wep-20250331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2025


☐			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

March 31, 2025

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

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WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2025

TABLE OF CONTENTS

Page

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Income Statements

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Cash Flows

Condensed Consolidated Statements of Equity

Notes to Condensed Consolidated Financial Statements

Page

Regulatory Assets and Liabilities

Note 5

Property, Plant, and Equipment

Note 6

Common Equity

Note 7

Short-Term Debt and Lines of Credit

Note 8

Materials, Supplies, and Inventories

Note 9

Income Taxes

Note 10

Fair Value Measurements

Note 11

Derivative Instruments

Variable Interest Entities

Note 16

Commitments and Contingencies

Note 17

Supplemental Cash Flow Information

Note 18

Regulatory Environment

Note 19

New Accounting Pronouncements

ITEM 2.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.

CONTROLS AND PROCEDURES


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GLOSSARY OF TERMS AND ABBREVIATIONS

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


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

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
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
CO2						Carbon Dioxide
CRL						Combustine Residual Leachate
CWA						Clean Water Act
ELG						Steam Electric Effluent Limitation Guidelines
FGD						Flue Gas Desulfurization
GHG						Greenhouse Gas
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
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

Other Terms and Abbreviations
AD						Antidumping
AI						Artificial Intelligence
AMI						Advanced Metering Infrastructure


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Badger Hollow Wind						Badger Hollow Wind Energy Generation Facility

Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
CODM						Chief Operating Decision Maker
CVD						Countervailing Duty
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
Darien						Darien Solar Park
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
Good Oak						Good Oak Solar Generation Facility
Gristmill						Gristmill Solar Generation Facility
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
OCPP						Oak Creek Power Plant
Paris						Paris Solar-Battery Park
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
Saratoga						Saratoga Solar Electric Generation and BESS Facility
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
Ursa						Ursa Solar Electric Generation Facility
VLC						Very Large Customer

Whitetail						Whitetail Wind Energy Generation Facility


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations, including associated compliance costs, legal proceedings, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, climate-related matters, the WEC Energy Group capital plan, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in our 2024 Annual Report on Form 10-K, 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, 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 including as a result of the new presidential administration, 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;


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

•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 CO2 emission and/or methane emission reduction goals and opportunities and actions related to those goals, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, 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;

•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;


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•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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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended
	March 31
(in millions)	2025		2024
Operating revenues	$	1,179.1	$	1,038.8

Operating expenses
Cost of sales	399.6		352.2
Other operation and maintenance	252.1		241.6
Depreciation and amortization	150.9		139.6
Property and revenue taxes	30.9		30.8
Total operating expenses	833.5		764.2

Operating income	345.6		274.6

Other income, net	10.8		16.3
Interest expense	124.7		120.8
Other expense	(113.9)		(104.5)

Income before income taxes	231.7		170.1
Income tax expense	35.3		35.8
Net income	196.4		134.3

Preferred stock dividend requirements	0.3		0.3
Net income attributed to common shareholder	$	196.1	$	134.0

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


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WISCONSIN ELECTRIC POWER COMPANY


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2025		December 31, 2024
Assets
Current assets
Cash and cash equivalents	$	62.7	$	0.4
Accounts receivable and unbilled revenues, net of reserves of $37.9 and $46.9, respectively	628.3		601.2
Accounts receivable from related parties	67.8		128.6
Materials, supplies, and inventories	305.0		354.8
Prepaid taxes	87.4		139.8
Other prepayments	24.7		24.9

Other	41.0		23.2
Current assets	1,216.9		1,272.9

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $6,055.5 and $5,952.3, respectively	13,036.2		12,810.7
Regulatory assets (March 31, 2025 and December 31, 2024 include $74.3 and $76.5, respectively, related to WEPCo Environmental Trust)	2,951.3		2,946.3
Pension and OPEB assets	80.0		79.2
Other	91.8		90.5
Long-term assets	16,159.3		15,926.7
Total assets	$	17,376.2	$	17,199.6

Liabilities and Equity
Current liabilities
Short-term debt	$	28.0	$	179.9
Current portion of long-term debt (March 31, 2025 and December 31, 2024 includes $9.2 related to WEPCo Environmental Trust)	259.2		259.2
Current portion of finance lease obligations	102.5		99.3
Accounts payable	324.9		529.3
Accounts payable to related parties	205.9		206.1


Accrued interest	60.8		27.6
Other	212.6		157.0
Current liabilities	1,193.9		1,458.4

Long-term liabilities
Long-term debt (March 31, 2025 and December 31, 2024 include $76.5 and $76.4, respectively, related to WEPCo Environmental Trust)	3,728.9		3,728.0
Finance lease obligations	2,718.6		2,742.9
Deferred income taxes	1,614.8		1,655.7
Regulatory liabilities	1,801.8		1,758.8

Other	374.4		348.6
Long-term liabilities	10,238.5		10,234.0

Commitments and contingencies (Note 16)

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	3,003.5		2,703.0
Retained earnings	2,577.0		2,440.9
Common shareholder's equity	5,913.4		5,476.8

Preferred stock	30.4		30.4
Total liabilities and equity	$	17,376.2	$	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


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2025		2024
Operating activities
Net income	$	196.4	$	134.3
Reconciliation to cash provided by operating activities
Depreciation and amortization	150.9		139.6
Deferred income taxes and ITCs, net	(38.1)		8.1


Change in –
Accounts receivable and unbilled revenues, net	1.0		34.5
Materials, supplies, and inventories	49.8		22.4
Prepaid taxes	52.4		28.7



Other current assets	1.3		2.6
Accounts payable	(120.2)		(64.5)
Accrued taxes	50.2		34.8

Accrued interest	33.2		35.1

Other current liabilities	6.2		(3.9)
Other, net	8.6		(2.3)
Net cash provided by operating activities	391.7		369.4

Investing activities
Capital expenditures	(417.9)		(203.0)



Reimbursement for ATC's transmission infrastructure upgrades	33.1		6.2




Other, net	(5.8)		(0.5)
Net cash used in investing activities	(390.6)		(197.3)

Financing activities
Change in short-term debt	(151.9)		(83.9)


Payments for finance lease obligations	(23.8)		(20.7)
Equity contribution from parent	300.0		—
Payment of dividends to parent	(60.0)		(60.0)
Other, net	(0.3)		(0.3)
Net cash provided by (used in) financing activities	64.0		(164.9)

Net change in cash, cash equivalents, and restricted cash	65.1		7.2
Cash, cash equivalents, and restricted cash at beginning of period	2.5		7.5
Cash, cash equivalents, and restricted cash at end of period	$	67.6	$	14.7

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


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WISCONSIN ELECTRIC POWER COMPANY


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


	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

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


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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 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 months ended March 31, 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—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 March 31
(in millions)	2025		2024
Wisconsin Electric Power Company
Electric utility	$	935.3	$	846.2
Natural gas utility	240.8		187.9
Total revenues from contracts with customers	1,176.1		1,034.1
Other operating revenues	3.0		4.7
Total operating revenues	$	1,179.1	$	1,038.8


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Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2025		2024
Residential	$	401.9	$	360.0
Small commercial and industrial	306.9		287.5
Large commercial and industrial	145.0		134.5
Other	5.7		5.6
Total retail revenues	859.5		787.6
Wholesale	14.1		11.0
Resale	48.6		36.5
Steam	12.5		10.1
Other utility revenues	0.6		1.0
Total electric utility operating revenues	$	935.3	$	846.2

Natural Gas Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2025		2024
Residential	$	169.1	$	135.9
Commercial and industrial	77.9		61.1
Total retail revenues	247.0		197.0
Transportation	8.0		7.5
Other utility revenues (1)	(14.2)		(16.6)
Total natural gas utility operating revenues	$	240.8	$	187.9

(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.

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)	2025		2024
Late payment charges	$	3.3	$	3.5
Rental revenues	0.3		0.3
Alternative revenues (1)	(0.6)		0.9
Total other operating revenues	$	3.0	$	4.7

(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 3—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 March 31, 2025 and December 31, 2024.


03/31/2025 Form 10-Q			9			Wisconsin Electric Power Company

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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)	March 31, 2025			December 31, 2024
Accounts receivable and unbilled revenues	$	666.2		$	648.1
Allowance for credit losses	37.9			46.9
Accounts receivable and unbilled revenues, net (1)	$	628.3		$	601.2

Total accounts receivable, net – past due greater than 90 days (1)	$	31.1		$	38.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	95.9		%	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 March 31, 2025, $363.4 million, or 57.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

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


	Three Months Ended March 31
(in millions)	2025		2024
Balance at January 1	$	46.9	$	44.5
Provision for credit losses	12.7		8.1
Provision for credit losses deferred for future recovery or refund	(6.0)		14.2
Write-offs charged against the allowance	(23.2)		(25.0)
Recoveries of amounts previously written off	7.5		7.1
Balance at March 31	$	37.9	$	48.9

There was a $9.0 million decrease in the allowance for credit losses at March 31, 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.

There was a $4.4 million increase in the allowance for credit losses at March 31, 2024, compared to January 1, 2024, largely driven by an increase in past due accounts receivable balances. An increase in past due balances is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. The winter moratorium begins on November 1 and ends on April 15.


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NOTE 4—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 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)	March 31, 2025		December 31, 2024
Regulatory assets
We Power finance leases	$	1,144.9	$	1,139.1
Plant retirement related items	670.0		655.1
Income tax related items	371.8		364.6
Pension and OPEB costs	333.9		343.1
Uncollectible expense	102.4		108.4
System support resource	100.4		102.9
Securitization	74.3		76.5
Asset retirement obligations	54.4		52.8
Bluewater Natural Gas Holding, LLC	20.1		21.1
Other, net	79.1		82.7
Total regulatory assets	$	2,951.3	$	2,946.3


(in millions)	March 31, 2025		December 31, 2024
Regulatory liabilities
Removal costs	$	821.6	$	809.2
Income tax related items	654.4		653.9
Pension and OPEB benefits	116.1		118.5
Energy costs refundable through rate adjustments	96.8		70.7
Revenue requirements of renewable generation facilities	36.4		37.9
Derivatives	34.4		13.3
Electric transmission costs	16.2		19.7
Other, net	44.5		39.6
Total regulatory liabilities	$	1,820.4	$	1,762.8

Balance sheet presentation
Other current liabilities	$	18.6	$	4.0
Regulatory liabilities	1,801.8		1,758.8
Total regulatory liabilities	$	1,820.4	$	1,762.8

NOTE 5—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, 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. OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of our ownership share of OCPP Units 7 and 8 was $648.1 million at March 31, 2025, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.


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NOTE 6—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 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 7—SHORT-TERM DEBT AND LINES OF CREDIT

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


(in millions, except percentages)	March 31, 2025			December 31, 2024
Commercial paper
Amount outstanding	$	28.0		$	179.9
Weighted-average interest rate on amounts outstanding	4.52		%	4.63		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2025 was $138.8 million with a weighted-average interest rate during the period of 4.56%.

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	March 31, 2025
Revolving credit facility	September 2026	$	500.0

Less:
Letters of credit issued inside credit facility		1.0
Commercial paper outstanding		28.0
Available capacity under existing credit facility		$	471.0

NOTE 8—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	March 31, 2025		December 31, 2024
Materials and supplies	$	233.0	$	252.1
Fossil fuel	60.3		60.0
Natural gas in storage	11.7		42.7
Total	$	305.0	$	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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NOTE 9—INCOME TAXES

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














	Three Months Ended March 31, 2025				Three Months Ended March 31, 2024
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	48.6	21.0	%	$	35.7	21.0	%
State income taxes net of federal tax benefit	14.1		6.1	%	10.0		5.9	%

PTCs, net	(13.0)		(5.6)	%	(5.1)		(3.0)	%
Federal excess deferred tax amortization	(7.0)		(3.0)	%	(5.7)		(3.4)	%
Tax repairs	(5.2)		(2.2)	%	1.1		0.7	%
AFUDC-Equity	(5.0)		(2.2)	%	(3.2)		(1.9)	%

Domestic production activities deferral	2.0		0.8	%	1.7		1.0	%
Other, net	0.8		0.3	%	1.3		0.7	%
Total income tax expense	$	35.3	15.2	%	$	35.8	21.0	%

The effective tax rate for the three months ended March 31, 2025, differs from the United States statutory federal income tax rate of 21%, primarily due to PTCs, the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, 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 rate for the three months ended March 31, 2024, does not materially differ from the United States statutory federal income tax rate of 21%. This is primarily due to the impact of the protected 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 line above).

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. Under this transferability provision, WEC Energy Group entered into agreements in October 2024 and April 2025 to sell the majority of the PTCs we generate in 2025 and 2026, respectively, to third parties. We elect to account for tax credits transferred under the scope of Accounting Standards Codification 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

NOTE 10—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.


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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:


	March 31, 2025
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	27.3	$	1.2	$	—	$	28.5
FTRs	—		—		1.1		1.1
Total derivative assets	$	27.3	$	1.2	$	1.1	$	29.6

Derivative liabilities
Natural gas contracts	$	—	$	0.7	$	—	$	0.7


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

Derivative liabilities
Natural gas contracts	$	0.6	$	0.5	$	—	$	1.1

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets.

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


	Three Months Ended March 31
(in millions)	2025		2024
Balance at the beginning of the period	$	2.9	$	2.5

Settlements	(1.8)		(1.5)
Balance at the end of the period	$	1.1	$	1.0


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Fair Value of Financial Instruments

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


	March 31, 2025				December 31, 2024
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	21.8	$	30.4	$	21.2
Long-term debt, including current portion	3,988.1		3,846.4		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 11—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.


	March 31, 2025				December 31, 2024
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	27.8	$	0.7	$	10.0	$	1.1
FTRs	1.1		—		2.9		—
Total current	28.9		0.7		12.9		1.1

Long-term
Natural gas contracts	0.7		—		0.5		—

Total	$	29.6	$	0.7	$	13.4	$	1.1

Realized gains and losses on derivatives are primarily recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our fuel and natural gas cost recovery mechanisms. Our estimated notional sales volumes and realized gains and losses were as follows:


	Three Months Ended March 31, 2025			Three Months Ended March 31, 2024
(in millions)	Volumes	Gains		Volumes	Gains (Losses)
Natural gas contracts	18.2 Dth	$	1.5	22.9 Dth	$	(17.0)
FTRs	4.7 MWh	1.0		4.9 MWh	1.9
Total		$	2.5		$	(15.1)

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 both March 31, 2025 and December 31, 2024, we had posted cash collateral of $4.9 million. These amounts were recorded on our balance sheets in other current assets. At March 31, 2025 and December 31, 2024, we had


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also received cash collateral of $15.9 million and $2.8 million, respectively. These amounts were recorded on our balance sheets in other current liabilities.

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


	March 31, 2025					December 31, 2024
(in millions)	Derivative Assets			Derivative Liabilities		Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	29.6		$	0.7	$	13.4		$	1.1
Gross amount not offset on the balance sheet	(16.1)		(1)	(0.2)		(3.6)		(2)	(0.8)
Net amount	$	13.5		$	0.5	$	9.8		$	0.3

(1) Includes cash collateral received of $15.9 million.

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

NOTE 12—GUARANTEES

As of March 31, 2025, we had $27.4 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

NOTE 13—EMPLOYEE BENEFITS

The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans.


		Pension Benefits
	Three Months Ended March 31
(in millions)		2025		2024
Service cost		$	2.6	$	2.8
Interest cost		11.7		11.3
Expected return on plan assets		(14.8)		(15.6)


Amortization of net actuarial loss		4.3		4.3
Net periodic benefit cost		$	3.8	$	2.8


		OPEB Benefits
	Three Months Ended March 31
(in millions)		2025		2024
Service cost		$	0.9	$	0.8
Interest cost		2.4		2.1
Expected return on plan assets		(2.7)		(2.7)
Amortization of prior service credit		—		(0.1)
Amortization of net actuarial gain		(0.8)		(1.4)
Net periodic benefit credit		$	(0.2)	$	(1.3)

During the three months ended March 31, 2025, we made contributions and payments of $0.8 million related to our pension plans and an insignificant amount related to our OPEB plans. During the remainder of 2025, we expect to make contributions and payments of $2.4 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 March 31, 2025 and December 31, 2024, our balance sheets included regulatory assets of $7.4 million and $9.9 million, respectively, for pension costs and $15.9 million and $17.8 million, respectively, for OPEB costs. In accordance with our December 2024 PSCW rate order, we began


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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 14—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 2, 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 March 31, 2025, we reported two segments, our utility segment and our other segment, which are described below. All of our operations and assets 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 months ended March 31, 2025 and 2024.

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 months ended March 31, 2025 and 2024.


Three Months Ended March 31 (in millions)	2025		2024
Cost of sales:
Fuel and purchased power	$	276.2	$	254.3
Cost of natural gas sold	123.4		97.9

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 15—VARIABLE INTEREST ENTITIES

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


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

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the 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.

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


(in millions)	March 31, 2025		December 31, 2024
Assets
Other current assets (restricted cash)	$	4.3	$	1.5
Regulatory assets	74.3		76.5
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.2		9.2
Accounts payable	0.1		—
Accrued interest	0.4		0.1
Long-term debt	76.5		76.4

NOTE 16—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.


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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 March 31, 2025, were approximately $6.5 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 particulates, ozone, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

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 PM Standard, the Greenhouse Gas 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.

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. After review of the final rule, we believe we are well positioned to meet the requirements.

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. In September 2024, the D.C. Circuit Court of Appeals granted the EPA's motion for partial voluntary remand so that it could address issues of severability raised in the Supreme Court's June 2024 opinion granting the petitions for stay of the rule. Pursuant to an order of the D.C. Circuit Court of Appeals, the parties filed motions to govern future proceedings in December 2024. In January 2025, the D.C. Circuit Court of Appeals issued an order establishing a schedule for supplemental briefing on the issue of severability that extended through early March 2025. 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.


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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 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. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this 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. This nonattainment status 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/m3, while retaining the 24-hour standard of 35 µg/m3. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until 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. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Climate Change

Pursuant to the final Greenhouse Gas Power Plant Rule published in May 2024, there are no applicable standards for coal plants until the end of 2031 and after 2031, 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 combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our new Weston Generating Station RICE units are not affected under the rule because the


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rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the Greenhouse Gas 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 combustion turbines from the rule. At that time, the EPA indicated it would work on new rulemaking phases, focusing on CO2 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 combustion turbines. 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 and planned combined cycle natural gas facilities will be positioned to comply with the proposed rule. As the EPA is not scheduled to finalize this proposal until late 2025, it could be revised or repealed. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, which includes updates to the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The revisions 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 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. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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-fueled generation. We have already retired nearly 2,100 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 PIPP, and the 2018 retirement of the Pleasant Prairie power plant. WEC Energy Group expects to retire approximately 1,200 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8. See Note 5, Property, Plant, and Equipment, for more information related to planned power plant retirements. In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet, which includes us, by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for WEC Energy Group's generation fleet is to be net carbon neutral by 2050. WEC Energy Group believes it will be in a position to eliminate coal as an energy source by the end of 2032.

WEC Energy Group will also continue to focus on methane emissions reductions by improving its natural gas distribution systems, and has set a target across its natural gas distribution operations, including our operations, to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its natural gas utility distribution systems. In addition, subject to regulatory approval and market conditions, WEC Energy Group expects to procure RTCs.

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 later in 2025.


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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. Through 2023, 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 Valley Power Plant 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.

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, reliability must run agreements, etc.) 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 rule through litigation pending in the U.S. Court of Appeals for the Eighth Circuit. The outcome of this case may affect our compliance plans. In February 2025, the U.S. Court of Appeals for the Eighth Circuit granted the EPA's request to hold the ELG rule litigation in abeyance. In April 2025, the EPA filed a motion with the U.S. Court of Appeals for the Eighth Circuit requesting that they continue to hold the case in abeyance until June 30, 2025. The Supplemental ELG Rule remains in effect during the pendency of the legal challenge. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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.


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


(in millions)	March 31, 2025		December 31, 2024
Regulatory assets	$	10.6	$	10.8
Reserves for future environmental remediation (1)	10.6		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. We expect the cost of 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 17—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Three Months Ended March 31
(in millions)	2025		2024
Cash paid for interest, net of amount capitalized	$	90.3	$	84.8
Cash received for income taxes (1)	—		(4.3)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	94.3		76.6

(1) The cash received for income taxes in the first quarter of 2024 relates to 2023 PTCs that were sold to a third party.

Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:


(in millions)	March 31, 2025		December 31, 2024
Cash and cash equivalents	$	62.7	$	0.4
Restricted cash included in other current assets	4.3		1.5
Restricted cash included in other long-term assets	0.6		0.6
Cash, cash equivalents, and restricted cash	$	67.6	$	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 15, Variable Interest Entities, for more information.


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NOTE 18—REGULATORY ENVIRONMENT

Very Large Customer and Bespoke Resources Tariffs

On March 31, 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 (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. 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 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 proposed, the ROE (10.48%) and equity ratio (57%) will 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.

NOTE 19—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 14, 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 CO2 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.

WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for its generation fleet is to be net carbon neutral by 2050.

As part of our path toward these goals, we have started implementing co-firing with natural gas at the ERGS coal-fired units. By the end of 2030, WEC Energy Group expects to use coal as a backup fuel only, and believes it will be in a position to eliminate coal as an energy source by the end of 2032.

WEC Energy Group already has retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the PIPP, and the 2018 retirement of the Pleasant Prairie power plant. WEC Energy Group expects to retire approximately 1,200 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8. See Note 5, 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 $9.1 billion from 2025-2029 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:

•2,900 MWs of utility-scale solar;

•900 MWs of wind; and


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•565 MWs of battery storage.

WEC Energy Group also plans on investing in a combination of clean, natural gas-fired generation, including:

•1,100 MWs of combustion turbines to be constructed at our OCPP site (we plan on constructing a new natural gas lateral pipeline to support this generation); with

•An additional 675 MWs of combustion turbines planned; and

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

•An additional 114 MWs of RICE natural gas-fueled generation planned.

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 signed up eight customers for a total of 51 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 reduce methane emissions by improving its natural gas distribution system, and has set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of 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 addition, subject to regulatory approval and market conditions, WEC Energy Group expects to procure RTCs.

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. 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 throughout 2025.

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.

In April 2024, we filed a request with the PSCW to construct an LNG facility with a storage capacity of two Bcf, which would 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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We continue to upgrade our electric and natural gas distribution systems to enhance reliability and system hardening. WEC Energy Group expects to spend $4.5 billion from 2025 to 2029 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 its businesses and finding the best and most efficient processes.

Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, 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.

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.

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.


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RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2025

Earnings

Our earnings for the first quarter of 2025 were $196.1 million, compared with $134.0 million for the same quarter in 2024. See below for information on the $62.1 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.


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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 for the first quarter of 2025, with the same quarter in 2024, including favorable or better, "B", and unfavorable or worse, "W", variances.


	Three Months Ended March 31
(in millions)	2025		2024		B (W)
Operating revenues	$	1,179.1	$	1,038.8	$	140.3

Operating expenses
Cost of sales (1)	399.6		352.2		(47.4)
Other operation and maintenance	252.1		241.6		(10.5)
Depreciation and amortization	150.9		139.6		(11.3)
Property and revenue taxes	30.9		30.8		(0.1)
Operating income	345.6		274.6		71.0

Other income, net	10.8		16.3		(5.5)
Interest expense	124.7		120.8		(3.9)
Income before income taxes	231.7		170.1		61.6

Income tax expense	35.3		35.8		0.5
Preferred stock dividend requirements	0.3		0.3		—
Net income attributed to common shareholder	$	196.1	$	134.0	$	62.1

(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 March 31
(in millions)	2025		2024		B (W)
Operation and maintenance not included in line items below	$	95.1	$	92.3	$	(2.8)
Transmission (1)	94.5		89.4		(5.1)
We Power (2)	32.6		33.6		1.0
Regulatory amortizations and other pass through expenses (3)	30.7		26.5		(4.2)
Earnings sharing mechanism	(0.8)		(0.2)		0.6
Total other operation and maintenance	$	252.1	$	241.6	$	(10.5)

(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 first quarter of 2025 and 2024, $95.6 million and $89.2 million, respectively, of costs were billed to us by transmission providers.

(2)Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. During the first quarter of 2025 and 2024, $27.1 million and $29.5 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.

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


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


	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2025	2024	B (W)
Customer Class
Residential	1,954.7	1,867.5	87.2
Small commercial and industrial	2,155.1	2,105.8	49.3
Large commercial and industrial	1,551.2	1,548.4	2.8
Other	27.2	29.2	(2.0)
Total retail	5,688.2	5,550.9	137.3
Wholesale	199.9	158.6	41.3
Resale	1,012.3	1,224.1	(211.8)
Total sales in MWh	6,900.4	6,933.6	(33.2)


	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2025	2024	B (W)
Customer Class
Residential	185.8	155.4	30.4
Commercial and industrial	104.2	86.7	17.5
Total retail	290.0	242.1	47.9
Transportation	85.2	77.7	7.5
Total sales in therms	375.2	319.8	55.4


	Three Months Ended March 31
	Degree Days
Weather (1)	2025	2024	B (W)
Heating (3,214 Normal)	3,283	2,701	21.5	%

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


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Gross Margin GAAP and Utility Margin Non-GAAP

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


	Three Months Ended March 31
(in millions)	2025		2024		B (W)
Electric revenues	$	937.8	$	850.4	$	87.4
Natural gas revenues	241.3		188.4		52.9
Operating revenues	1,179.1		1,038.8		140.3

Operating expenses
Fuel and purchased power	(276.2)		(254.3)		(21.9)
Cost of natural gas sold	(123.4)		(97.9)		(25.5)
Other operation and maintenance (1)	(189.3)		(187.7)		(1.6)
Depreciation and amortization	(150.9)		(139.6)		(11.3)
Property and revenue taxes	(30.9)		(30.8)		(0.1)
Gross margin (GAAP)	408.4		328.5		79.9

Other operation and maintenance (1)	189.3		187.7		1.6
Depreciation and amortization	150.9		139.6		11.3
Property and revenue taxes	30.9		30.8		0.1
Utility margin (non-GAAP)	$	779.5	$	686.6	$	92.9

(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 $79.9 million during the first quarter of 2025, compared with the same quarter in 2024, and utility margin (non-GAAP) increased $92.9 million during the first quarter of 2025, compared with the same quarter in 2024. Both measures were driven by:

•A $65.6 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 $28.3 million increase in margins related to higher retail sales volumes driven by the impact of colder winter weather during the first quarter of 2025, compared with the same quarter in 2024. As measured by heating degree days, the first quarter of 2025 was 21.5% colder than 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:

•An $11.3 million increase in depreciation and amortization expense; and

•A $5.1 million increase in transmission expense.

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

Other operating expenses at the utility segment increased $21.9 million during the first quarter of 2025, compared with the same quarter in 2024. The significant factors impacting the increase in other operating expenses were:

•An $11.3 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.


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•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 $4.2 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $3.0 million increase in benefit costs, primarily driven by higher stock-based compensation and deferred compensation expense.

Other Income, Net

Other income, net at the utility segment decreased $5.5 million during the first quarter of 2025, compared with the same quarter in 2024, driven by an $11.2 million negative impact from the non-service components of our net periodic pension and OPEB costs. See Note 13, Employee Benefits, for more information on our benefit costs. This decrease was partially offset by a $4.2 million positive impact from higher AFUDC-Equity due to continued capital investment and a $0.9 million increase in interest income.

Interest Expense

Interest expense at the utility segment increased $3.9 million during the first quarter of 2025, compared with the same quarter in 2024, driven by the impact of WE's debt issuances in May and September 2024. These increases were partially offset by lower average short-term debt balances, lower short-term debt interest rates, and higher AFUDC-Debt due to continued capital investment. 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, also partially offset the increase in interest expense.

Income Tax Expense

Income tax expense at the utility segment decreased $0.5 million during the first quarter of 2025, compared with the same quarter in 2024, driven by a $7.9 million increase in PTCs and a $6.3 million positive impact related to the flow through of tax repairs in connection with our rate order approved by the PSCW, effective January 1, 2025. These positive income tax impacts were partially offset by higher pre-tax income.

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 three months ended March 31:


(in millions)	2025		2024		Change in 2025 Over 2024
Cash provided by (used in):
Operating activities	$	391.7	$	369.4	$	22.3
Investing activities	(390.6)		(197.3)		(193.3)
Financing activities	64.0		(164.9)		228.9


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Operating Activities

Net cash provided by operating activities increased $22.3 million during the first quarter of 2025, compared with the same quarter in 2024, driven by:

•A $33.3 million increase in cash driven by collateral received from counterparties during the first quarter of 2025, compared with collateral paid to counterparties during the same quarter in 2024, as well as realized gains on derivative instruments recognized during the first quarter of 2025, compared with realized losses recognized during the same quarter in 2024.

•A $33.0 million increase in cash from higher overall collections from customers during the first quarter of 2025, compared with the same quarter 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 colder winter weather during the first quarter of 2025, compared with the same quarter in 2024.

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

•A $36.6 million decrease in cash related to higher payments for other operation and maintenance expenses. During the first quarter of 2025, our payments were higher for transmission expense, benefit costs, and the timing of payments for accounts payable.

•A $5.5 million decrease in cash from higher payments for interest driven by the issuance of long-term debt in 2024.

•A $4.3 million decrease in cash related to the timing of proceeds from the sale of PTCs to third parties. During the first quarter of 2024, we received proceeds related to an installment sale for PTCs generated in 2023. We did not receive any proceeds from PTC sales during the first quarter of 2025. See Note 9, Income Taxes, and Note 17, Supplemental Cash Flow Information, for more information.

Investing Activities

Net cash used in investing activities increased $193.3 million during the first quarter of 2025, compared with the same quarter in 2024, driven by a $214.9 million increase in cash paid for capital expenditures during the first quarter of 2025, which is discussed in more detail below. This increase in net cash used in investing activities was partially offset by a $26.9 million increase in cash received from ATC during the first quarter of 2025, compared with the same quarter in 2024, for the reimbursement of transmission infrastructure upgrades.

Capital Expenditures

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


(in millions)	2025		2024		Change in 2025 Over 2024
Capital expenditures	$	417.9	$	203.0	$	214.9

The increase in cash paid for capital expenditures during the first quarter of 2025, compared with the same quarter in 2024, was driven by higher payments for renewable energy projects and for our electric distribution system.

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

Financing Activities

Net cash related to financing activities increased $228.9 million during the first quarter of 2025, compared with the same quarter in 2024, driven by equity contributions of $300.0 million received from our parent during the first quarter of 2025, to balance our capital structure. There were no equity contributions received from our parent during the first quarter of 2024. This increase in cash was partially offset by a $68.0 million decrease in cash due to higher net repayments of commercial paper during the first quarter of 2025, compared with the same quarter in 2024.


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Other Significant Financing Activities

For more information on our other significant financing activities, see Note 7, Short-Term Debt and Lines of Credit.

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.

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 16, Commitments and Contingencies.


(in millions)
2025	$	3,047.3	(1)
2026	3,281.2
2027	3,501.6
Total	$	9,830.1

(1)This includes actual capital expenditures incurred through March 31, 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.

WEC Energy Group is committed to investing in solar, wind, battery storage, and natural gas-fired generation. Below are examples of projects that are proposed or currently underway.

•We, along with WPS and an unaffiliated utility, received PSCW approval to acquire and construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system located in Kenosha County, Wisconsin. In December 2024, the construction of the solar portion of Paris was completed. We own 150 MWs of solar generation and will own 82 MWs of battery storage of this project when construction is completed, currently expected to be in 2025. Our share of the cost of this project is estimated to be approximately $452 million.

•We, along with WPS and an unaffiliated utility, received PSCW approval to acquire and construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system located in Rock and Walworth counties, Wisconsin. In March 2025, the construction of the solar portion of Darien was completed. We own 188 MWs of solar generation and will own 56 MWs of battery storage of this project when construction is completed, currently expected to be in 2026. Our share of the cost of this project is estimated to be approximately $473 million.

•We, along with WPS and an unaffiliated utility, received PSCW approval to acquire Koshkonong Solar Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once fully constructed, we will own 225 MWs of solar generation and 124 MWs of battery storage of this project. Our share of the cost of this project is estimated to be approximately $775 million, with construction of the solar portion and battery storage expected to be completed in 2026 and 2027, respectively.

•We plan to enhance fuel flexibility at the coal-fired ERGS units.


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•We, along with WPS and an unaffiliated utility, received PSCW approval to acquire and construct High Noon Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Columbia County, Wisconsin and once fully constructed, we will own 225 MWs of solar generation and 124 MWs of battery storage of this project. Our share of the cost of this project is estimated to be approximately $736 million, with construction expected to be completed in 2027.

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

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

•In April 2024, we filed a request with the PSCW to construct the Rochester Lateral, which would supply additional natural gas service to the OCPP site. The natural gas lateral would be built in Kenosha, Racine, and Milwaukee counties. If approved, the cost of this project is estimated to be approximately $200 million.

•In April 2024, we filed a request with the PSCW to construct an LNG facility which would be located on the OCPP site. If approved, the facility would have a storage capacity of two Bcf and the cost of this project is estimated to be approximately $456 million.

•In September 2024, we, along with WPS and an unaffiliated utility, filed a request with the PSCW to acquire Dawn Harvest Solar Energy Center, a utility-scale solar-powered electric generating facility with a battery energy storage system. If approved, the project will be located in Rock County, Wisconsin and once fully constructed, we will own 120 MWs of solar generation and 50 MWs of battery storage of this project. If approved, our share of the cost of this project is estimated to be approximately $375 million, with construction expected to be completed in 2028.

•In September 2024, we, along with WPS and an unaffiliated utility, filed a request with the PSCW to acquire Saratoga, a utility-scale solar-powered electric generating facility with a battery energy storage system and Ursa, a utility-scale solar-powered electric generating facility. If approved, Saratoga will be located in Wood County, Wisconsin and Ursa will be located in Columbia County, Wisconsin. Once fully constructed, we will own 120 MWs of solar generation and 40 MWs of battery storage of Saratoga and 160 MWs of solar generation of Ursa. If approved, our share of the cost of Ursa is estimated to be approximately $361 million, with construction expected to be completed in 2027. If approved, our share of the cost of Saratoga is estimated to be approximately $361 million, with construction expected to be completed in 2028.

•In September 2024, we, along with WPS and an unaffiliated utility, filed a request with the PSCW to acquire and construct Badger Hollow Wind and to acquire Whitetail, two utility-scale wind-powered electric generating facilities. If approved, Badger Hollow Wind will be located in Iowa and Grant counties, Wisconsin and Whitetail will be located in Grant County, Wisconsin. Once fully constructed, we will own 89 MWs of wind generation of Badger Hollow Wind and 53 MWs of wind generation of Whitetail. If approved, our share of the cost of Badger Hollow Wind is estimated to be $284 million and the cost of Whitetail is estimated to be approximately $178 million, with construction for both projects expected to be completed in 2027.

•In October 2024, we, along with WPS and an unaffiliated utility, filed a request with the PSCW to acquire and construct Good Oak and Gristmill, two utility-scale solar electric generating facilities. If approved, both Good Oak and Gristmill will be located in Columbia County, Wisconsin. Once fully constructed, we will own 78 MWs of solar generation of Good Oak and 53 MWs of solar generation of Gristmill. If approved, our share of the cost of Good Oak is estimated to be $172 million and the cost of Gristmill is estimated to be approximately $116 million, with construction for both projects expected to be completed in 2028.

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.

As part of WEC Energy Group's capital plan, we plan to build additional natural gas-fired combustion turbines capable of producing approximately 675 MWs at an estimated cost of $960 million. In addition, we, along with WPS, plan to add natural gas-fired RICE units that would be capable of producing approximately 114 MWs at an estimated cost of $250 million.


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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 related USITC and DOC investigations, and CBP actions, respectively. The expected in-service dates and costs identified above already reflect some of these impacts.

Long-Term Debt

There were no material changes in our outstanding long-term debt during the three months ended March 31, 2025.

Common Stock Dividends

During the three months ended March 31, 2025, we paid common stock dividends of $60.0 million to the sole holder of our common stock, WEC Energy Group.

Other Significant Cash Requirements

See Note 16, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the three months ended March 31, 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 7, Short-Term Debt and Lines of Credit, Note 12, Guarantees, and Note 15, 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


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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 March 31, 2025, our current liabilities sometimes exceed our current assets. If this occurs, we do not expect that it would have any impact on our liquidity, as we currently believe that our cash and cash equivalents, our available capacity under our existing revolving credit facility, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

See Note 7, 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 March 31, 2025, we were in compliance with all such covenants. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, 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 March 31, 2025. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If we had a sub-investment grade credit rating at March 31, 2025, we could have been required to post $106 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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 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 January 2025, the Department of Homeland Security announced the addition of several more Chinese businesses to the UFLPA, including five 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

In August 2023, the DOC issued a final decision regarding an AD/CVD petition filed by a California-based company finding that Chinese manufacturers were shifting products to four Southeast Asian countries to avoid tariffs required on products imported from China. The DOC applied duties to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia, starting on June 6, 2024. In addition, in response to its findings, the DOC promulgated new regulations that imposed enhanced duties in certain circumstances, including when the USITC determines there is a reasonable indication the domestic solar industry is materially or potentially injured because of imported products that violate certain fair trade laws.

In April 2024, a coalition of several U.S. producers of solar panels filed a new petition with the DOC 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. In response to the petition, the DOC and USITC initiated new AD/CVD investigations of solar panels from the four Southeast Asian countries to determine whether there was a reasonable indication imports of such solar panels were causing injury to the U.S. solar industry. Based on the USITC’s preliminary affirmative determination, the DOC began AD/CVD investigations and, in the fall of 2024, announced preliminary affirmative determinations and set preliminary duties on imports from the four Southeast Asian countries. As a result of these preliminary 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.

On April 21, 2025, the DOC announced its final affirmative determinations in its AD/CVD investigations, increasing the preliminary tariff rates, in some cases significantly. These increased rates will become effective if the USITC also issues a final affirmative determination. The USITC’s final determination is anticipated to be issued in June 2025. We are currently evaluating the potential impact, if any, of the increased rates.

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.


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Under the IRA transferability option, WEC Energy Group entered into an agreement in October 2024 to sell the majority of our 2025 PTCs to a third party, and in April 2025, WEC Energy Group entered into an agreement to sell the majority of our 2026 PTCs. See Note 9, 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 new 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 new 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. The executive order did not impact the IRA's provisions for tax credits and the transferability option.

Environmental Matters

See Note 16, 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 inflation and supply chain disruptions described below. In addition, there is continuing uncertainty over the impact that the ongoing regional conflicts, including those in Ukraine, Israel and in other parts of the Middle East, will have on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 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. has recently implemented 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.

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


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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 10, Fair Value Measurements, Note 11, Derivative Instruments, and Note 12, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the first quarter of 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 16, Commitments and Contingencies, and Note 18, 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 16, Commitments and Contingencies, and Note 18, 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

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2024 Annual Report on Form 10-K.

ITEM 5. OTHER INFORMATION

During the three months ended March 31, 2025, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction, or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 of Regulation S-K).


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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














31	Rule 13a-14(a) / 15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data Files

	101.INS	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

	101.SCH	Inline XBRL Taxonomy Extension Schema

	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase

	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase

	101.LAB	Inline XBRL Taxonomy Extension Label Linkbase

	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase

104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


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SIGNATURE

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


		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	May 7, 2025	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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