tax benefit from the distribution of performance units for the same years was $0.7 million, $0.1 million, and $0.3 million, respectively.

During the year ended December 31, 2025, we transferred 17,544 performance units to WBS in connection with the transfer of certain employees. At December 31, 2025, our employees held 41,341 WEC Energy Group performance units, including dividend equivalents. A liability of $4.6 million was recorded on our balance sheet at December 31, 2025 related to these outstanding units. As of December 31, 2025, we expected to recognize approximately $11.9 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, performance units held by our employees with an intrinsic value of $2.0 million were settled. The tax benefit from the distribution of these awards was $0.5 million. This amount and the tax benefits disclosed above do not account for the compensation limitations under Internal Revenue Code Section 162(m). In January 2026, the Compensation Committee also awarded 16,268 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

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Restrictions

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries.

In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 53.0%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.

We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a 12-month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

See Note 13, Short-Term Debt and Lines of Credit, for a discussion of certain financial covenants related to our short-term debt obligations.

As of December 31, 2025, our restricted retained earnings totaled $2.2 billion.

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

NOTE 12—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2025 and 2024:

(in millions, except share and per share amounts)						Shares Authorized						Shares Outstanding						Redemption Price Per Share						Total
$100 par value, Six Per Cent. Preferred Stock						45,000						44,498						$	—					$	4.4
$100 par value, Serial Preferred Stock 3.60% Series						2,286,500						260,000						101						26.0
$25 par value, Serial Preferred Stock						5,000,000						—						—						—
Total																								$	30.4

NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:

(in millions, except percentages)						2025						2024
Commercial paper
Amount outstanding at December 31						$	680.6					$	179.9
Average interest rate on amounts outstanding at December 31						3.88		%				4.63		%

Our average amount of commercial paper borrowings based on daily outstanding balances during 2025 was $201.5 million, with a weighted-average interest rate during the period of 4.30%.

We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 65% or less. As of December 31, 2025, we were in compliance with this ratio.

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The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31:

(in millions)						Maturity						2025
Revolving credit facility (1)						August 2030						$	800.0
Less:
Letters of credit issued inside credit facility												1.0
Commercial paper outstanding												680.6
Available capacity under existing agreement												$	118.4

(1)    In August 2025, we increased our credit facility to $800.0 million and extended the maturity to August 2030.

This facility has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year.

Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control.

NOTE 14—LONG-TERM DEBT

The following table is a summary of our long-term debt outstanding as of December 31:

(in millions)						Interest Rate						Year Due						2025						2024
WE Debentures (unsecured)						3.10%						N/A						$	—					$	250.0
						6.50%						2028						150.0						150.0
						1.70%						2028						300.0						300.0
						3.95%						2029						300.0						—
						5.00%						2029						350.0						350.0
						4.15%						2030						500.0						—
						4.75%						2032						500.0						500.0
						5.625%						2033						335.0						335.0
						4.60%						2034						300.0						300.0
						5.70%						2036						300.0						300.0
						3.65%						2042						250.0						250.0
						4.25%						2044						250.0						250.0
						4.30%						2045						250.0						250.0
						4.30%						2048						300.0						300.0
						5.05%						2054						300.0						300.0
						6.875%						2095						100.0						100.0
WEPCo Environmental Trust (secured, nonrecourse) (1) (2)						1.578%						2026-2035						78.8						88.0
Total																		4,563.8						4,023.0
Unamortized debt issuance costs																		(23.3)						(19.8)
Unamortized discount, net																		(15.2)						(16.0)
Total long-term debt, including current portion																		4,525.3						3,987.2
Current portion of long-term debt																		(9.3)						(259.2)
Total long-term debt																		$	4,516.0					$	3,728.0

(1)    WEPCo Environmental Trust’s ETBs are secured by a pledge of and lien on environmental control property, which includes the right to impose, collect and receive a non-bypassable environmental control charge paid by all of our retail electric distribution customers, the right to obtain true-up adjustments of the environmental control charge, and all revenues or other proceeds arising from those rights and interests. See Note 21, Variable Interest Entities, for more information.

(2)    The long-term debt of WEPCo Environmental Trust requires periodic principal payments.

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We amortize debt premiums, discounts, and debt issuance costs over the life of the debt using the straight-line method and we include the costs in interest expense.

In December 2024, the DOE issued to us a conditional commitment for a federal loan guarantee for up to $2.5 billion of borrowings that we would use to fund a portion of the costs to construct certain utility-scale renewable generation projects. The conditional commitment was issued pursuant to provisions of the IRA. Under the conditional commitment, the guaranteed borrowings would be senior, unsecured borrowings made through the Federal Financing Bank and reduce our issuance of senior, unsecured obligations in the capital markets. Final approval and issuance of a loan guarantee by the DOE is subject to numerous conditions, including negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and the satisfaction of other conditions. While we continue to work with the DOE, there can be no assurance that the DOE will issue the loan guarantee.

In June 2025, our $250.0 million of 3.10% Debentures, due June 1, 2025, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

In September 2025, we issued $500.0 million of 4.15% Debentures, due October 15, 2030, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In December 2025, we issued $300.0 million of 3.95% Debentures, due March 1, 2029, and used the net proceeds to repay short-term debt and for other general corporate purposes.

The following table shows the future maturities of our long-term debt outstanding as of December 31, 2025:

(in millions)
2026						$	9.3
2027						9.5
2028						459.6
2029						659.8
2030						509.9
Thereafter						2,915.7
Total						$	4,563.8

Our long-term debt obligations contain covenants related to payment of principal and interest when due and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

NOTE 15—LEASES

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our leases is modified to conform to the rate treatment. The difference between the lease expense that is allowed for rate-making purposes and the unadjusted lease expense calculated under Topic 842 is deferred as a regulatory asset on our balance sheets. For our finance leases, amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes in accordance with Subtopic 980-842.

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities associated with the following operating leases:

•Land we are leasing related to our Rothschild biomass plant through June 2051.

•Rail cars we are leasing to transport coal to various generating facilities through June 2027.

•Land we are leasing related to our utility solar generation projects through May 2075.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Certain of our leases contain options for early termination or to renew past the initial term, as set forth in the lease agreements. These options are included in our calculation of the lease obligations if it is reasonably certain that they will be exercised.

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Obligations Under Finance Leases

Port Washington Generating Station

We are leasing PWGS 1 and PWGS 2, two natural gas-fired generation units, which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the original 25-year term of the leases. The lease payments are recovered through our rates, as supported by Wisconsin's 2001 leased generation law.

The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes is generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability.

When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.

Elm Road Generating Station

We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OCPP generating units 5 through 8, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The lease payments are recovered through our rates, as supported by Wisconsin's 2001 leased generation law.

The only variability associated with the ERGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes is generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability.

When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.

Land Leases – Utility Solar Generation

We have entered into various land leases related to our investments in utility solar generation. Each lease has an initial term and one or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term which can range from 40 to 50 years. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates.

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Amounts Recognized in the Financial Statements and Other Information

The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows:

(in millions)						2025						2024						2023
Finance lease expense
Amortization of right of use assets (1)						$	100.9					$	88.5					$	77.5
Interest on lease liabilities (2)						325.1						331.2						329.5
Operating lease expense (3)						2.1						2.0						1.6
Total lease expense						$	428.1					$	421.7					$	408.6
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases						$	325.2					$	331.2					$	329.5
Operating cash flows for operating leases						2.1						2.0						1.6
Financing cash flows for finance leases						100.3						87.9						77.0
Non-cash activities:
Right of use assets obtained in exchange for finance lease liabilities (4)						$	81.5					$	87.1					$	136.5
Right of use assets obtained in exchange for operating lease liabilities						1.5						2.6						2.3
Weighted-average remaining lease term – finance leases						16.3 years						16.4 years						16.2 years
Weighted-average remaining lease term – operating leases						31.4 years						29.6 years						24.9 years
Weighted-average discount rate – finance leases (5)						12.7		%				13.0		%				13.4		%
Weighted average discount rate – operating leases (5)						5.3		%				5.2		%				4.8		%

(1)    Amortization of right of use assets was included as a component of depreciation and amortization expense.

(2)    Interest on lease liabilities was included as a component of interest expense.

(3)    Operating lease expense was included as a component of other operation and maintenance expense.

(4)    Amounts are net of any reductions to right of use assets and finance lease liabilities resulting from remeasurements.

(5)    For the PWGS and ERGS finance leases, the rate implicit in the lease was readily determinable. For all of our other operating and finance leases, we used an estimate of the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

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The following table summarizes our finance and operating lease right of use assets and obligations at December 31:

(in millions)						2025						2024						Balance Sheet Location
Right of use assets
Operating lease right of use assets, net						$	13.3					$	12.2					Other long-term assets
Finance lease right of use assets, net
PWGS						$	212.6					$	239.1
ERGS						1,223.5						1,286.3
Land leases – utility solar generation						209.1						162.5
Total finance lease right of use assets, net (1)						$	1,645.2					$	1,687.9					Property, plant, and equipment, net
Lease obligations
Current operating lease liabilities						$	0.9					$	0.8					Other current liabilities
Long-term operating lease liabilities						$	12.5					$	11.5					Other long-term liabilities
Current finance lease liabilities
PWGS						$	55.6					$	48.5
ERGS						57.8						50.8
Total current finance lease liabilities						$	113.4					$	99.3					Current portion of finance lease obligations
Long-term finance lease liabilities
PWGS						$	384.2					$	431.3
ERGS						2,097.1						2,134.0
Land leases – utility solar generation						234.1						177.6
Total long-term finance lease liabilities						$	2,715.4					$	2,742.9					Finance lease obligations

(1)    Amounts are net of accumulated amortization of $1,727.4 million and $1,603.9 million at December 31, 2025 and 2024, respectively.

Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2025, were as follows:

(in millions)						Total Operating Leases						PWGS						ERGS						Land Leases - Utility Solar Generation						Total Finance Leases
2026						$	1.6					$	105.6					$	317.9					$	6.5					$	430.0
2027						1.0						105.3						317.9						10.2						433.4
2028						0.7						105.3						317.8						11.9						435.0
2029						0.7						105.3						317.6						12.1						435.0
2030						0.8						82.8						317.4						12.4						412.6
Thereafter						25.6						123.0						3,026.7						916.5						4,066.2
Total minimum lease payments						30.4						627.3						4,615.3						969.6						6,212.2
Less: Interest						(17.0)						(187.5)						(2,460.4)						(735.5)						(3,383.4)
Present value of minimum lease payments						13.4						439.8						2,154.9						234.1						2,828.8
Less: Short-term lease liabilities						(0.9)						(55.6)						(57.8)						—						(113.4)
Long-term lease liabilities						$	12.5					$	384.2					$	2,097.1					$	234.1					$	2,715.4

As of February 20, 2026, we have not entered into any material leases that have not yet commenced.

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NOTE 16—INCOME TAXES

We adopted the new disclosure provisions of ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, effective January 1, 2025. See Note 1(n), Income Taxes, for more information on the adoption of this ASU.

Income Tax Expense

The following table is a summary of income tax expense for each of the years ended December 31:

(in millions)						2025						2024						2023
Current tax expense
Federal						$	58.2					$	16.9					$	84.7
State						36.6						9.8						37.3
Deferred income taxes, net
Federal						5.7						75.6						16.5
State						18.3						39.5						9.7
ITCs, net						(3.8)						(5.4)						(5.5)
Total income tax expense						$	115.0					$	136.4					$	142.7

Statutory Rate Reconciliation

The provision for income taxes for each of the years ended December 31 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:

						2025												2024												2023
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Income before income taxes						$	743.0											$	650.8											$	624.5
US federal statutory income tax rate						$	155.8					21.0		%				$	136.4					21.0		%				$	130.9					21.0		%
State and local income taxes net of federal tax effect (1)						42.9						5.8		%				39.0						6.0		%				37.4						6.0		%
Tax credits
PTCs, net (2)						(39.0)						(5.3)		%				(19.0)						(2.9)		%				(11.6)						(1.9)		%
Other						(4.0)						(0.5)		%				(5.5)						(0.9)		%				(5.8)						(0.9)		%
Nontaxable or nondeductible items
AFUDC- Equity (3)						(16.6)						(2.3)		%				(9.7)						(1.5)		%				(8.6)						(1.4)		%
Other						5.9						0.8		%				8.0						1.3		%				7.8						1.2		%
Other adjustments
Tax repairs (4)						(16.2)						(2.2)		%				4.1						0.6		%				4.1						0.7		%
Federal excess deferred tax amortization (5)						(21.8)						(2.9)		%				(20.8)						(3.2)		%				(20.8)						(3.3)		%
Other, net						8.0						1.1		%				3.9						0.6		%				9.3						1.5		%
Total income tax expense						$	115.0					15.5		%				$	136.4					21.0		%				$	142.7					22.9		%

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

(2)    PTCs are an inflation adjusted US 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)    Amounts reflect the net benefit or expense related to the flow through of tax repairs in connection with various rate orders.

(5)    The Tax Cuts and Jobs Act of 2017 required us to remeasure our 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.

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Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 were as follows:

(in millions)						2025						2024
Deferred tax assets
Tax gross up – regulatory items						$	97.1					$	94.6
Deferred revenues						95.0						101.2
Future tax benefits						77.3						11.7
Other						53.2						51.0
Total deferred tax assets						$	322.6					$	258.5
Deferred tax liabilities
Property-related						$	1,651.1					$	1,551.1
Deferred costs – plant retirements						167.8						182.3
Employee benefits and compensation						49.8						55.6
Deferred costs – SSR						30.7						34.1
Other						89.8						91.1
Total deferred tax liabilities						1,989.2						1,914.2
Deferred tax liability, net						$	1,666.6					$	1,655.7

Consistent with ratemaking treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.

The components of net deferred tax assets associated with federal tax benefit carryforwards as of December 31, 2025 and 2024 are summarized in the tables below:

2025 (in millions)						Gross Value						Deferred Tax Effect						Earliest Year of Expiration
Future tax benefits as of December 31, 2025
Federal tax credit						$	—					$	77.3					2042
Balance as of December 31, 2025						$	—					$	77.3

2024 (in millions)						Gross Value						Deferred Tax Effect						Earliest Year of Expiration
Future tax benefits as of December 31, 2024
Federal tax credit						$	—					$	11.7					2042
Balance as of December 31, 2024						$	—					$	11.7

Unrecognized Tax Benefits

We had no unrecognized tax benefits at December 31, 2025 and 2024.

For the years ended December 31, 2025, 2024, and 2023, we recognized no interest expense and no penalties related to unrecognized tax benefits in our income statements. At December 31, 2025 and 2024, we had no interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets.

Our primary tax jurisdictions include federal and the state of Wisconsin. With a few exceptions we are no longer subject to federal income tax examinations by the IRS for years prior to 2022. As of December 31, 2025, we were subject to examination by the Wisconsin taxing authority for tax years 2021 through 2025.

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Cash Paid For Income Taxes, Net

The table below is a summary of income taxes paid by jurisdiction for the years ended December 31:

(in millions)						2025						2024						2023
Federal						$	32.8		(1)			$	42.8		(2)			$	68.4		(3)
State						24.7						21.5						30.7
Total income taxes paid, net						$	57.5					$	64.3					$	99.1

(1)    Amount is net of $36.9 million of cash received, related to 2025 and 2024 PTCs that were sold to third parties.

(2)    Amount is net of $18.8 million of cash received, related to 2024 and 2023 PTCs that were sold to third parties.

(3)    Amount is net of $4.9 million of cash received, related to 2023 PTCs that were sold to third parties.

Income taxes paid (net of refunds) exceeded 5 percent of total income taxes paid (net of refunds) in the following jurisdiction:

(in millions)						2025						2024						2023
Wisconsin						$	24.7					$	21.5					$	30.7

NOTE 17—FAIR VALUE MEASUREMENTS

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:

						December 31, 2025
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	0.2					$	3.1					$	—					$	3.3
FTRs						—						—						2.9						2.9
Total derivative assets						$	0.2					$	3.1					$	2.9					$	6.2
Derivative liabilities
Natural gas contracts						$	5.9					$	1.8					$	—					$	7.7

						December 31, 2024
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	7.0					$	3.5					$	—					$	10.5
FTRs						—						—						2.9						2.9
Total derivative assets						$	7.0					$	3.5					$	2.9					$	13.4
Derivative liabilities
Natural gas contracts						$	0.6					$	0.5					$	—					$	1.1

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 to manage electric transmission congestion costs in the MISO Energy Markets.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:

(in millions)						2025						2024						2023
Balance at the beginning of the period						$	2.9					$	2.5					$	2.0
Purchases						12.1						12.1						8.1
Settlements						(12.1)						(11.7)						(7.6)
Balance at the end of the period						$	2.9					$	2.9					$	2.5

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Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:

						December 31, 2025												December 31, 2024
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock						$	30.4					$	21.2					$	30.4					$	21.2
Long-term debt, including current portion						4,525.3						4,434.6						3,987.2						3,792.3

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

NOTE 18—DERIVATIVE INSTRUMENTS

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.

						December 31, 2025												December 31, 2024
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	3.3					$	7.4					$	10.0					$	1.1
FTRs						2.9						—						2.9						—
Total current						6.2						7.4						12.9						1.1
Long-term
Natural gas contracts						—						0.3						0.5						—
Total						$	6.2					$	7.7					$	13.4					$	1.1

Realized gains and losses on derivatives are primarily 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 fuel and natural gas cost recovery mechanisms. Our realized gains and losses and the estimated notional volumes related to these settlements were as follows for the years ended:

						December 31, 2025												December 31, 2024												December 31, 2023
(in millions)						Volumes						Gains (Losses)						Volumes						Gains (Losses)						Volumes						Gains (Losses)
Natural gas contracts						70.5 Dth						$	(3.3)					69.9 Dth						$	(38.3)					68.5 Dth						$	(102.2)
FTRs						17.4 MWh						9.5						19.2 MWh						5.8						20.4 MWh						14.5
Total												$	6.2											$	(32.5)											$	(87.7)

At December 31, 2025 and 2024, we had posted cash collateral of $12.2 million and $4.9 million, respectively. We had also received cash collateral of $2.8 million at December 31, 2024.

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

						December 31, 2025												December 31, 2024
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Gross amount recognized on the balance sheet						$	6.2					$	7.7					$	13.4					$	1.1
Gross amount not offset on the balance sheet						(0.3)						(6.1)			(1)			(3.6)			(2)			(0.8)
Net amount						$	5.9					$	1.6					$	9.8					$	0.3

(1)     Includes cash collateral posted of $5.8 million.

(2)    Includes cash collateral received of $2.8 million.

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NOTE 19—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Generally, employees receive a benefit based on a percentage of their annual salary plus an interest credit. Management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

We use a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets:

						Pension Benefits												OPEB Benefits
(in millions)						2025						2024						2025						2024
Change in benefit obligation
Obligation at January 1						$	851.7					$	900.8					$	172.0					$	163.4
Service cost						10.1						10.4						3.5						3.2
Interest cost						45.6						44.5						9.4						8.2
Participant contributions						—						—						5.4						5.3
Plan amendments						—						—						(0.8)						—
Net transfer from/to affiliates						0.9						0.4						0.2						0.3
Actuarial (gain) loss						(6.0)						(27.5)						8.6						5.8
Benefit payments						(76.1)						(76.9)						(18.1)						(16.8)
Federal subsidy on benefits paid						N/A						N/A						1.3						1.3
Transfer						—						—						1.3						1.3
Obligation at December 31						$	826.2					$	851.7					$	182.8					$	172.0
Change in fair value of plan assets
Fair value at January 1						$	902.7					$	932.2					$	170.8					$	172.8
Actual return on plan assets						74.7						43.9						17.0						9.2
Employer contributions net of plan transfer						3.0						3.1						0.1						0.1
Participant contributions						—						—						5.4						5.3
Net transfer from/to affiliates						0.9						0.4						0.2						0.2
Benefit payments						(76.1)						(76.9)						(18.1)						(16.8)
Fair value at December 31						$	905.2					$	902.7					$	175.4					$	170.8
Funded status at December 31						$	79.0					$	51.0					$	(7.4)					$	(1.2)

In 2025 and 2024, we had actuarial gains related to our pension benefit obligations of $6.0 million and $27.5 million, respectively. The primary driver for the actuarial gain in 2025 was higher than expected asset returns. The primary driver for the actuarial gain in 2024 was a higher discount rate. Partially offsetting the gain in 2024, was lower than expected asset returns. The discount rate for our pension benefits was 5.49%, 5.70%, and 5.20% in 2025, 2024, and 2023, respectively.

In 2025 and 2024, we had actuarial losses related to our OPEB benefit obligation of $8.6 million and $5.8 million, respectively, both of which were driven by changes to medical trend assumptions and claims and premium updates. The 2025 loss was also driven by a lower discount rate. Partially offsetting the loss in 2024 was a higher discount rate. The discount rate for our OPEB benefits was 5.55%, 5.70%, and 5.15% in 2025, 2024, and 2023, respectively.

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The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:

						Pension Benefits												OPEB Benefits
(in millions)						2025						2024						2025						2024
Pension and OPEB assets						$	105.8					$	79.2					$	—					$	—
Other long-term liabilities						26.8						28.2						7.4						1.2
Total net assets						$	79.0					$	51.0					$	(7.4)					$	(1.2)

The accumulated benefit obligation for all defined benefit pension plans was $825.3 million and $851.0 million as of December 31, 2025 and 2024, respectively.

The following table shows information for the pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)						2025						2024
Accumulated benefit obligation						$	26.7					$	28.0

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:

(in millions)						2025						2024
Projected benefit obligation						$	26.9					$	28.2

The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:

(in millions)						2025						2024
Accumulated benefit obligation						$	182.8					$	172.0
Fair value of plan assets						175.4						170.8

The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31:

						Pension Benefits												OPEB Benefits
(in millions)						2025						2024						2025						2024
Net regulatory assets (liabilities)
Net actuarial loss (gain)						$	273.5					$	311.1					$	(69.3)					$	(75.7)
Prior service credits						(1.7)						(1.8)						(1.0)						(0.3)
Total						$	271.8					$	309.3					$	(70.3)					$	(76.0)

The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:

						Pension Benefits																		OPEB Benefits
(in millions)						2025						2024						2023						2025						2024						2023
Service cost						$	10.1					$	10.4					$	10.3					$	3.5					$	3.2					$	2.6
Interest cost						45.6						44.5						47.1						9.4						8.2						7.7
Expected return on plan assets						(59.1)						(61.6)						(64.3)						(10.9)						(11.0)						(13.4)
Plan settlement/curtailment						—						3.1						—						—						—						—
Amortization of prior service credit						(0.1)						(0.1)						(0.1)						(0.1)						(0.1)						(0.9)
Amortization of net actuarial loss (gain)						16.0						18.1						9.2						(3.9)						(5.7)						(8.7)
Net periodic benefit cost (credit)						$	12.5					$	14.4					$	2.2					$	(2.0)					$	(5.4)					$	(12.7)

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of December 31, 2025 and 2024, we recorded a $9.8 million regulatory liability and a $9.9 million regulatory asset for pension costs, respectively, and a $1.0 million and a $17.8 million regulatory asset for OPEB costs, respectively. The above table does not reflect any adjustments for the creation of these regulatory assets and liabilities.

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The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:

						Pension Benefits												OPEB Benefits
						2025						2024						2025						2024
Discount rate						5.49%						5.70%						5.55%						5.70%
Rate of compensation increase						4.00%						4.00%						N/A						N/A
Interest credit rate						5.12%						5.14%						N/A						N/A
Assumed medical cost trend rate (Pre 65)						N/A						N/A						8.00%						7.00%
Ultimate trend rate (Pre 65)						N/A						N/A						5.00%						5.00%
Year ultimate trend rate is reached (Pre 65)						N/A						N/A						2032						2033
Assumed medical cost trend rate (Post 65)						N/A						N/A						9.83%						6.20%
Ultimate trend rate (Post 65)						N/A						N/A						5.00%						5.00%
Year ultimate trend rate is reached (Post 65)						N/A						N/A						2034						2030

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:

						Pension Benefits
						2025						2024						2023
Discount rate						5.70%						5.20%						5.50%
Expected return on plan assets						6.50%						6.50%						6.50%
Rate of compensation increase						4.00%						4.00%						4.00%
Interest credit rate						5.14%						5.14%						5.14%

						OPEB Benefits
						2025						2024						2023
Discount rate						5.70%						5.15%						5.50%
Expected return on plan assets						6.50%						6.50%						6.50%
Assumed medical cost trend rate (Pre 65)						7.00%						6.25%						6.50%
Ultimate trend rate (Pre 65)						5.00%						5.00%						5.00%
Year ultimate trend rate is reached (Pre 65)						2033						2031						2031
Assumed medical cost trend rate (Post 65)						6.20%						6.55%						6.00%
Ultimate trend rate (Post 65)						5.00%						5.00%						5.00%
Year ultimate trend rate is reached (Post 65)						2030						2030						2031

WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the trust. For 2026, the expected return on asset assumption for the pension plan and OPEB plans is 6.50%.

Plan Assets

Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Our pension trust target asset allocations are 25% equity investments, 55% fixed income investments, and 20% private equity and real estate investments. The OPEB trust target asset allocations are 45% equity investments, 45% fixed income investments, and 10% real estate investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income

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securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(o), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

The following tables provide the fair values of our investments by asset class:

						December 31, 2025
						Pension Plan Assets																								OPEB Assets
(in millions)						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Asset Class
Equity securities:
United States equity						$	53.2					$	—					$	—					$	53.2					$	17.7					$	—					$	—					$	17.7
International equity						56.3						—						—						56.3						18.4						—						—						18.4
Fixed income securities: (1)
United States bonds						—						402.5						0.7						403.2						17.1						50.9						0.1						68.1
International bonds						—						20.6						—						20.6						—						1.8						—						1.8
						$	109.5					$	423.1					$	0.7					$	533.3					$	53.2					$	52.7					$	0.1					$	106.0
Investments measured at net asset value:
Equity securities																								138.1																								38.1
Fixed income securities																								—																								7.4
Other																								233.8																								23.9
Total																								$	905.2																							$	175.4

(1)    This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

						December 31, 2024
						Pension Plan Assets																								OPEB Assets
(in millions)						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Asset Class
Equity securities:
United States equity						$	55.2					$	—					$	—					$	55.2					$	17.6					$	—					$	—					$	17.6
International equity						51.8						—						—						51.8						16.4						—						—						16.4
Fixed income securities: (1)
United States bonds						—						388.9						—						388.9						14.7						49.7						—						64.4
International bonds						—						28.0						—						28.0						—						2.8						—						2.8
						$	107.0					$	416.9					$	—					$	523.9					$	48.7					$	52.5					$	—					$	101.2
Investments measured at net asset value:
Equity securities																								137.0																								36.5
Fixed income securities																								—																								6.9
Other																								241.8																								26.2
Total																								$	902.7																							$	170.8

(1)    This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

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The following tables set forth a reconciliation of changes in fair values of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:

																		United States Bonds
(in millions)																														Pension						OPEB
Beginning balance at January 1, 2025																														$	—					$	—
Purchases																														0.7						0.1
Ending balance at December 31, 2025																														$	0.7					$	0.1

Cash Flows

We expect to contribute $3.0 million to the pension plans and $0.3 million to the OPEB plans in 2026, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years:

(in millions)						Pension Benefits						OPEB Benefits
2026						$	83.7					$	11.9
2027						80.2						12.6
2028						77.8						13.0
2029						76.6						13.4
2030						71.7						13.7
2031-2035						323.1						70.4

Savings Plans

WEC Energy Group sponsors 401(k) savings plans that allow substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive a retirement contribution in lieu of receiving a pension benefit. Total costs incurred under all of these plans were $19.7 million, $17.7 million, and $15.5 million in 2025, 2024, and 2023, respectively.

NOTE 20—SEGMENT INFORMATION

Our President, 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 shareholder to measure segment profitability and to allocate resources, including assets, to our business. Net income attributed to common shareholder 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 net income to evaluate performance by comparing actual results to budgeted and forecasted amounts, as well as the ROE earned.

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, as well as the revenue streams for the products or services provided to customers through electric, natural gas, and renewable operations. See Note 5, Operating Revenues, for more information on disaggregation of operating revenues. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.

At December 31, 2025, we reported two segments, our utility segment and our other segment, which are described below. All of our operations are located within the United States.

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Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations.

•Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee.

•Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin.

No significant items were reported in the other segment during the twelve months ended December 31, 2025, 2024, and 2023.

Since our utility segment consists of all revenues and costs used in our performance measure of net income attributable to common shareholder, see our income statements for more information. Other income, net on our income statements includes amounts that are not material for interest income.

The following table shows additional financial information for our utility segment cost of sales for the years ended December 31, 2025, 2024, and 2023.

(in millions)						2025						2024						2023
Cost of Sales:
Fuel and purchased power						$	1,217.7					$	1,088.6					$	1,178.9
Cost of natural gas sold						281.1						211.7						272.5

Our utility segment assets are reported on the balance sheet as total assets. Our utility segment capital expenditures are reported on the statement of cash flows as capital expenditures and asset acquisitions.

NOTE 21—VARIABLE INTEREST ENTITIES

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

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

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to our 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 us 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 our wholly owned subsidiary.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from us. 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 our 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 us or any of our affiliates.

We act as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and are responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, we are authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal,

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interest, and other ongoing financing costs. We remit 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 have the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, we are 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)						December 31, 2025						December 31, 2024
Assets
Other current assets (restricted cash)						$	2.0					$	1.5
Regulatory assets						67.5						76.5
Other long-term assets (restricted cash)						0.6						0.6
Liabilities
Current portion of long-term debt						9.3						9.2
Account payable						0.1						—
Other current liabilities (accrued interest)						0.1						0.1
Long-term debt						67.4						76.4

NOTE 22—COMMITMENTS AND CONTINGENCIES

We 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

We have obligations to distribute and sell electricity and natural gas to our customers and 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 following table shows our minimum future commitments related to these purchase obligations as of December 31, 2025:

																		Payments Due By Period
(in millions)						Date Contracts Extend Through						Total Amounts Committed						2026						2027						2028						2029						2030						Later Years
Electric utility:
Nuclear						2033						$	5,045.8					$	681.6					$	730.4					$	782.6					$	838.5					$	898.5					$	1,114.2
Coal supply and transportation						2030						262.2						144.3						93.0						19.7						3.5						1.7						—
Purchased power						2058						132.4						5.0						5.1						5.1						5.3						5.4						106.5
Natural gas utility supply and transportation						2048						697.4						88.6						84.4						80.4						72.4						42.6						329.0
Total												$	6,137.8					$	919.5					$	912.9					$	887.8					$	919.7					$	948.2					$	1,549.7

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 SO2, NOx, fine particulates, 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.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:

•the development of additional sources of renewable electric energy supply, battery storage, and natural gas and LNG storage facilities;

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•the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;

•the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;

•the protection of wetlands and waterways, biodiversity including threatened and endangered species, and cultural resources associated with construction projects;

•the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;

•the beneficial use of ash and other products from coal-fired and biomass generating units;

•the remediation of former manufactured gas plant sites;

•the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure; and

•the tracking and reporting of GHG emissions.

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 would 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. The rule is expected to face litigation.

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.

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. We believe we are well positioned to comply with the requirements of the 2024 Amendments.

In June 2025, the EPA proposed to repeal the 2024 Amendments which would result in a return of the PM limit to 0.03 lb/MMBtu. In December 2025, the EPA submitted a draft of the rule to the OMB for interagency review. Following completion of the OMB review process, the EPA has stated it expects the rule to be finalized in the first quarter of 2026.

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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 territory 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 WDNR 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. 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. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

New Source Performance Standards

Nitrogen Oxides

In January 2026, the EPA released a pre-publication version of its final rule regulating NOx for CTs constructed, modified, or reconstructed after December 13, 2024. The final rule, which 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 we are well positioned to comply with this rule.

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

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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 which version 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. WEC Energy Group does not expect either alternative to have any impact on its 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, under the Federal Deregulatory Actions discussion 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.

WEC Energy Group's 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 2,100 MWs of fossil-fueled generation since the beginning of 2018. WEC Energy Group expects to retire approximately 900 MWs of additional coal-fired generation by the end of 2031. See Note 8, Property, Plant, and Equipment, for more information related to our planned power plant retirements. WEC Energy Group has a long-term goal to achieve net carbon-neutral electric generation by the end of 2050. It expects to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. As part of our path toward this goal, we have started implementing co-firing with natural gas at the ERGS coal-fired units in 2025. WEC Energy Group expects 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.

WEC Energy Group also continues to focus on methane emission reductions by improving and upgrading its natural gas distribution system and using RNG throughout its natural gas utility systems.

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 combustion residual leachate 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 DOE, a public utility commission, or independent system operator. Based on current electric

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generation resource planning, in December 2025, we filed Notice of Planned Participations to opt into the PCCC subcategory for certain of our past and current coal-fueled facilities.

In December 2025, the EPA published a final rule, 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.

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 2024 ELG Rule, as well as the deadline extension rule, remain in effect during the pendency of the legal challenge. The outcome of this case may affect our compliance plans.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we 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. We are responsible for the environmental remediation of these sites. We are working with the state of Wisconsin 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.

We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31:

(in millions)						2025						2024
Regulatory assets for environmental remediation costs						$	7.8					$	10.8
Reserves for future environmental remediation (1)						$	7.7					$	10.6

(1)    Recorded within other long-term liabilities on our balance sheets.

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. The EPA has stated it plans to publish a new final rule by the end of 2026. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. We have achieved our required renewable energy percentage of 8.27% by constructing various wind and solar facilities, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual retail operating revenues.

Enforcement and Litigation Matters

We 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 23—SUPPLEMENTAL CASH FLOW INFORMATION

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

						Year Ended December 31
(in millions)						2025						2024						2023
Cash paid for interest, net of amount capitalized						$	482.7					$	474.9					$	463.8
Cash paid for income taxes, net						57.5						64.3						99.1
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						191.8						178.4						71.8
Liabilities accrued for software licensing agreements						9.0						—						—

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 at December 31 to the total of these amounts shown on the statements of cash flows:

(in millions)						2025						2024						2023
Cash and cash equivalents						$	—					$	0.4					$	6.1
Restricted cash included in other current assets						2.0						1.5						0.8
Restricted cash included in other long-term assets						0.6						0.6						0.6
Cash, cash equivalents, and restricted cash						$	2.6					$	2.5					$	7.5

Our restricted cash consisted of cash on deposit in a financial institution that is restricted to satisfy the requirements of a debt agreement at WEPCo Environmental Trust. See Note 21, Variable Interest Entities, for more information.

NOTE 24—REGULATORY ENVIRONMENT

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. We subsequently filed testimony in October 2025 slightly modifying the initial proposals. Under these proposed inter-connected tariffs, VLCs (new customers using 500 MWs or more, 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 proposed tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

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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 the resource, except for wind or solar resources which will have a term of 20 years. As currently proposed, the ROE (can range from 10.48% to 10.98% as agreed upon with the customer) and equity ratio (57%) will both be fixed for the entire term of the agreement, and the revenue and costs recovered through the tariffs will be excluded from future rate case proceedings and earnings sharing mechanisms.

We expect a decision from the PSCW in the second quarter of 2026. Prior to the PSCW approving the tariffs, for infrastructure investments that have not received regulatory approval, we require VLCs to enter into payment and cancellation agreements which obligate the VLC to reimburse us 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.

2025 and 2026 Rates

In April 2024, we filed a request with the PSCW to increase our retail electric, natural gas, and steam rates. The primary drivers of the requested increases in electric rates were continued capital investments to transition our generation fleet from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW. The requested increases in natural gas rates were driven by our ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.

In December 2024, the PSCW issued a final written order approving electric, natural gas, and steam base rate increases, effective January 1, 2025 and 2026, as applicable. The final written order reflected the following:

2025 rate increase
Electric (1)						$	144.0	million	/			4.2%
Gas						$	41.3	million	/			7.1%
Steam						$	1.5	million	/			5.0%
2026 rate increase (2)
Electric (1)						$	169.5	million	/			4.5%
Gas						$	29.8	million	/			4.5%
ROE						9.8%
Common equity component average on a financial basis						53.0%

(1)    Amounts reflect the impact to our Wisconsin retail electric operations and include the incremental decrease resulting from updated fuel costs.

(2)    The 2026 rate increases are incremental to the previously authorized revenue plus the approved rate increases for 2025.

Effective January 1, 2025, we were required to implement a new earnings sharing mechanism, under which, if we earn above our authorized ROE: (i) we retain 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.

2024 Limited Rate Case Re-Opener

In accordance with our rate order approved by the PSCW in December 2022, we filed a request with the PSCW in May 2023 for a limited electric and natural gas rate case re-opener. Our limited electric rate case re-opener included updated fuel costs and revenue requirements for the generation projects that were previously approved by the PSCW and were placed into service in 2023 or were expected to be placed into service in 2024. It also included the projected savings from the retirement of the OCPP Units 5 and 6, which were retired in May 2024. Our limited natural gas rate case re-opener reflected the additional revenue requirements associated with our previously approved LNG project that was placed into service in November 2023.

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In December 2023, the PSCW issued a final written order approving electric and natural gas rate increases, effective January 1, 2024. The final orders reflected the following:

2024 incremental rate increases
Electric (1)						$	82.2	million	/			2.5%
Gas						$	23.9	million	/			4.5%

(1)    Amount reflects the impact to our Wisconsin retail electric operations and includes the incremental increase from updated fuel costs.

Our ROE and common equity component average were not addressed in the limited rate case re-opener.

2023 and 2024 Rates

In April 2022, we filed a request with the PSCW to increase our retail electric, natural gas, and steam rates. Our request was updated in July 2022 to reflect new developments that impacted the original proposal. The requested increase in electric rates was driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen our distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments had already been approved by the PSCW. The requested increase in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.

In December 2022, the PSCW issued a final written order approving electric, natural gas, and steam base rate increases, effective January 1, 2023. The final order reflected the following:

2023 base rate increase
Electric						$	283.5	million	/			9.1%
Gas						$	46.1	million	/			9.6%
Steam						$	7.6	million	/			35.3%
ROE						9.8%
Common equity component average on a financial basis						53.0%

In addition to the above, the final order included the following terms:

•We kept our then current earnings sharing mechanism, under which, if we earned above our authorized ROE: (i) we retained 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points was refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings was required to be refunded to ratepayers.

•We were required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life.

•We were not allowed to propose any changes to our real time pricing rates for large commercial and industrial electric customers through the end of 2024.

•We were required to lower monthly residential and small commercial electric customer fixed charges by $1.00 from previously authorized rates.

•We were required to offer an additional voluntary renewable energy pilot for commercial and industrial customers.

•We were required to continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs. We, along with WPS, also collectively contributed $4.0 million to the Keep Wisconsin Warm Fund.

•We were required to implement escrow accounting treatment for pension and OPEB costs. As a result, we defer as a regulatory asset or liability, the difference between actual pension and OPEB costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

•As discussed above, we were authorized to file a limited electric and natural gas rate case re-opener for 2024.

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NOTE 25—OTHER INCOME, NET

Total other income, net was as follows for the years ended December 31:

(in millions)						2025						2024						2023
AFUDC-Equity						$	78.9					$	46.0					$	41.0
Non-service components of net periodic benefit costs						(19.9)						24.3						24.1
Interest income						2.9						9.8						1.1
Other, net						1.0						(1.1)						2.6
Other income, net						$	62.9					$	79.0					$	68.8

NOTE 26—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 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2025.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this annual report.

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 fourth quarter of 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

During the three months ended December 31, 2025, 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).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

The information under "Election of Directors," "Corporate Governance – Frequently Asked Questions," and "Committees of the WEC Energy Group Board of Directors" in our Definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Shareholders to be held April 30, 2026 (the "2026 Annual Meeting Information Statement") is incorporated herein by reference. Also see "Information about our Executive Officers" in Part I of this report.

WEC Energy Group has adopted a written code of ethics, referred to as its Code of Business Conduct. We are a subsidiary of WEC Energy Group, and as such, all of our directors, executive officers, and employees, including our principal executive officer, principal financial officer and principal accounting officer, have a responsibility to comply with WEC Energy Group's Code of Business Conduct. WEC Energy Group has posted its Code of Business Conduct in the "Governance" section on its website, www.wecenergygroup.com. WEC Energy Group has not provided any waiver to the Code for any director, executive officer, or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on WEC Energy Group's website or in a current report on Form 8-K.

ITEM 11. EXECUTIVE COMPENSATION

The information under "Compensation Discussion and Analysis," "Executive Compensation," "Director Compensation," "Committees of the WEC Energy Group Board of Directors," and "Certain Relationships and Related Transactions" in the 2026 Annual Meeting Information Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

All of our Common Stock is owned by our parent company, WEC Energy Group, Inc., 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201. Our directors and director nominees, who are all senior officers of WE and/or WEC Energy Group, as well as our other executive officers, do not own any of our voting securities. The information concerning their beneficial ownership in WEC Energy Group common stock, as well as information regarding ownership of our preferred securities as set forth under "Stock Ownership of Directors, Nominees and Executive Officers" and "Owners of More Than 5% of Preferred Stock," respectively, in the 2026 Annual Meeting Information Statement is incorporated herein by reference.

We do not have any equity compensation plans under which our equity securities may be issued. Our directors, officers and certain employees participate in the compensation plans of WEC Energy Group.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information under "Corporate Governance – Frequently Asked Questions" and "Certain Relationships and Related Transactions" in the 2026 Annual Meeting Information Statement is incorporated herein by reference. A full description of the guidelines the WEC Energy Group Board uses to determine director independence is located in Appendix A of WEC Energy Group's Corporate Governance Guidelines, which can be found on its website, www.wecenergygroup.com.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our AOC under "Independent Auditors' Fees and Services" in the 2026 Annual Meeting Information Statement is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1.			Financial Statements and Report of Independent Registered Public Accounting Firm Included in Part II of This Report
			Description						Page in 10-K
			Report of Independent Registered Public Accounting Firm (PCAOB No. 34).						54
			Consolidated Income Statements for the three years ended December 31, 2025, 2024, and 2023.						56
			Consolidated Balance Sheets at December 31, 2025 and 2024.						57
			Consolidated Statements of Cash Flows for the three years ended December 31, 2025, 2024, and 2023.						58
			Consolidated Statements of Equity for the three years ended December 31, 2025, 2024, and 2023.						59
			Notes to Consolidated Financial Statements.						60
2.			Financial Statement Schedules Included in Part IV of This Report
			Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2025, 2024, and 2023.						110
			Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
3.			Exhibits and Exhibit Index
			The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company (File No. 001-01245). An asterisk (*) indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 15(b) of Form 10-K is identified below by two asterisks (**) following the description of the exhibit.

Number

Exhibit

3

Articles of Incorporation and By-laws

3.1*

Restated Articles of Incorporation of WE, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to WE's 12/31/94 Form 10-K.)

3.2*

Bylaws of WE, as amended to May 1, 2000. (Exhibit (3)-2 to WE's 03/31/00 Form 10-Q.)

4

Instruments defining the rights of security holders, including indentures

4.1*

Reference is made to Article III of the Restated Articles of Incorporation of WE. (See Exhibit 3.1 above.)

4.2*

Description of WE's Preferred Stock. (Exhibit 4.2 to WE's 12/31/19 Form 10-K.)

Indentures and Securities Resolutions:

4.3*

Indenture for Debt Securities of WE (the "WE Indenture"), dated December 1, 1995. (Exhibit (4)-1 to WE's 12/31/95 Form 10-K.)

4.4*

Securities Resolution No. 1 of WE under the WE Indenture, dated December 5, 1995. (Exhibit (4)-2 to WE's 12/31/95 Form 10-K.)

2025 Form 10-K 106 Wisconsin Electric Power Company

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Number

Exhibit

4.5*

Securities Resolution No. 3 of WE under the WE Indenture, dated May 27, 1998. (Exhibit (4)-1 to WE's 06/30/98 Form 10-Q.)

4.6*

Securities Resolution No. 5 of WE under the WE Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to WE's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)

4.7*

Securities Resolution No. 7 of WE under the WE Indenture, dated as of November 2, 2006. (Exhibit 4.1 to WE's 11/02/06 Form 8-K.)

4.8*

Securities Resolution No. 12 of WE under the WE Indenture, dated as of December 5, 2012. (Exhibit 4.1 to WE's 12/05/12 Form 8-K.)

4.9*

Securities Resolution No. 14 of WE under the WE Indenture, dated as of May 12, 2014. (Exhibit 4.1 to WE's 05/12/14 Form 8-K.)

4.10*

Securities Resolution No. 16 of WE under the WE Indenture, dated as of November 13, 2015. (Exhibit 4.1 to WE's 11/13/15 Form 8-K.)

4.11*

Securities Resolution No. 17 of WE under the WE Indenture, dated as of October 1, 2018. (Exhibit 4.1 to WE's 10/01/18 Form 8-K.)

4.12*

Securities Resolution No. 19 of WE under the WE Indenture, dated as of June 8, 2021. (Exhibit 4.1 to WE's 06/15/21 Form 8-K.)

4.13*

Securities Resolution No. 20 of WE under the WE Indenture, dated as of September 14, 2022. (Exhibit 4.1 to WE's 09/22/22 Form 8-K.)

4.14*

Securities Resolution No. 21 of WE under the WE Indenture, dated as of May 7, 2024. (Exhibit 4.1 to WE's 05/14/2024 Form 8-K.)

4.15*

Securities Resolution No. 22 of WE under the WE Indenture, dated as of September 9, 2024. (Exhibit 4.1 to WE's 09/13/2024 Form 8-K.)

4.16*

Securities Resolution No. 23 of WE under the WE Indenture, dated as of September 18, 2025. (Exhibit 4.1 to WE's 09/25/2025 Form 8-K.)

4.17*

Securities Resolution No. 24 of WE under the WE Indenture, dated as of December 2, 2025. (Exhibit 4.1 to WE's 12/05/2025 Form 8-K.)

The forgoing list of exhibits does not include certain unregistered long-term debt instruments of the Registrant and its subsidiary where the total amount of securities authorized to be issued under the instrument does not exceed 10 percent of the total assets of the Registrant and its subsidiary on a consolidated basis. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.

10

Material Contracts

10.1*

WEC Energy Group Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2018. (Exhibit 10.1 to WEC Energy Group's 12/31/18 Form 10-K (File No. 001-09057).)**

10.2*

Legacy Wisconsin Energy Corporation Executive Deferred Compensation Plan, Amended and Restated as of January 1, 2018. (Exhibit 10.2 to WEC Energy Group's 12/31/18 Form 10-K (File No. 001-09057).)**

10.3*

WEC Energy Group Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2018. (Exhibit 10.3 to WEC Energy Group's 12/31/18 Form 10-K (File No. 001-09057).)**

10.4*

Amendment dated as of December 20, 2023 to the WEC Energy Group Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2018. (Exhibit 10.4 to WEC Energy Group's 12/31/2023 Form 10-K.)**

2025 Form 10-K 107 Wisconsin Electric Power Company

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Number

Exhibit

10.5*

WEC Energy Group Non-Qualified Retirement Savings Plan, Amended and Restated Effective as of January 1, 2018. (Exhibit 10.6 to WEC Energy Group's 12/31/18 Form 10-K (File No. 001-09057).)**

10.6*

WEC Energy Group Supplemental Long Term Disability Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.7 to WEC Energy Group's 12/31/18 Form 10-K (File No. 001-09057).)**

10.7*

WEC Energy Group Short-Term Performance Plan, Amended and Restated Effective as of January 1, 2019. (Exhibit 10.8 to WEC Energy Group's 12/31/18 Form 10-K (File No. 001-09057).)**

10.8*

Wisconsin Energy Corporation 2014 Rabbi Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 23, 2015, regarding the trust established to provide a source of funds to assist in meeting the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.13 to Wisconsin Energy Corporation's 12/31/14 Form 10-K (File No. 001-09057).)**

10.9*

Retention Agreement by and between WEC Energy Group and Scott J. Lauber, dated February 21, 2022. (Exhibit 10.16 to WEC Energy Group's 12/31/21 Form 10-K. (File No. 001-09057).)**

10.10*

Letter Agreement by and between WEC Energy Group and Xia Liu, dated March 24, 2020. (Exhibit 10.2 to WEC Energy Group's 03/31/20 Form 8-K (File No. 001-09057).)**

10.11*

Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q (File No. 001-09057).)**

10.12*

Letter Agreement by and between WEC Energy Group and Margaret C. Kelsey, dated as of July 19, 2017. (Exhibit 10.1 to WEC Energy Group's 09/30/17 Form 10-Q. (File No. 001-09057).)**

10.13*

Letter Agreement by and between WEC Energy Group and Michael Hooper, dated March 7, 2024. (Exhibit 10.1 to WEC Energy Group's 03/12/24 Form 8-K.)**

10.14.1*

WEC Energy Group Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.19 to WEC Energy Group's 12/31/15 Form 10-K (File No. 001-09057).)**

10.14.2*

WEC Energy Group Omnibus Stock Incentive Plan, amended and restated effective as of May 6, 2021. (Exhibit 10.1 to WEC Energy Group's 05/11/21 Form 8-K (File No. 001-09057).)**

10.15*

WEC Energy Group Performance Unit Plan, amended and restated effective as of January 1, 2023. (Exhibit 10.1 to WEC Energy Group's 12/02/22 Form 8-K (File No. 001-09057).)**

10.16*

2016 WEC Energy Group Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the WEC Energy Group Omnibus Stock Incentive Plan. (Exhibit 10.29 to WEC Energy Group’s 12/31/15 Form 10-K (File No. 001-09057).)**

10.17*

Non-Qualified Stock Option Award Terms and Conditions under the WEC Energy Group Omnibus Stock Incentive Plan. (Exhibit 10.2 to WEC Energy Group's 06/30/21 Form 10-Q (File No. 001-09057).)**

10.18*

Restricted Stock Award Terms and Conditions under the WEC Energy Group Omnibus Stock Incentive Plan. (Exhibit 10.3 to WEC Energy Group's 06/30/21 Form 10-Q (File No. 001-09057).)**

10.19*

PWGS I Facility Lease Agreement between PWGS, as Lessor, and WE, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to WE's 06/30/03 Form 10-Q.)

10.20*

PWGS II Facility Lease Agreement between PWGS, as Lessor, and WE, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to WE's 06/30/03 Form 10-Q.)

10.21*

ER I Facility Lease Agreement between ERGS, as Lessor, and WE, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

10.22*

ER II Facility Lease Agreement between ERGS, as Lessor, and WE, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

2025 Form 10-K 108 Wisconsin Electric Power Company

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Number

Exhibit

10.23*

Point Beach PPA between FPL Energy Point Beach, LLC and WE, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q (File No. 001-09057).)

10.24*

Letter Agreement between WE and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)

19

Insider Trading Policies and Procedures

19.1

Corporate Securities Trading Policy

23

Consents of Experts and Counsel

23.1

Deloitte & Touche LLP – Milwaukee, WI, Consent of Independent Registered Public Accounting Firm for WE.

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 File

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)

ITEM 16. FORM 10-K SUMMARY

None.

2025 Form 10-K 109 Wisconsin Electric Power Company

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SCHEDULE II

WISCONSIN ELECTRIC POWER COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts (in millions)						Balance at Beginning of Period						Expense (1)						Deferral						Net Write-offs (2)						Balance at End of Period
December 31, 2025						$	46.9					$	66.0					$	6.3					$	(79.5)					$	39.7
December 31, 2024						44.5						32.8						46.3						(76.7)						46.9
December 31, 2023						49.7						23.8						45.7						(74.7)						44.5

(1)    Net of recoveries.

(2)    Represents amounts written off to the reserve, net of adjustments to regulatory assets.

2025 Form 10-K 110 Wisconsin Electric Power Company

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

						WISCONSIN ELECTRIC POWER COMPANY
			By			/s/ SCOTT J. LAUBER
Date:			February 20, 2026			Scott J. Lauber
						Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ SCOTT J. LAUBER						February 20, 2026
Scott J. Lauber, Chairman of the Board, Chief Executive Officer and Director --
Principal Executive Officer
/s/ XIA LIU						February 20, 2026
Xia Liu, Executive Vice President, Chief Financial Officer and Director --
Principal Financial Officer
/s/ WILLIAM J. GUC						February 20, 2026
William J. Guc, Vice President and Controller --
Principal Accounting Officer
/s/ MICHAEL W. HOOPER						February 20, 2026
Michael W. Hooper, Director
/s/ KYLE A. HOOPS						February 20, 2026
Kyle A. Hoops, Director
/s/ MARGARET C. KELSEY						February 20, 2026
Margaret C. Kelsey, Director

2025 Form 10-K 111 Wisconsin Electric Power Company

FAQ

How much revenue did Wisconsin Electric Power (WELPM) generate in 2025?

Wisconsin Electric Power reported total utility operating revenues of $4,493.6 million in 2025, up from $3,979.9 million in 2024. Electric utility revenues were $3,935.4 million, while Wisconsin natural gas utility revenues contributed $558.2 million for the year.

What is WELPM’s electric generation and power purchase mix for 2025?

In 2025, WELPM sourced 68.1% of its electric supply from company-owned or leased generation and 30.8% from power purchase contracts, with an additional 1.1% from purchased power in MISO. Owned renewables supplied 7.6% of total electric utility supply.

How many customers does Wisconsin Electric Power (WELPM) serve?

At December 31, 2025, WELPM served 1,184.7 thousand electric customers and 519.5 thousand natural gas customers. Electric customers included 1,061.1 thousand residential and 121.3 thousand small commercial and industrial accounts, reflecting steady multi-year customer growth across its Wisconsin territories.

What are WELPM’s carbon reduction achievements and targets?

WEC Energy Group’s fleet, including WELPM, has achieved a 53% reduction in carbon emissions from a 2005 baseline by the end of 2025. It aims for net carbon-neutral electric generation by 2050, expects to use coal only as backup by 2030, and eliminate coal by 2032.

What is Wisconsin Electric Power’s authorized return on equity (ROE)?

For 2025, WELPM’s regulated retail electric, natural gas, and steam operations under the PSCW had an authorized ROE of 9.80% with an average common equity component of 53.0%. For very large customers, proposed ROEs range from 10.48% to 10.98%, with a 57.0% equity ratio.

How is WELPM investing in renewables, storage, and natural gas generation?

WELPM owns 150 MW of solar and 83 MW of battery storage at Paris and 188 MW of solar at Darien, with 57 MW of storage expected. It has PSCW approval for 730 MW additional solar, 345 MW storage, and 1,228 MW of new natural gas-fired generation.

What regulatory mechanisms affect WELPM’s fuel and natural gas cost recovery?

WELPM’s Wisconsin electric rates embed fuel and purchased power costs and use fuel rules that defer variances beyond a ±2% tolerance for later recovery or refund. Its natural gas utility operates under a Gas Cost Recovery Mechanism allowing dollar-for-dollar recovery of prudently incurred gas costs.