WELPP 10-Q Quarterly Report Sept. 30, 2025 | Alphaminr
WISCONSIN ELECTRIC POWER CO
ALPHAMINR

WELPP 10-Q Quarter ended Sept. 30, 2025

Balance Sheet
Cash Flow
Income Statement
Debt
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wep-20250930
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒ No ☐



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ Accelerated filer ☐
Non-accelerated filer ☒ Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

Yes ☐ No ☒

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Common Stock, $10 Par Value,
33,289,327 shares outstanding at
September 30, 2025

All of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.

WISCONSIN ELECTRIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2025
TABLE OF CONTENTS
Page
Page

09/30/2025 Form 10-Q
i
Wisconsin Electric Power Company

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:
Affiliates
ATC American Transmission Company LLC
We Power W.E. Power, LLC
WEC Energy Group WEC Energy Group, Inc.
WEPCo Environmental Trust WEPCo Environmental Trust Finance I, LLC
WPS Wisconsin Public Service Corporation
Federal and State Regulatory Agencies
CBP United States Customs and Border Protection Agency
DOC United States Department of Commerce
EPA United States Environmental Protection Agency
IRS United States Internal Revenue Service
PSCW Public Service Commission of Wisconsin
SEC United States 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
ASC Accounting Standards Codification
ASU Accounting Standards Update
FASB Financial Accounting Standards Board
GAAP United States Generally Accepted Accounting Principles
OPEB Other Postretirement Employee Benefits
VIE Variable Interest Entity
Environmental Terms
BATW Bottom Ash Transport Water
BTA Best Technology Available
CASAC Clean Air Scientific Advisory Committee
CCR Coal Combustion Residuals
CO 2
Carbon Dioxide
CRL Combustion Residual Leachate
CWA Clean Water Act
ELG Steam Electric Effluent Limitation Guidelines
FGD Flue Gas Desulfurization
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
PM Particulate Matter
WPDES Wisconsin Pollutant Discharge Elimination System
Measurements
Bcf Billion Cubic Feet
Dth Dekatherm
lb/MMBtu Pound Per Million British Thermal Unit
MW Megawatt
MWh Megawatt-hours
µg/m3 Micrograms Per Cubic Meter
09/30/2025 Form 10-Q
ii
Wisconsin Electric Power Company

Other Terms and Abbreviations
AD Antidumping
AI Artificial Intelligence
AMI Advanced Metering Infrastructure
BESS Battery Energy Storage System
Chicago, IL-IN-WI Chicago, Illinois, Indiana, and Wisconsin
CODM Chief Operating Decision Maker
CT Combustion Turbine
CVD Countervailing Duty
D.C. Circuit Court of Appeals United States Court of Appeals for the District of Columbia Circuit
DRER Dedicated Renewable Energy Resource
ERGS Elm Road Generating Station
ETB Environmental Trust Bond
EV Electric Vehicle
Exchange Act Securities Exchange Act of 1934, as amended
FTR Financial Transmission Right
High Noon High Noon Solar Energy Center
IRA Inflation Reduction Act
ITC Investment Tax Credit
LDC Local Natural Gas Distribution Company
LNG Liquefied Natural Gas
MISO Midcontinent Independent System Operator, Inc.
NOPP Notice of Planned Participation
OBBBA One Big Beautiful Bill Act
OCPP Oak Creek Power Plant
PIPP Presque Isle Power Plant
PPA Power Purchase Agreement
PTC Production Tax Credit
RICE Reciprocating Internal Combustion Engine
RNG Renewable Natural Gas
ROE Return on Equity
RTC Renewable Thermal Credit
S&P Standard & Poor's
SIP State Implementation Plan
Supreme Court United States Supreme Court
Tax Legislation Tax Cuts and Jobs Act of 2017
UFLPA Uyghur Forced Labor Prevention Act
VAPP Valley Power Plant
VLC Very Large Customer
West Riverside West Riverside Energy Center
Weston Weston Generating Station

09/30/2025 Form 10-Q
iii
Wisconsin Electric Power Company

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations, including associated compliance costs, legal proceedings, 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 risk factors as set forth in our 2024 Annual Report on Form 10-K and this report, 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, including those caused by climate change, 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, 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, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, electrification initiatives and other efforts to reduce the use of natural gas, and tax laws, including those that affect our ability to use PTCs and ITCs, as well as changes in the interpretation and/or enforcement of any laws or regulations by regulatory agencies;

• Federal, state, and local legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in 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, including focus on environmental, social, and governance concerns;

• The risk of delays and shortages, and increased costs of equipment, materials, or other resources that are critical to our business operations and corporate strategy, as a result of 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;

09/30/2025 Form 10-Q
1
Wisconsin Electric Power Company

• 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, and lower than anticipated need for electricity by these customers;

• 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 implementation of WEC Energy Group's CO 2 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 financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;

• The risks associated with inflation and changing commodity prices, including natural gas and electricity;

• The availability and cost of sources of natural gas and other fossil fuels, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

• Any impacts on the global economy, including from sanctions, and impacts on supply chains and fuel prices, generally, from ongoing, expanding, or escalating regional or international conflicts, including those in Ukraine, Israel, and other parts of the Middle East;

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

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Wisconsin Electric Power Company

• 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;

• 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.

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Wisconsin Electric Power Company

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) Three Months Ended Nine Months Ended
September 30 September 30
(in millions) 2025 2024 2025 2024
Operating revenues $ 1,201.9 $ 1,079.3 $ 3,391.8 $ 3,020.1
Operating expenses
Cost of sales 401.2 353.9 1,127.1 986.0
Other operation and maintenance 271.2 241.6 773.1 720.6
Depreciation and amortization 160.4 145.5 467.6 427.1
Property and revenue taxes 29.7 17.0 90.2 77.1
Total operating expenses 862.5 758.0 2,458.0 2,210.8
Operating income 339.4 321.3 933.8 809.3
Other income, net 15.5 19.5 38.6 52.0
Interest expense 121.3 123.3 367.3 364.5
Other expense ( 105.8 ) ( 103.8 ) ( 328.7 ) ( 312.5 )
Income before income taxes 233.6 217.5 605.1 496.8
Income tax expense 36.2 47.8 92.5 107.2
Net income 197.4 169.7 512.6 389.6
Preferred stock dividend requirements 0.3 0.3 0.9 0.9
Net income attributed to common shareholder $ 197.1 $ 169.4 $ 511.7 $ 388.7

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

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Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in millions, except share and per share amounts)
September 30, 2025 December 31, 2024
Assets
Current assets
Cash and cash equivalents $ 3.0 $ 0.4
Accounts receivable and unbilled revenues, net of reserves of $ 31.7 and $ 46.9 , respectively
546.7 601.2
Accounts receivable from related parties 116.0 128.6
Materials, supplies, and inventories 337.8 354.8
Prepaid taxes 82.4 139.8
Other prepayments 17.3 24.9
Other 25.8 23.2
Current assets 1,129.0 1,272.9
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $ 6,268.2 and $ 5,952.3 , respectively
14,417.5 12,810.7
Regulatory assets (September 30, 2025 and December 31, 2024 include $ 69.6 and $ 76.5 , respectively, related to WEPCo Environmental Trust)
2,945.5 2,946.3
Pension and OPEB assets 83.0 79.2
Other 89.3 90.5
Long-term assets 17,535.3 15,926.7
Total assets $ 18,664.3 $ 17,199.6
Liabilities and Equity
Current liabilities
Short-term debt $ 37.0 $ 179.9
Current portion of long-term debt (September 30, 2025 and December 31, 2024 include $ 9.2 related to WEPCo Environmental Trust)
9.2 259.2
Current portion of finance lease obligations 109.5 99.3
Accounts payable 442.4 529.3
Accounts payable to related parties 196.7 206.1
Accrued payroll and benefits 56.8 50.4
Accrued interest 57.1 27.6
Other 106.5 106.6
Current liabilities 1,015.2 1,458.4
Long-term liabilities
Long-term debt (September 30, 2025 and December 31, 2024 include $ 72.0 and $ 76.4 , respectively, related to WEPCo Environmental Trust)
4,222.1 3,728.0
Finance lease obligations 2,734.1 2,742.9
Deferred income taxes 1,670.7 1,655.7
Regulatory liabilities 1,696.8 1,758.8
Other 460.9 348.6
Long-term liabilities 10,784.6 10,234.0
Commitments and contingencies (Note 19)
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 3,788.6 2,703.0
Retained earnings 2,712.6 2,440.9
Common shareholder's equity 6,834.1 5,476.8
Preferred stock 30.4 30.4
Total liabilities and equity $ 18,664.3 $ 17,199.6

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

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Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended
September 30
(in millions) 2025 2024
Operating activities
Net income $ 512.6 $ 389.6
Reconciliation to cash provided by operating activities
Depreciation and amortization 467.6 427.1
Deferred income taxes and ITCs, net 24.1 60.7
Change in –
Accounts receivable and unbilled revenues, net 44.2 52.1
Materials, supplies, and inventories 17.0 ( 3.2 )
Prepaid taxes 57.4 30.7
Other current assets 2.7 22.1
Accounts payable ( 72.2 ) ( 22.1 )
Accrued taxes 20.1 2.4
Accrued interest 29.5 31.3
Other current liabilities ( 19.5 ) ( 7.8 )
Other, net ( 88.9 ) 21.2
Net cash provided by operating activities 994.6 1,004.1
Investing activities
Capital expenditures ( 1,891.1 ) ( 988.0 )
Acquisition of West Riverside — ( 97.9 )
Reimbursement for ATC's transmission infrastructure upgrades 33.1 6.2
Other, net 1.8 ( 2.1 )
Net cash used in investing activities ( 1,856.2 ) ( 1,081.8 )
Financing activities
Change in short-term debt ( 142.9 ) ( 360.8 )
Issuance of long-term debt 499.6 947.4
Retirement of long-term debt ( 254.6 ) ( 4.5 )
Payments for finance lease obligations ( 73.9 ) ( 64.9 )
Equity contribution from parent 1,085.0 —
Payment of dividends to parent ( 240.0 ) ( 180.0 )
Other, net ( 6.0 ) ( 10.0 )
Net cash provided by financing activities 867.2 327.2
Net change in cash, cash equivalents, and restricted cash 5.6 249.5
Cash, cash equivalents, and restricted cash at beginning of period 2.5 7.5
Cash, cash equivalents, and restricted cash at end of period $ 8.1 $ 257.0

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

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Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)
Wisconsin Electric Power Company Common Shareholder's Equity
(in millions) Common Stock Additional Paid In Capital Retained Earnings Total Common Shareholder's Equity Preferred Stock Total Equity
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 — — 196.1 196.1 — 196.1
Payment of dividends to parent — — ( 60.0 ) ( 60.0 ) — ( 60.0 )
Equity contribution from parent — 300.0 — 300.0 — 300.0
Stock-based compensation and other — 0.5 — 0.5 — 0.5
Balance at March 31, 2025 $ 332.9 $ 3,003.5 $ 2,577.0 $ 5,913.4 $ 30.4 $ 5,943.8
Net income attributed to common shareholder — — 118.5 118.5 — 118.5
Payment of dividends to parent — — ( 60.0 ) ( 60.0 ) — ( 60.0 )
Equity contribution from parent — 410.0 — 410.0 — 410.0
Stock-based compensation and other — — 0.1 0.1 — 0.1
Balance at June 30, 2025 $ 332.9 $ 3,413.5 $ 2,635.6 $ 6,382.0 $ 30.4 $ 6,412.4
Net income attributed to common shareholder — — 197.1 197.1 — 197.1
Payment of dividends to parent — — ( 120.0 ) ( 120.0 ) — ( 120.0 )
Equity contribution from parent — 375.0 — 375.0 — 375.0
Stock-based compensation and other — 0.1 ( 0.1 ) — — —
Balance at September 30, 2025 $ 332.9 $ 3,788.6 $ 2,712.6 $ 6,834.1 $ 30.4 $ 6,864.5

Wisconsin Electric Power Company Common Shareholder's Equity
(in millions) Common Stock Additional Paid In Capital Retained Earnings Total Common Shareholder's Equity Preferred Stock Total Equity
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 — — 134.0 134.0 — 134.0
Payment of dividends to parent — — ( 60.0 ) ( 60.0 ) — ( 60.0 )
Stock-based compensation and other — 0.5 ( 0.1 ) 0.4 — 0.4
Balance at March 31, 2024 $ 332.9 $ 2,552.9 $ 2,241.7 $ 5,127.5 $ 30.4 $ 5,157.9
Net income attributed to common shareholder — — 85.3 85.3 — 85.3
Payment of dividends to parent — — ( 60.0 ) ( 60.0 ) — ( 60.0 )
Stock-based compensation and other — — 0.1 0.1 — 0.1
Balance at June 30, 2024 $ 332.9 $ 2,552.9 $ 2,267.1 $ 5,152.9 $ 30.4 $ 5,183.3
Net income attributed to common shareholder — — 169.4 169.4 — 169.4
Payment of dividends to parent — — ( 60.0 ) ( 60.0 ) — ( 60.0 )
Balance at September 30, 2024 $ 332.9 $ 2,552.9 $ 2,376.5 $ 5,262.3 $ 30.4 $ 5,292.7

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

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Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2025

NOTE 1— GENERAL INFORMATION

Wisconsin Electric Power Company serves approximately 1.2 million electric customers and 0.5 million natural gas customers.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary.

On our financial statements, we consolidate VIEs of which we are the primary beneficiary.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2024. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2025, are not necessarily indicative of expected results for 2025 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2— ACQUISITION

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

Acquisition of Electric Generation Facility in Wisconsin

In May 2024, we completed the acquisition of 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. Prior to the acquisition, WPS received approval to transfer its ownership interest rights to us. Including this acquisition, we own 200 MWs, or 27.5 %, of West Riverside at a total cost of $ 193.2 million.

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Wisconsin Electric Power Company

NOTE 3— OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2024 Annual Report on Form 10-K.

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.
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Wisconsin Electric Power Company
Electric utility $ 1,146.7 $ 1,028.6 $ 3,003.3 $ 2,706.2
Natural gas utility 53.2 48.2 378.8 302.6
Total revenues from contracts with customers 1,199.9 1,076.8 3,382.1 3,008.8
Other operating revenues 2.0 2.5 9.7 11.3
Total operating revenues $ 1,201.9 $ 1,079.3 $ 3,391.8 $ 3,020.1

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class:
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Residential $ 501.3 $ 454.7 $ 1,285.6 $ 1,162.6
Small commercial and industrial 357.8 331.2 971.0 900.9
Large commercial and industrial 202.3 186.8 507.0 466.2
Other 5.1 4.9 15.7 15.4
Total retail revenues 1,066.5 977.6 2,779.3 2,545.1
Wholesale 13.4 11.1 38.4 35.8
Resale 61.1 35.8 159.6 104.6
Steam 2.9 2.5 20.6 17.3
Other utility revenues 2.8 1.6 5.4 3.4
Total electric utility operating revenues $ 1,146.7 $ 1,028.6 $ 3,003.3 $ 2,706.2

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Residential $ 26.6 $ 24.4 $ 248.8 $ 198.3
Commercial and industrial 10.7 7.9 111.5 82.9
Total retail revenues 37.3 32.3 360.3 281.2
Transportation 4.5 4.8 17.6 17.5
Other utility revenues (1)
11.4 11.1 0.9 3.9
Total natural gas utility operating revenues $ 53.2 $ 48.2 $ 378.8 $ 302.6

(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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Wisconsin Electric Power Company

Other Operating Revenues

Other operating revenues consist primarily of the following:
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Late payment charges $ 2.3 $ 2.4 $ 8.5 $ 8.8
Rental revenues 0.3 0.2 2.1 2.3
Alternative revenues (1)
( 0.6 ) ( 0.1 ) ( 0.9 ) 0.2
Total other operating revenues $ 2.0 $ 2.5 $ 9.7 $ 11.3

(1) 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, in our 2024 Annual Report on Form 10-K.

NOTE 4— CREDIT LOSSES

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are 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 September 30, 2025 and December 31, 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 to mitigate credit risk.

We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses.
(in millions) September 30, 2025 December 31, 2024
Accounts receivable and unbilled revenues $ 578.4 $ 648.1
Allowance for credit losses 31.7 46.9
Accounts receivable and unbilled revenues, net (1)
$ 546.7 $ 601.2
Total accounts receivable, net – past due greater than 90 days (1)
$ 29.0 $ 38.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)
94.7 % 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 September 30, 2025, $ 346.7 million, or 63.4 %, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

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Wisconsin Electric Power Company

A rollforward of the allowance for credit losses is included below:
Three Months Ended September 30
(in millions) 2025 2024
Balance at July 1 $ 32.9 $ 42.0
Provision for credit losses 17.5 8.4
Provision for credit losses deferred for future recovery or refund 1.8 7.9
Write-offs charged against the allowance ( 27.5 ) ( 23.7 )
Recoveries of amounts previously written off 7.0 6.2
Balance at September 30
$ 31.7 $ 40.8

Nine Months Ended September 30
(in millions) 2025 2024
Balance at January 1 $ 46.9 $ 44.5
Provision for credit losses 47.2 23.6
Provision for credit losses deferred for future recovery or refund ( 6.2 ) 28.6
Write-offs charged against the allowance ( 79.5 ) ( 75.2 )
Recoveries of amounts previously written off 23.3 19.3
Balance at September 30
$ 31.7 $ 40.8

There was a $ 15.2 million decrease in the allowance for credit losses at September 30, 2025, compared to January 1, 2025. The decrease was 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.

There was a $ 3.7 million decrease in the allowance for credit losses at September 30, 2024, compared to January 1, 2024, largely driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. The winter moratorium begins on November 1 and ends on April 15. Also contributing to the decrease in the allowance for credit losses, were lower required reserve percentages as a result of an improvement in loss rates. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions in the first half of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

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Wisconsin Electric Power Company

NOTE 5— REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2025 and December 31, 2024. For more information on our regulatory assets and liabilities, see Note 7, Regulatory Assets and Liabilities, in our 2024 Annual Report on Form 10-K.
(in millions) September 30, 2025 December 31, 2024
Regulatory assets
We Power finance leases $ 1,154.8 $ 1,139.1
Plant retirement related items 643.8 655.1
Income tax related items 403.9 364.6
Pension and OPEB costs 313.7 343.1
Uncollectible expense 102.2 108.4
System support resource 95.2 102.9
Securitization 69.6 76.5
Asset retirement obligations 58.3 52.8
Other finance and operating leases (1)
21.7 15.1
Bluewater Natural Gas Holding, LLC 15.8 21.1
Other, net 66.5 67.6
Total regulatory assets $ 2,945.5 $ 2,946.3

(1) 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 this lease expense and the unadjusted lease expense calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842.
(in millions) September 30, 2025 December 31, 2024
Regulatory liabilities
Removal costs $ 848.2 $ 809.2
Income tax related items 660.8 653.9
Pension and OPEB benefits 110.9 118.5
Revenue requirements of renewable generation facilities 18.9 37.9
Energy costs refundable through rate adjustments 12.3 70.7
Electric transmission costs — 19.7
Other, net 49.2 52.9
Total regulatory liabilities $ 1,700.3 $ 1,762.8
Balance sheet presentation
Other current liabilities $ 3.5 $ 4.0
Regulatory liabilities 1,696.8 1,758.8
Total regulatory liabilities $ 1,700.3 $ 1,762.8

NOTE 6— PROPERTY, PLANT, AND EQUIPMENT

Plant to be Retired

Oak Creek Power Plant Units 7-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien Solar Park, 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 $ 630.4 million at September 30, 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.

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Wisconsin Electric Power Company

NOTE 7— COMMON EQUITY

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 other subsidiaries. See Note 11, Common Equity, in our 2024 Annual Report on Form 10-K for additional information on these and other restrictions.

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

NOTE 8— SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:
(in millions, except percentages) September 30, 2025 December 31, 2024
Commercial paper
Amount outstanding $ 37.0 $ 179.9
Weighted-average interest rate on amounts outstanding 4.20 % 4.63 %

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2025 was $ 156.3 million with a weighted-average interest rate during the period of 4.53 %.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:
(in millions) Maturity September 30, 2025
Revolving credit facility (1)
August 2030 $ 800.0
Less:
Letters of credit issued inside credit facility 1.0
Commercial paper outstanding 37.0
Available capacity under existing credit facility $ 762.0

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

NOTE 9— LONG-TERM DEBT

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.

NOTE 10— LEASES

In June 2025, we, along with WPS, partnered with an unaffiliated utility to acquire and construct High Noon, a utility-scale solar-powered electric generating facility located in Columbia County, Wisconsin. Commercial operation of the project is targeted for 2027. Related to our investment in High Noon, we, WPS, and our unaffiliated utility partner, entered into several land leases that commenced in the second quarter of 2025. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25 -year extension. We expect the optional extension to be exercised, and, as a result, these land leases are being amortized over the extended term of the leases. Once High Noon achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased. We expect to recover the lease payments through rates.

Our total obligation under the land-related finance leases for High Noon was $ 54.9 million at September 30, 2025, and was included in finance lease obligations on our balance sheet. Our finance lease right of use asset related to High Noon was $ 55.2 million as of
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Wisconsin Electric Power Company

September 30, 2025, and was included in property, plant, and equipment on our balance sheet. Our weighted-average discount rate for the High Noon finance leases was 6.45 %. We used an estimate of the fully collateralized incremental borrowing rate based upon information available for similarly rated companies in determining the present value of lease payments.

Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for High Noon as of September 30, 2025, were as follows:
(in millions)
Three Months Ended December 31, 2025 $ 0.7
2026 1.2
2027 1.5
2028 3.0
2029 3.1
2030 3.2
Thereafter 242.3
Total minimum lease payments 255.0
Less: Interest ( 200.1 )
Present value of minimum lease payments 54.9
Less: Short-term lease liabilities —
Long-term lease liabilities $ 54.9

NOTE 11— MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:
(in millions) September 30, 2025 December 31, 2024
Materials and supplies $ 231.9 $ 252.1
Fossil fuel 53.5 60.0
Natural gas in storage 52.4 42.7
Total $ 337.8 $ 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.

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Wisconsin Electric Power Company

NOTE 12— INCOME TAXES

The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
Three Months Ended September 30, 2025 Three Months Ended September 30, 2024
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $ 49.0 21.0 % $ 45.6 21.0 %
State income taxes net of federal tax benefit 13.4 5.7 % 13.2 6.1 %
PTCs, net ( 10.8 ) ( 4.6 ) % ( 6.1 ) ( 2.8 ) %
Federal excess deferred tax amortization ( 6.5 ) ( 2.8 ) % ( 6.9 ) ( 3.2 ) %
AFUDC-Equity ( 5.8 ) ( 2.5 ) % ( 2.9 ) ( 1.3 ) %
Tax repairs ( 4.8 ) ( 2.1 ) % 1.4 0.6 %
Domestic production activities deferral 1.8 0.8 % 2.1 1.0 %
Other, net ( 0.1 ) — % 1.4 0.6 %
Total income tax expense $ 36.2 15.5 % $ 47.8 22.0 %
Nine Months Ended September 30, 2025 Nine Months Ended September 30, 2024
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate
Statutory federal income tax $ 126.9 21.0 % $ 104.1 21.0 %
State income taxes net of federal tax benefit 34.8 5.8 % 29.7 6.0 %
PTCs, net ( 31.1 ) ( 5.1 ) % ( 14.3 ) ( 2.9 ) %
Federal excess deferred tax amortization ( 17.7 ) ( 2.9 ) % ( 16.1 ) ( 3.2 ) %
AFUDC-Equity ( 13.7 ) ( 2.3 ) % ( 8.0 ) ( 1.6 ) %
Tax repairs ( 13.2 ) ( 2.2 ) % 3.2 0.6 %
Domestic production activities deferral 5.1 0.8 % 4.9 1.0 %
Other, net 1.4 0.2 % 3.7 0.7 %
Total income tax expense $ 92.5 15.3 % $ 107.2 21.6 %

The effective tax rates for the three and nine months ended September 30, 2025, differ from the United States statutory federal income tax rate of 21 %, primarily due to PTCs, the impact of the deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, the impact of the income tax benefits associated with AFUDC-Equity, driven by continued capital investment, and the flow through of tax repairs in connection with our rate order approved by the PSCW, effective January 1, 2025. These items were partially offset by state income taxes.

The effective tax rates for the three and nine months ended September 30, 2024, do not materially differ from the United States statutory federal income tax rate of 21 %. This is primarily due to the impact of the deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs, offset by state income taxes.

The Tax Legislation required us to remeasure the deferred income taxes at our utility segment, and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization lines above).

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 in October 2024, April 2025, and September 2025, to sell the majority of the PTCs we generate in 2025 and 2026 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. In September 2025, WEC Energy Group entered into an agreement to sell substantially all of the ITCs we generate in 2025 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.

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Wisconsin Electric Power Company

NOTE 13— FAIR VALUE MEASUREMENTS

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

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.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
September 30, 2025
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets
Natural gas contracts $ 1.2 $ 1.6 $ — $ 2.8
FTRs — — 4.9 4.9
Total derivative assets $ 1.2 $ 1.6 $ 4.9 $ 7.7
Derivative liabilities
Natural gas contracts $ 4.5 $ 1.0 $ — $ 5.5

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

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Wisconsin Electric Power Company

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 and Operating Reserves Markets.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Balance at the beginning of the period $ 9.9 $ 9.7 $ 2.9 $ 2.5
Purchases — — 12.1 12.1
Settlements ( 5.0 ) ( 5.2 ) ( 10.1 ) ( 10.1 )
Balance at the end of the period $ 4.9 $ 4.5 $ 4.9 $ 4.5

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that were not recorded at fair value:
September 30, 2025 December 31, 2024
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $ 30.4 $ 22.2 $ 30.4 $ 21.2
Long-term debt, including current portion 4,231.3 4,164.9 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 14— 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 an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities are included in the other current and other long-term line items on our balance sheets. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below are designated as hedging instruments.
September 30, 2025 December 31, 2024
(in millions) Derivative
Assets 		Derivative
Liabilities 		Derivative
Assets 		Derivative
Liabilities
Current
Natural gas contracts $ 2.7 $ 5.3 $ 10.0 $ 1.1
FTRs 4.9 — 2.9 —
Total current 7.6 5.3 12.9 1.1
Long-term
Natural gas contracts 0.1 0.2 0.5 —
Total $ 7.7 $ 5.5 $ 13.4 $ 1.1

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Wisconsin Electric Power Company

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 estimated notional sales volumes and realized gains and losses were as follows:
Three Months Ended September 30, 2025 Three Months Ended September 30, 2024
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts
14.2 Dth
$ ( 5.7 )
14.5 Dth
$ ( 7.7 )
FTRs
4.5 MWh
3.0
5.1 MWh
2.6
Total $ ( 2.7 ) $ ( 5.1 )
Nine Months Ended September 30, 2025 Nine Months Ended September 30, 2024
(in millions) Volumes Gains Volumes Gains (Losses)
Natural gas contracts
51.5 Dth
$ 0.4
53.7 Dth
$ ( 34.1 )
FTRs
13.8 MWh
5.3
15.1 MWh
5.9
Total $ 5.7 $ ( 28.2 )

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2025 and December 31, 2024, we had posted cash collateral of $ 12.7 million and $ 4.9 million, respectively. These amounts were recorded on our balance sheets in other current assets. At December 31, 2024, we had also received cash collateral of $ 2.8 million. This amount was recorded on our balance sheet in other current liabilities.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
September 30, 2025 December 31, 2024
(in millions) Derivative
Assets 		Derivative
Liabilities 		Derivative
Assets 		Derivative
Liabilities
Gross amount recognized on the balance sheet $ 7.7 $ 5.5 $ 13.4 $ 1.1
Gross amount not offset on the balance sheet ( 1.5 ) ( 4.8 )
(1)
( 3.6 )
(2)
( 0.8 )
Net amount $ 6.2 $ 0.7 $ 9.8 $ 0.3

(1) Includes cash collateral posted of $ 3.3 million.

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

NOTE 15— GUARANTEES

As of September 30, 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.

NOTE 16— EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans.
Pension Benefits
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Service cost $ 2.5 $ 2.6 $ 7.5 $ 7.8
Interest cost 11.4 11.1 34.2 33.4
Expected return on plan assets ( 14.6 ) ( 15.3 ) ( 44.2 ) ( 46.1 )
Amortization of prior service credit ( 0.1 ) ( 0.1 ) ( 0.1 ) ( 0.1 )
Amortization of net actuarial loss 4.0 4.6 12.0 13.6
Net periodic benefit cost $ 3.2 $ 2.9 $ 9.4 $ 8.6

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Wisconsin Electric Power Company

OPEB Benefits
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Service cost $ 0.8 $ 0.8 $ 2.6 $ 2.4
Interest cost 2.3 2.0 7.0 6.1
Expected return on plan assets ( 2.7 ) ( 2.7 ) ( 8.1 ) ( 8.2 )
Amortization of prior service credit — — ( 0.1 ) ( 0.1 )
Amortization of net actuarial gain ( 0.9 ) ( 1.5 ) ( 2.9 ) ( 4.3 )
Net periodic benefit credit $ ( 0.5 ) $ ( 1.4 ) $ ( 1.5 ) $ ( 4.1 )

During the nine months ended September 30, 2025, we made contributions and payments of $ 2.3 million related to our pension plans and $ 0.1 million related to our OPEB plans. During the remainder of 2025, we expect to make contributions and payments of $ 0.9 million related to our pension plans and $ 0.2 million related to our OPEB plans, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As of September 30, 2025 and December 31, 2024, our balance sheets included regulatory assets of $ 0.4 million and $ 9.9 million, respectively, for pension costs and $ 11.3 million and $ 17.8 million, respectively, for OPEB costs. In accordance with our December 2024 PSCW rate order, we began amortizing these regulatory assets in 2025. We continue to utilize escrow accounting for our current pension and OPEB costs. The above tables do not reflect any adjustments for the creation or amortization of these regulatory assets.

NOTE 17— 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 and natural gas operations. See Note 3, 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, in our 2024 Annual Report on Form 10-K.

At September 30, 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.

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 three and nine months ended September 30, 2025 and 2024.

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Wisconsin Electric Power Company

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 three and nine months ended September 30, 2025 and 2024.
Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2025 2024 2025 2024
Fuel and purchased power $ 378.4 $ 336.6 $ 941.0 $ 845.2
Cost of natural gas sold 22.8 17.3 186.1 140.8

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.

NOTE 18— 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, 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.

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Wisconsin Electric Power Company

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheets:
(in millions) September 30, 2025 December 31, 2024
Assets
Other current assets (restricted cash) $ 4.5 $ 1.5
Regulatory assets 69.6 76.5
Other long-term assets (restricted cash) 0.6 0.6
Liabilities
Current portion of long-term debt 9.2 9.2
Accrued interest 0.4 0.1
Long-term debt 72.0 76.4

NOTE 19— 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. Our minimum future commitments related to these purchase obligations as of September 30, 2025, were approximately $ 6.3 billion.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine PM2.5, ozone, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Federal Deregulatory Actions

In March 2025, the EPA announced a large-scale deregulatory effort. The EPA announced that, in total, it expects to take 31 deregulatory actions that will likely take multiple years to complete. Of these 31 deregulatory actions, the actions that would apply to us include those 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 any such actions are likely to be subject to legal challenges. We continue to monitor and evaluate potential risks and benefits to us, depending on the actions ultimately taken.

In July 2025, the EPA proposed to rescind a 2009 declaration that determined that CO 2 and other GHGs endanger public health and welfare. The "endangerment finding" is the legal underpinning of a host of climate regulations under the Clean Air Act. The proposal is subject to a review process and public comment and will likely be litigated. We are monitoring the status of the proposal and assessing the potential impact on our business and operations.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

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

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Wisconsin Electric Power Company

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

In February 2024, the Supreme Court heard oral arguments regarding stay applications related to the EPA's Good Neighbor Rule. In June 2024, the Supreme Court granted a stay of the Good Neighbor Rule pending disposition of the applicants' petitions for review at the D.C. Circuit Court of Appeals. After a series of procedural motions and orders, in March 2025, the D.C. Circuit Court of Appeals issued an order removing the case from its active docket and holding the case in abeyance, pending quarterly updates from the parties beginning in July 2025. We will continue to monitor this case as arguments at the D.C. Circuit Court of Appeals move forward.

In November 2024, the EPA issued a Good Neighbor Interim Final Rule that administratively stayed the effectiveness of the Good Neighbor Rule in all states to which it originally applies and ensured implementation of good neighbor obligations previously established to address the 2008 ozone NAAQS while the process works through the courts. We believe we are well positioned to comply with the rule's requirements. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. In May 2024, the EPA published a final rule in the Federal Register (the "2024 Final Action") lowering the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. We believe we are well positioned to comply with the rule's requirements.

In June 2025, the EPA announced a proposed rule to repeal the 2024 Final Action on the basis that it imposed large compliance costs and raised technical feasibility concerns. Currently, the EPA is reviewing comments it received on the proposed rule.

National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that also supported the reconsideration; however, in August 2023, the EPA announced that it was instead restarting its ozone standard evaluation. The EPA released the first two volumes of its Integrated Review Plan in December 2024. This new review is anticipated to take 3 to 5 years to complete.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023.

The EPA's initial 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 7, 2022.

The most recent attainment evaluation date was in August 2024. The moderate attainment deadline was not met, so in December 2024 the EPA published a final determination reclassifying the nonattainment areas in Wisconsin to a "serious" classification effective January 16, 2025. The Wisconsin Department of Justice filed a petition in February 2025 for review of the reclassification to "serious."

In September 2025, the United States Court of Appeals for the Seventh Circuit granted the State of Wisconsin's motion to stay the reclassification until further notice. This means that Southeast Wisconsin has returned to "moderate" status while the underlying lawsuit proceeds.

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Wisconsin Electric Power Company

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 additional emission reduction credits.

Particulate Matter

All counties within our service territory are in attainment with current 2012 standards for fine PM2.5. Under the former presidential administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m 3 , while retaining the 24-hour standard of 35 µg/m 3 . In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m 3 . The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until February 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. 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 this new standard to have a material impact on our units. In March 2025, the EPA announced plans to reconsider the 2024 PM2.5 NAAQS. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Climate Change

Pursuant to the final GHG Power Plant Rule, there are no applicable standards for coal plants until the end of 2031. Thereafter, the applicable standard is dependent upon the unit's retirement date. Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029. For new combined cycle natural gas plants above a 40 % capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031. For new simple-cycle natural gas-fired CTs, there are no applicable limits as long as the capacity factor is less than 20 %. Our Weston RICE units are not affected under the rule because the rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the GHG Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals.

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 phases, focusing on CO 2 emissions, as well as NOx and hazardous air pollutants (formaldehyde) emissions. In November 2024, the EPA released the first proposed rule of the three rule "packages" to address NOx emissions from existing CTs. The proposed rule for turbines that operate at a greater than 20 % capacity factor will require more stringent NOx limits and control requirements for new, modified, or reconstructed turbines. For turbines that operate at a capacity of 20 % or lower, less restrictive standards and the use of combustion controls would apply. We currently believe our existing combined-cycle natural gas facilities would be positioned to comply with the proposed rule if finalized in its current form. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

In June 2025, the EPA announced a proposed rule that contains co-proposals for addressing the GHG Power Plant Rule. The lead proposal would exclude the power sector from the GHG regulation on the grounds that it does not "significantly" contribute to dangerous air pollution. A secondary proposal would eliminate the carbon capture and sequestration/storage and other requirements from the GHG Power Plant Rule. By issuing co-proposals, the EPA is providing public notice of two very different potential regulatory paths. Based on the comments received, the EPA may choose to finalize either approach.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, which includes updates to the global warming potentials to determine CO 2 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 final 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, the EPA released a proposal in September 2025 to amend the GHG Reporting Program that would 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 subsidiaries until 2034. We continue to monitor the status of this deregulatory action.

WEC Energy Group's capital plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and reliable, efficient natural gas-fired generation. We have already retired nearly 2,100 MWs of fossil-fueled generation
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since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of 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 6, Property, Plant, and Equipment, for more information related to planned power plant retirements. In the third quarter of 2025, WEC Energy Group made a decision to reconsider its near-term CO 2 emission reduction goals due to a combination of factors, including tightened energy supply requirements in the Midwest power market and the need to serve customers with safe, reliable, and affordable energy. However, WEC Energy Group's long-term goal to achieve net carbon neutral electric generation by 2050 remains intact. 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. 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. In light of WEC Energy Group's progress, significant uncertainty surrounding the market for RTCs, and WEC Energy Group's desire to focus on long-term GHG emissions-reduction across the enterprise, in the third quarter of 2025, WEC Energy Group made a decision to reassess its previous, standalone goal related to methane emissions from natural gas distribution.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

Revisions to an EPA rule authorized under Section 316(b) of the CWA became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.

Effective in June 2020, the requirements of Section 316(b) were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for our facilities.

We have received interim BTA determinations for all generation facilities where Section 316(b) is applicable. With respect to OCPP Units 7 and 8, we believe that in accordance with the requirements in the CWA, the WDNR will determine that existing technology (wet cooling towers) installed at the units represents BTA for minimizing adverse environmental impacts when the WPDES permit for those units is reissued, which is expected in 2026.

Steam Electric Effluent Limitation Guidelines

The EPA's 2015 final ELG rule, which took effect in January 2016 (2015 ELG rule), was modified in 2020 (2020 ELG rule), and again in May 2024 with the publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect us relate to wastewater discharge limits for BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP and ERGS to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Compliance costs associated with the 2015 and 2020 ELG rules required $ 97 million in capital investment.

The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date. The Supplemental ELG Rule also kept one existing and created one new "permanent cessation of coal" subcategory. Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively. For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025. All of our coal-fueled units fully meet the 2020 ELG rule requirements. Based on current electrical generation resource planning, we plan to file a NOPP by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for the ERGS coal-fired facility. A NOPP also may be filed for the OCPP, Port Washington Generating Station, and VAPP facilities because this ELG rule option will allow the company to qualify for more reasonable requirements to address the CRL provisions at our landfills that served these former coal-fired facilities.
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The final Supplemental ELG Rule allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2028 or 2034, as allowed by either the 2015 or the 2020 ELG Rule, respectively, if needed for reliability concerns (i.e., energy emergencies and reliability must run agreements) as determined by the United States Department of Energy, a public utility commission, or independent system operator.

In November 2024, Edison Electric Institute, on behalf of its members, submitted a petition for reconsideration to the EPA regarding the CRL provisions in the Supplemental ELG Rule in an effort to codify the rule interpretations articulated by the EPA staff during informational conference calls on this issue. We are still awaiting either a rule revision or clear written guidance from the EPA about the Supplemental ELG Rule CRL provisions to determine the applicability and potential compliance costs for inactive/closed landfills.

Numerous parties have challenged the 2024 Supplemental ELG Rule through litigation in SWEPCO v. U.S. EPA pending in the United States Court of Appeals for the Eighth Circuit. The outcome of this case may affect our compliance plans. This case has been held in abeyance since February 2025. In August 2025, the court granted the EPA's motion to continue to hold this case in abeyance and required the EPA to file regular periodic reports. The Supplemental ELG Rule remains in effect during the pendency of the legal challenge.

In September 2025, the EPA announced it intends to issue a proposed rule and a companion direct final rule to modify certain 2024 ELG Rule provisions. The proposed rule would (1) extend compliance deadlines for the zero-discharge requirements in the 2024 ELG Rule, (2) update provisions to allow permitting authorities site-specific flexibility to extend deadlines due to unexpected demand, and (3) solicit data from the electric utility industry about the viability of compliance pathways to evaluate economic achievability and energy reliability. The companion direct final rule would extend the date from December 31, 2025 to December 31, 2031 for existing coal-fired steam electric power plants to submit a NOPP for the permanent cessation of coal.

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 also working with the state of Wisconsin in our investigation and remediation planning. 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:
(in millions) September 30, 2025 December 31, 2024
Regulatory assets $ 10.6 $ 10.8
Reserves for future environmental remediation (1)
10.5 10.6

(1) Recorded within other long-term liabilities on our balance sheets.

Coal Combustion Residuals Rule

The EPA finalized a rule for CCR in April 2024 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site. The rule will regulate previously exempt closed landfills.

The final rule, which became effective in November 2024, will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. The D.C. Circuit Court of Appeals granted the EPA's request to extend its ongoing abeyance until December 15, 2025. In July 2025, the EPA issued a proposed rule update to extend certain CCR compliance deadlines. A final rulemaking on this issue is anticipated by the end of 2025 with additional proposed changes expected in 2026. We expect the cost of
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the additional remediation would be recovered through future rates. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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 20— SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides additional information regarding our statements of cash flows:
Nine Months Ended September 30
(in millions) 2025 2024
Cash paid for interest, net of amount capitalized $ 334.2 $ 330.3
Cash paid for income taxes, net
26.3
(1)
48.6
(2)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs 154.4 96.6
Liabilities accrued for software licensing agreements 8.8 —
Receivable for the transfer of assets to Wisconsin Gas LLC 2.7 —

(1) Cash paid for income taxes was net of $ 29.1 million of cash received related to 2025 and 2024 PTCs that were sold to third parties.

(2) Cash paid for income taxes was net of $ 14.9 million of cash received related to 2024 and 2023 PTCs that were sold to third parties.

Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:
(in millions) September 30, 2025 December 31, 2024
Cash and cash equivalents $ 3.0 $ 0.4
Restricted cash included in other current assets 4.5 1.5
Restricted cash included in other long-term assets 0.6 0.6
Cash, cash equivalents, and restricted cash $ 8.1 $ 2.5

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 18, Variable Interest Entities, for more information.

NOTE 21— 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 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.

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
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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, 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 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.

NOTE 22— NEW ACCOUNTING PRONOUNCEMENTS

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.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our 2024 Annual Report on Form 10-K.

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 17, Segment Information, for more information on our reportable business segments.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our customers and WEC Energy Group's shareholders by focusing on the fundamentals of our business: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. WEC Energy Group's capital plan provides a roadmap to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow 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.

Creating a Sustainable Future

WEC Energy Group's capital plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and reliable, efficient natural gas-fired generation at its electric utilities, including us. The retirements are intended to address compliance with the EPA Clean Air rules as well as contribute to meeting WEC Energy Group's and our goals to reduce CO 2 emissions from electric generation. When taken together, the retirements and new investments in renewables and reliable, efficient natural gas generation should better balance supply with demand, while helping to address compliance and maintaining reliable, affordable energy for our customers.

In the third quarter of 2025, WEC Energy Group made a decision to reconsider its near-term CO 2 emission reduction goals due to a combination of factors, including tightened energy supply requirements in the Midwest power market and the need to serve customers with safe, reliable, and affordable energy. However, WEC Energy Group's long-term goal to achieve net carbon neutral electric generation by 2050 remains intact. 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. 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 has already 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 6, Property, Plant, and Equipment, for more information related to the planned retirement of OCPP Units 7 and 8.

In addition to retiring these older, fossil-fueled plants, WEC Energy Group expects to invest approximately $11.6 billion from 2026 to 2030 in regulated renewable energy in Wisconsin. WEC Energy Group's plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following investments made by either us or WPS based on specific customer needs:

• 3,700 MWs of utility-scale solar;
• 1,780 MWs of battery storage; and
• 555 MWs of wind.
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WEC Energy Group also plans on investing in a combination of clean, 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.

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

In December 2018, we received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MWs of solar generation to our portfolio, allowing non-profit and government entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property. Under this program, we have energized 30 Solar Now projects, totaling more than 30 MWs. The second program, the DRER pilot, is designed to allow large commercial and industrial customers to access renewable resources that we would operate. The DRER pilot is intended to help these larger customers meet their sustainability and renewable energy goals, and could add up to 35 MWs of renewables to our portfolio. We have signed up one customer under this program for 4 MWs of generation capacity. In July 2023, the PSCW approved the Renewable Pathway Pilot, the third renewable energy program. This program allows our commercial and industrial customers to subscribe to a portion of a utility-scale Wisconsin-based renewable energy generating facility for up to 125 MWs. Under this program, we have 14 active contracts for a total of 47 MWs of generation capacity.

In August 2021, the PSCW approved pilot programs for us to install and maintain EV charging equipment for customers at their homes or businesses. We proposed modifications to these pilot programs, which were approved by the PSCW and implemented on January 1, 2025. The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment. In October 2021, subject to the receipt of any necessary regulatory approvals, WEC Energy Group pledged to expand the EV charging network within its utilities' electric service territories. In doing so, WEC Energy Group joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition WEC Energy Group joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

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. In 2022, we received approval from the PSCW for an RNG pilot. The RNG supplied is expected to directly replace higher-emission methane from natural gas that would have entered our pipes. In light of WEC Energy Group's progress, significant uncertainty surrounding the market for RTCs, and WEC Energy Group's desire to focus on long-term GHG emissions-reduction across the enterprise, in the third quarter of 2025, WEC Energy Group made a decision to reassess its previous, standalone goal related to methane emissions from natural gas distribution.

In December 2023, WEC Energy Group started a pilot program with the Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S. electric grid at our VAPP. The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today. WEC Energy Group expects the pilot activities to continue into 2026.

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 reliability 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.

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• The WEC Energy Group capital plan includes $2.2 billion of investments from 2026 to 2030 in battery energy storage systems, 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 system hardening.

WEC Energy Group expects to spend $4.7 billion from 2026 to 2030 on reliability related to electric distribution projects at its regulated utilities, which includes us, 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 AMI program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

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. 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 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, Acquisition, for more information on our planned and recently completed acquisitions.

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.

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

THREE MONTHS ENDED SEPTEMBER 30, 2025

Earnings

Our earnings for the third quarter of 2025 were $197.1 million, compared with $169.4 million for the same quarter in 2024. See below for information on the $27.7 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

The following table compares our utility segment's contribution to net income attributed to common shareholder for the third quarter of 2025, with the same quarter in 2024, including favorable or better, "B", and unfavorable or worse, "W", variances.
Three Months Ended September 30
(in millions) 2025 2024 B (W)
Operating revenues $ 1,201.9 $ 1,079.3 $ 122.6
Operating expenses
Cost of sales (1)
401.2 353.9 (47.3)
Other operation and maintenance 271.2 241.6 (29.6)
Depreciation and amortization 160.4 145.5 (14.9)
Property and revenue taxes 29.7 17.0 (12.7)
Operating income 339.4 321.3 18.1
Other income, net 15.5 19.5 (4.0)
Interest expense 121.3 123.3 2.0
Income before income taxes 233.6 217.5 16.1
Income tax expense 36.2 47.8 11.6
Preferred stock dividend requirements 0.3 0.3 —
Net income attributed to common shareholder $ 197.1 $ 169.4 $ 27.7

(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:
Three Months Ended September 30
(in millions) 2025 2024 B (W)
Operation and maintenance not included in line items below $ 111.0 $ 95.9 $ (15.1)
Transmission (1)
94.5 89.4 (5.1)
Regulatory amortizations and other pass through expenses (2)
34.6 24.0 (10.6)
We Power (3)
31.9 32.5 0.6
Earnings sharing mechanism (0.8) (0.2) 0.6
Total other operation and maintenance $ 271.2 $ 241.6 $ (29.6)

(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 the third quarter of 2025 and 2024, $103.6 million and $96.5 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 the third quarter of 2025 and 2024, $29.0 million and $27.8 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.

09/30/2025 Form 10-Q
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Wisconsin Electric Power Company

The following tables provide information on delivered sales volumes by customer class and weather statistics:
Three Months Ended September 30
MWh (in thousands)
Electric Sales Volumes 2025 2024 B (W)
Customer Class
Residential 2,414.4 2,363.1 51.3
Small commercial and industrial 2,404.2 2,357.4 46.8
Large commercial and industrial 1,799.7 1,763.5 36.2
Other 20.6 21.8 (1.2)
Total retail 6,638.9 6,505.8 133.1
Wholesale 160.4 143.0 17.4
Resale 1,344.4 1,315.8 28.6
Total sales in MWh 8,143.7 7,964.6 179.1

Three Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes 2025 2024 B (W)
Customer Class
Residential 20.8 20.7 0.1
Commercial and industrial 15.9 14.6 1.3
Total retail 36.7 35.3 1.4
Transportation 49.2 48.3 0.9
Total sales in therms 85.9 83.6 2.3

Three Months Ended September 30
Degree Days
Weather (1)
2025 2024 B (W)
Heating (88 Normal)
68 28 142.9 %
Cooling (525 Normal)
574 600 (4.3) %

(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.

09/30/2025 Form 10-Q
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Wisconsin Electric Power Company

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).
Three Months Ended September 30
(in millions) 2025 2024 B (W)
Electric revenues $ 1,148.5 $ 1,030.8 $ 117.7
Natural gas revenues 53.4 48.5 4.9
Operating revenues 1,201.9 1,079.3 122.6
Operating expenses
Fuel and purchased power (378.4) (336.6) (41.8)
Cost of natural gas sold (22.8) (17.3) (5.5)
Other operation and maintenance (1)
(197.2) (184.4) (12.8)
Depreciation and amortization (160.4) (145.5) (14.9)
Property and revenue taxes (29.7) (17.0) (12.7)
Gross margin (GAAP) 413.4 378.5 34.9
Other operation and maintenance (1)
197.2 184.4 12.8
Depreciation and amortization 160.4 145.5 14.9
Property and revenue taxes 29.7 17.0 12.7
Utility margin (non-GAAP) $ 800.7 $ 725.4 $ 75.3

(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 $34.9 million during the third quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $75.3 million during the third quarter of 2025, compared with the same quarter in 2024. Both measures were driven by:

• A $66.6 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, in our 2024 Annual Report on Form 10-K, for more information on the 2025 rate order.

• A $7.8 million increase in margins related to higher sales volumes, including the impact of weather during the third quarter of 2025, compared with the same quarter in 2024.

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 $14.9 million increase in depreciation and amortization expense;

• A $12.7 million increase in property and revenues taxes;

• A $5.1 million increase in transmission expense;

• A $4.6 million increase in electric and natural gas distribution expenses; and

• A $2.8 million increase in other operating and maintenance related to our power plants.

09/30/2025 Form 10-Q
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Wisconsin Electric Power Company

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

Other operating expenses at the utility segment increased $57.2 million during the third quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in other operating expenses were:

• A $14.9 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $12.7 million increase in property and revenue taxes during the third quarter of 2025, compared with the same quarter in 2024, driven by a favorable 2024 adjustment related to a sales tax audit.

• A $10.6 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $5.1 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 $4.6 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the third quarter of 2025, compared with the same quarter in 2024.

• A $3.8 million increase in benefits expenses, driven by higher compensation costs.

• A $2.8 million increase in other operating and maintenance related to our power plants, partially driven by renewable generation facilities placed in service during 2025 and the fourth quarter of 2024.

Other Income, Net

Other income, net at the utility segment decreased $4.0 million during the third quarter of 2025, compared with the same quarter in 2024, driven by a $10.9 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 the third quarter of 2025, we amortized $5.2 million of the previously deferred non-service costs as we are now collecting these costs in rates. See Note 16, Employee Benefits, for more information on our benefit costs. This decrease in other income, net was partially offset by a $7.1 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the utility segment decreased $2.0 million during the third quarter of 2025, compared with the same quarter in 2024, driven by higher AFUDC-Debt due to continued capital investment and lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. These decreases were partially offset by the impact of our long-term debt issuance in September 2024.

Income Tax Expense

Income tax expense at the utility segment decreased $11.6 million during the third quarter of 2025, compared with the same quarter in 2024. This decrease was driven by:

• A $6.2 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;

• A $4.7 million increase in PTCs; and

• A $2.9 million increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment.

Partially offsetting these decreases in income tax expense was higher pre-tax income.
09/30/2025 Form 10-Q
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Wisconsin Electric Power Company


NINE MONTHS ENDED SEPTEMBER 30, 2025

Earnings

Our earnings for the nine months ended September 30, 2025 were $511.7 million, compared to $388.7 million for the same period in 2024. See below for information on the $123.0 million increase in earnings.

Expected 2025 Annual Effective Tax Rate

We expect our 2025 annual effective tax rate to be between 15.0% and 16.0%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

Non-GAAP Financial Measures

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.

09/30/2025 Form 10-Q
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Wisconsin Electric Power Company

Utility Segment Contribution to Net Income Attributed to Common Shareholder

The following table compares our utility segment's contribution to net income attributed to common shareholder for the nine months ended September 30, 2025, with the same period in 2024, including favorable or better, "B", and unfavorable or worse, "W", variances.
Nine Months Ended September 30
(in millions) 2025 2024 B (W)
Operating revenues $ 3,391.8 $ 3,020.1 $ 371.7
Operating expenses
Cost of sales (1)
1,127.1 986.0 (141.1)
Other operation and maintenance 773.1 720.6 (52.5)
Depreciation and amortization 467.6 427.1 (40.5)
Property and revenue taxes 90.2 77.1 (13.1)
Operating income 933.8 809.3 124.5
Other income, net 38.6 52.0 (13.4)
Interest expense 367.3 364.5 (2.8)
Income before income taxes 605.1 496.8 108.3
Income tax expense 92.5 107.2 14.7
Preferred stock dividend requirements 0.9 0.9 —
Net income attributed to common shareholder $ 511.7 $ 388.7 $ 123.0

(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:
Nine Months Ended September 30
(in millions) 2025 2024 B (W)
Operation and maintenance not included in line items below $ 297.2 $ 277.8 $ (19.4)
Transmission (1)
283.4 268.3 (15.1)
Regulatory amortizations and other pass through expenses (2)
98.9 75.9 (23.0)
We Power (3)
97.0 99.2 2.2
Earnings sharing mechanism (3.4) (0.6) 2.8
Total other operation and maintenance $ 773.1 $ 720.6 $ (52.5)

(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 the nine months ended September 30, 2025 and 2024, $303.5 million and $276.5 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 the nine months ended September 30, 2025 and 2024, $88.9 million and $86.7 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.

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Wisconsin Electric Power Company

The following tables provide information on delivered sales volumes by customer class and weather statistics:
Nine Months Ended September 30
MWh (in thousands)
Electric Sales Volumes 2025 2024 B (W)
Customer Class
Residential 6,202.0 6,047.4 154.6
Small commercial and industrial 6,676.7 6,569.9 106.8
Large commercial and industrial 4,962.1 4,925.0 37.1
Other 68.0 72.7 (4.7)
Total retail 17,908.8 17,615.0 293.8
Wholesale 513.3 432.4 80.9
Resale 3,672.3 3,734.1 (61.8)
Total sales in MWh 22,094.4 21,781.5 312.9

Nine Months Ended September 30
Therms (in millions)
Natural Gas Sales Volumes 2025 2024 B (W)
Customer Class
Residential 259.8 219.0 40.8
Commercial and industrial 152.8 127.6 25.2
Total retail 412.6 346.6 66.0
Transportation 190.7 179.6 11.1
Total sales in therms 603.3 526.2 77.1

Nine Months Ended September 30
Degree Days
Weather (1)
2025 2024 B (W)
Heating (4,176 Normal)
4,364 3,360 29.9 %
Cooling (707 Normal)
750 802 (6.5) %

(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.

09/30/2025 Form 10-Q
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Wisconsin Electric Power Company

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).
Nine Months Ended September 30
(in millions) 2025 2024 B (W)
Electric revenues $ 3,011.8 $ 2,716.3 $ 295.5
Natural gas revenues 380.0 303.8 76.2
Operating revenues 3,391.8 3,020.1 371.7
Operating expenses
Fuel and purchased power (941.0) (845.2) (95.8)
Cost of natural gas sold (186.1) (140.8) (45.3)
Other operation and maintenance (1)
(582.9) (561.2) (21.7)
Depreciation and amortization (467.6) (427.1) (40.5)
Property and revenue taxes (90.2) (77.1) (13.1)
Gross margin (GAAP) 1,124.0 968.7 155.3
Other operation and maintenance (1)
582.9 561.2 21.7
Depreciation and amortization 467.6 427.1 40.5
Property and revenue taxes 90.2 77.1 13.1
Utility margin (non-GAAP) $ 2,264.7 $ 2,034.1 $ 230.6

(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 $155.3 million during the nine months ended September 30, 2025, compared with the same period in 2024, and utility margin (non-GAAP) increased $230.6 million during the nine months ended September 30, 2025, compared with the same period in 2024. Both measures were driven by:

• A $191.0 million increase in margins driven by the impact of our rate order approved by the PSCW, effective January 1, 2025.

• A $44.3 million increase in margins related to higher retail sales volumes driven by the impact of colder weather during the nine months ended September 30, 2025, compared with the same period in 2024. As measured by heating degree days, the nine months ended September 30, 2025 were 29.9% colder than the same period in 2024.

These increases in margins were partially offset by a $4.6 million decrease in margins driven by higher ash removal and fuel handling 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 $40.5 million increase in depreciation and amortization expense;

• A $15.1 million increase in transmission expense;

• A $13.1 million increase in property and revenues taxes; and

• An $8.7 million increase in electric and natural gas distribution expenses.

09/30/2025 Form 10-Q
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Wisconsin Electric Power Company

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

Other operating expenses at the utility segment increased $106.1 million during the nine months ended September 30, 2025, compared with the same period in 2024. The significant factors impacting the increase in other operating expenses were:

• A $40.5 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $23.0 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $15.1 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 $13.1 million increase in property and revenue taxes during the nine months ended September 30, 2025, compared with the same period in 2024, driven by a favorable 2024 adjustment related to a sales tax audit.

• An $8.7 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems during the nine months ended September 30, 2025, compared with the same period in 2024.

• A $5.1 million increase in benefits expenses, driven by higher compensation costs.

Other Income, Net

Other income, net at the utility segment decreased $13.4 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by a $33.6 million negative impact from the non-service components of our net periodic pension and OPEB costs. In accordance with our December 2024 PSCW rate order, in 2025, we began amortizing our pension and OPEB costs that were previously deferred under escrow accounting. During the nine months ended September 30, 2025, we amortized $15.7 million of the previously deferred non-service costs as we are now collecting these costs in rates. This decrease in other income, net was partially offset by an $18.7 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the utility segment increased $2.8 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by the impact of our long-term debt issuances in May and September 2024. This increase was partially offset by higher AFUDC-Debt due to continued capital investment and lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. Lower average short-term debt balances and lower average short-term debt interest rates, also partially offset the increase in interest expense.

Income Tax Expense

Income tax expense at the utility segment decreased $14.7 million during the nine months ended September 30, 2025, compared with the same period in 2024. This decrease was driven by:

• A $16.8 million increase in PTCs;

• A $16.4 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;

• A $5.7 million increase in the income tax benefits associated with AFUDC-Equity, driven by continued capital investment; and

• A $1.6 million increase in the deferred tax benefits associated with the Tax Legislation. See Note 12, Income Taxes, for more information.

Partially offsetting these decreases in income tax expense was higher pre-tax income.
09/30/2025 Form 10-Q
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Wisconsin Electric Power Company


LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Cash Flows

The following table summarizes our cash flows during the nine months ended September 30:
(in millions) 2025 2024 Change in 2025 Over 2024
Cash provided by (used in):
Operating activities $ 994.6 $ 1,004.1 $ (9.5)
Investing activities (1,856.2) (1,081.8) (774.4)
Financing activities 867.2 327.2 540.0

Operating Activities

Net cash provided by operating activities decreased $9.5 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by a $127.0 million decrease in cash related to higher payments for other operation and maintenance expenses. During the nine months ended September 30, 2025, our payments were higher due to increased transmission costs, electric and natural gas distribution costs, benefit expenses, as well as the timing of payments for accounts payable.

This decrease in net cash provided by operating activities was partially offset by:

• An $87.4 million increase in cash from higher overall collections from customers during the nine months ended September 30, 2025, compared with the same period in 2024. This increase was driven by the impact of our rate order approved by the PSCW, effective January 1, 2025, a higher per-unit cost of natural gas, and higher sales volumes from the impact of colder weather during the nine months ended September 30, 2025, compared with the same period in 2024.

• A $22.3 million increase in cash from lower cash paid for income taxes driven by lower taxable income and the timing of proceeds received from the sale of PTC's to third parties during the nine months ended September 30, 2025, compared with the same period in 2024.

• A $5.2 million increase in cash driven by lower collateral paid to counterparties during the nine months ended September 30, 2025, compared with the same period in 2024, as well as realized gains on derivative instruments recognized during the nine months ended September 30, 2025, compared with realized losses on derivative instruments recognized during the same period in 2024.

Investing Activities

Net cash used in investing activities increased $774.4 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by a $903.1 million increase in cash paid for capital expenditures during the nine months ended September 30, 2025, which is discussed in more detail below.

This increase in net cash used in investing activities was 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, Acquisition, for more information.

• A $26.9 million increase in cash received from ATC during the nine months ended September 30, 2025, compared with the same period in 2024, for the reimbursement of transmission infrastructure upgrades.
09/30/2025 Form 10-Q
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Wisconsin Electric Power Company


Capital Expenditures

Capital expenditures for the nine months ended September 30 were as follows:
(in millions) 2025 2024 Change in 2025 Over 2024
Capital expenditures $ 1,891.1 $ 988.0 $ 903.1

The increase in cash paid for capital expenditures during the nine months ended September 30, 2025, compared with the same period in 2024, was driven by higher payments for renewable energy projects, CTs at OCPP, and for our electric and natural gas distribution systems.

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

Financing Activities

Net cash provided by financing activities increased $540.0 million during the nine months ended September 30, 2025, compared with the same period in 2024, driven by:

• Equity contributions of $1,085.0 million received from our parent during the nine months ended September 30, 2025, to balance our capital structure. There were no equity contributions received from our parent during the same period in 2024.

• A $217.9 million increase in cash due to lower net repayments of commercial paper during the nine months ended September 30, 2025, compared with the same period in 2024.

These increases in cash were partially offset by:

• A $447.8 million decrease in cash due to lower issuances of long-term debt during the nine months ended September 30, 2025, compared with the same period in 2024.

• A $250.1 million decrease in cash due to higher retirements of long-term debt during the nine months ended September 30, 2025, compared with the same period in 2024.

• A $60.0 million decrease in cash due to higher dividends paid to our parent during the nine months ended September 30, 2025, compared with the same period in 2024, to balance our capital structure.

Other Significant Financing Activities

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

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. See the discussion below and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Requirements in our 2024 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

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Wisconsin Electric Power Company

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 requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 19, Commitments and Contingencies.
(in millions)
2025 $ 2,775.5
(1)
2026 3,212.1
2027 4,670.5
Total $ 10,658.1

(1) This includes actual capital expenditures incurred through September 30, 2025, as well as estimated capital expenditures for the remainder of the year.

We continue to upgrade our electric and natural gas distribution systems to enhance reliability. These upgrades include addressing our aging infrastructure, system hardening, and the AMI program. AMI is an integrated system of smart meters, communication networks, and data management systems that enable two-way communication between utilities and customers.

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Wisconsin Electric Power Company

WEC Energy Group is committed to investing in solar, wind, battery storage, and natural gas-fired generation. Below are examples of our share of projects that are proposed, currently underway, or recently completed.
Project Ownership Interest Source Share of Generation Share of Estimated Costs Date of Expected Commercial Operation
Paris Solar-Battery Park 75% Solar/Battery 150 MW/82 MW $443 million
December 2024 Solar
June 2025 Battery (2)
Darien Solar-Battery Park 75% Solar/Battery 188 MW/56 MW $467 million
March 2025 Solar (2)
2026 Battery
Koshkonong Solar Park 75% Solar/Battery 225 MW/124 MW $775 million 2026 Solar
2027 Battery
Badger Hollow Wind Energy Generation Facility (1)
80% Wind 89 MW $284 million 2027
High Noon 75% Solar/Battery 225 MW/124 MW $736 million 2027
OCPP 100% LNG (2 Bcf) N/A $456 million 2027
Paris RICE Generation 100% RICE 128 MW $300 million 2027
Rochester Lateral 100% Gas Lateral N/A $200 million 2027
Ursa Solar Electric Generation Facility (1)
80% Solar 160 MW $361 million 2027
Whitetail Energy Generation Facility (1)
80% Wind 53 MW $178 million 2027
OCPP 100% CTs 1,100 MW $1.2 billion 2027-2028
Dawn Harvest Solar Energy Center (1)
80% Solar
100% Battery 		Solar/Battery 120 MW/50 MW $375 million 2028
ERGS Fuel Flexibility (1)
83.34% Add Gas Capability N/A $132 million 2028
Fox Solar (1)
90% Solar 90 MW $238 million 2028
Good Oak Solar Generation Facility (1)
80% Solar 78 MW $172 million 2028
Gristmill Solar Generation Facility (1)
80% Solar 53 MW $116 million 2028
PWGS Turbine Upgrade (1)
100% Combined Cycle
Gas Turbine 		100 MW $227 million 2028
Saratoga Solar Electric Generation and BESS Facility (1)
80% Solar/Battery 120 MW/40 MW $361 million 2028
Sinissippi Solar (1)
100% Solar 100 MW $277 million 2028
Superior Solar (1)
90% Solar 135 MW $354 million 2028
Whitewater Solar Electric Generation Facility (1)
50% Solar 90 MW $206 million 2028
Akron Solar (1)
90% Solar 180 MW $461 million 2029
Dawn Break Solar and BESS Facility (1)
90% Solar/Battery 162 MW/162 MW $697 million 2029
Emerald Bluffs Solar (1)
90% Solar 203 MW $510 million 2029

(1) Pending approval by the PSCW.

(2) Commercial operation achieved for Paris Solar-Battery Park and Darien Solar Park.

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.

In connection with several investigations it conducted, the DOC set duties on solar panels and cells imported from four southeast Asian countries. See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the duties set by the DOC and 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.
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Long-Term Debt

See Note 9, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the nine months ended September 30, 2025.

Common Stock Dividends

During the nine months ended September 30, 2025, we paid common stock dividends of $ 240.0 million to the sole holder of our common stock, WEC Energy Group.

Other Significant Cash Requirements

See Note 19, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the nine months ended September 30, 2025.

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. For additional information, see Note 8, Short-Term Debt and Lines of Credit, Note 15, Guarantees, and Note 18, Variable Interest Entities.

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 markets, which allows us to obtain external short-term borrowings, including commercial paper, and 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 for the remainder of 2025, 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 in our 2024 Annual Report on Form 10-K.

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.

Although not the case as of September 30, 2025, our current liabilities sometimes exceed our current assets. If this occurs, we do not expect that it would have an impact on our liquidity, as we currently believe that our available capacity under our existing revolving
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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 8, Short-Term Debt and Lines of Credit, for more information about our credit facility and commercial paper.

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts have investments consisting of fixed income and equity securities that are subject to the volatility of the stock market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2024 Annual Report on Form 10-K.

Debt Covenants

Our credit facility contains financial covenants that we must satisfy, including a debt to capitalization ratio. At September 30, 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, in our 2024 Annual Report on Form 10-K for more information regarding our debt covenants.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of September 30, 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 September 30, 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.

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. This discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2024 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental and regulatory matters, critical accounting policies and estimates, and other matters.

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Regulatory, Legislative, and Legal Matters

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 on June 6, 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 2024, a coalition of several U.S. producers of solar panels filed a new petition requesting tariffs on imports from the same four Southeast Asian countries. The group alleged that some Chinese companies had moved their solar operations to avoid penalties imposed in the first investigation. In April 2025, the DOC reached final affirmative determinations, 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 and Inflation Reduction Act

In November 2021, the Infrastructure Investment and Jobs Act was signed into law and provides for approximately $1.2 trillion of federal spending over a five year period, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States. We believe that funding from this Act would support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid. Funding in the Act could also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future to the benefit of our customers, the communities we serve, and our company.

In August 2022, the IRA was signed into law and provides for $258 billion in energy-related provisions over a 10-year period. The provisions of the IRA are intended to, among other things, lower gasoline and electricity prices, incentivize domestic clean energy investment, manufacturing, and production, and promote reductions in carbon emissions. We believe that we and our customers can benefit from the IRA’s provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects.

Under 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
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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 12, Income Taxes, for more information about the impact of these sales. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us. Overall, we believe the IRA will help reduce our cost of investing in projects that will support our commitment to reduce emissions and provide customers affordable, reliable, and clean energy over the longer term.

In January 2025, pursuant to an executive order issued by the current presidential administration, disbursement of funds under these two Acts was paused until agency heads can determine whether grants, loans, contracts, and other disbursements are consistent with the current administration's energy policy. Agency heads must consult with the Office of Management and Budget and the National Economic Council prior to any funding being disbursed. The new policy encourages use of domestic energy sources including oil, natural gas, coal, hydropower, biofuels, critical minerals, and nuclear, promotes consumer choice of goods and appliances, aims to boost American workers and businesses, eliminates the EV mandate, and limits regulations that apply to the energy industry. The pause could disrupt funding, temporarily or permanently, for infrastructure projects already in progress, may cause project delays and cancellations, may impact continuing payment obligations for downstream contractors and suppliers, and may cause legal and contractual claims.

One Big Beautiful Bill Act

On July 4, 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 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 released IRS Notice 2025-42, implementing new beginning of construction safe harbor rules that became effective September 2, 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 19, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the risks described below. In addition, there is continuing uncertainty over the impact that the ongoing regional conflicts, including those in Ukraine, Israel and in other parts of the Middle East, will ultimately have on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2024 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Changes to United States Trade Policy (Tariff Activity)

The 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 are also adjusting 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.
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Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the 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. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below that are disclosed in Part I of our 2024 Annual Report on Form 10-K.

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

• Item 1A. Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

• Item 1A. Risk Factors – Risks Related to the Operation of Our Business – We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

• Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – The fluctuation in demand for certain commodities and their respective prices could negatively impact our operations.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2024 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 13, Fair Value Measurements, Note 14, Derivative Instruments, and Note 15, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the third quarter of 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2024 Annual Report on Form 10-K. See Note 19, Commitments and Contingencies, and Note 21, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in Note 19, Commitments and Contingencies, and Note 21, 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.

ITEM 1A. RISK FACTORS

The following risk factor updates and supplements those risk factors disclosed in Item 1A. Risk Factors in Part I of our 2024 Annual Report on Form 10-K.

Risks Related to the Operations of Our Business

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 are planning 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 provider, ATC, is also planning 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 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 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, 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 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
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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. Additionally, these customers may experience business downturn, which may cause the loss of these customers or may weaken their financial condition, including their creditworthiness. 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.

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 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).

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ITEM 6. EXHIBITS
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to 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.
Number Exhibit
4 Instruments Defining the Rights of Security Holders, Including Indentures
31 Rule 13a-14(a) / 15d-14(a) Certifications
32 Section 1350 Certifications
101 Interactive Data Files
101.INS Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH Inline XBRL Taxonomy Extension Schema
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB Inline XBRL Taxonomy Extension Label Linkbase
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



WISCONSIN ELECTRIC POWER COMPANY
(Registrant)
/s/ WILLIAM J. GUC
Date: October 31, 2025 William J. Guc
Vice President and Controller
(Duly Authorized Officer and Chief Accounting Officer)

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TABLE OF CONTENTS
Part I. Financial InformationItem 1. Financial StatementsNote 1 General InformationNote 2 AcquisitionNote 3 Operating RevenuesNote 4 Credit LossesNote 5 Regulatory Assets and LiabilitiesNote 6 Property, Plant, and EquipmentNote 7 Common EquityNote 8 Short-term Debt and Lines Of CreditNote 9 Long-term DebtNote 10 LeasesNote 11 Materials, Supplies, and InventoriesNote 12 Income TaxesNote 13 Fair Value MeasurementsNote 14 Derivative InstrumentsNote 15 GuaranteesNote 16 Employee BenefitsNote 17 Segment InformationNote 18 Variable Interest EntitiesNote 19 Commitments and ContingenciesNote 20 Supplemental Cash Flow InformationNote 21 Regulatory EnvironmentNote 22 New Accounting PronouncementsItem 2. Management's Discussion and Analysis Of Financial Condition and Results Of OperationsItem 3. Quantitative and Qualitative Disclosures About Market RiskItem 4. Controls and ProceduresPart II. Other InformationItem 1. Legal ProceedingsItem 1A. Risk FactorsItem 5. Other InformationItem 6. Exhibits

Exhibits

4.1* Securities Resolution No. 23 of Wisconsin Electric Power Company, effective as of September 18, 2025, under the Indenture for Debt Securities, dated as of December 1, 1995, between Wisconsin Electric Power Company and U.S. Bank Trust Company, National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to Wisconsin Electric Power Company's Form 8-K filed September 18, 2025.) 31.1 Certification Pursuant to Rule13a-14(a) or 15d-14(a), as Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification Pursuant to Rule13a-14(a) or 15d-14(a), as Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley Act of 2002.