wep-20260331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2026


☐			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, 2026

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

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2026

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 6

Property, Plant, and Equipment

Note 7

Common Equity

Note 8

Short-Term Debt and Lines of Credit

Note 9

Long-Term Debt

Note 10

Materials, Supplies, and Inventories

Note 11

Income Taxes

Note 12

Fair Value Measurements

Note 13

Derivative Instruments

Variable Interest Entities

Note 18

Commitments and Contingencies

Note 19

Supplemental Cash Flow Information

Note 20

Regulatory Environment

Note 21

Other Income, Net

Note 22

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

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
BTA						Best Technology Available
CAA						Clean Air Act
CCR						Coal Combustion Residuals
CO2						Carbon Dioxide
CRL						Combustion Residual Leachate
ELG						Steam Electric Effluent Limitation Guidelines
GHG						Greenhouse Gas
GHG Power Plant Rule						2024 Greenhouse Gas Power Plant Rule
MATS						Mercury and Air Toxics Standards
NAAQS						National Ambient Air Quality Standards
NOx						Nitrogen Oxide
PCCC						Permanent Cessation of Coal Combustion
PM						Particulate Matter
PM2.5						Particulates Less Than 2.5 Micrometers in Diameter
ZLD						Zero Liquid Discharge

Measurements
Bcf						Billion Cubic Feet
Dth						Dekatherm
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
Chicago, IL-IN-WI						Chicago, Illinois, Indiana, and Wisconsin
CODM						Chief Operating Decision Maker


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CT						Combustion Turbine
CVD						Countervailing Duty
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
ERGS						Elm Road Generating Station
ETB						Environmental Trust Bond
Exchange Act						Securities Exchange Act of 1934, as amended
FTR						Financial Transmission Right
IRA						Inflation Reduction Act
ITC						Investment Tax Credit
LDC						Local Natural Gas Distribution Company
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.
OBBBA						One Big Beautiful Bill Act
OCPP						Oak Creek Power Plant
PPA						Power Purchase Agreement
PTC						Production Tax Credit
RNG						Renewable Natural Gas
ROE						Return on Equity
S&P						Standard & Poor's
Supreme Court						United States Supreme Court
UFLPA						Uyghur Forced Labor Prevention Act
VLC						Very Large Customer


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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 2025 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, changes in economic conditions, including continued economic growth, customer growth and declines, including our ability to develop and/or acquire new generation to meet demand from data centers and other large customers and uncertainty regarding the projected demand from these customers, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers or co-location of generation near data centers;

•The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;

•The impact of federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, the results of rate orders, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, changes to address energy affordability concerns, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, electrification initiatives and other efforts to reduce the use of natural gas, and tax laws, including those that affect our ability to use PTCs and ITCs, as well as changes in the interpretation and/or enforcement of any laws or regulations by regulatory agencies;

•Federal, state, and local legislative and regulatory changes relating to the environment, including changing environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in and uncertainty regarding the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

•The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

•The timely completion of capital projects within budgets and the ability to recover the related costs through rates;

•The impact of changing expectations and demands of our customers, regulators, investors, and other stakeholders;

•The risk of delays and shortages, and increased costs of equipment, materials, or other resources that are critical to our business operations and corporate strategy, as a result of changes to United States trade policy (including changes to tariffs on imports, port fees, and other trade policy tools) as well as changes to foreign governments' trade policies impacting United States exports, supply chain disruptions (including from rail congestion), inflation, and other factors;


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

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

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

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

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

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

•Any impacts on the global economy, including from sanctions, and impacts on supply chains and fuel prices, generally, from increasing tensions between the United States and other countries, such as the war with Iran, or from other new, protracted or escalating regional or international conflicts;

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

•Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

•The direct or indirect effect on our business resulting from terrorist or other physical attacks and cybersecurity intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;

•The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;

•Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including data centers and other large-scale customers, participants in the energy trading markets and fuel suppliers and transporters;

•The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

•Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

•Advances in technology, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;

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


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

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

•The timing and outcome of any audits, disputes, and other proceedings related to taxes;

•The effect of accounting pronouncements issued periodically by standard-setting bodies; and

•Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

Except as may be required by law, we expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.


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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)		2026		2025
Operating revenues		$	1,323.5	$	1,179.1

Operating expenses
Cost of sales		481.6		399.6
Other operation and maintenance		284.2		252.1
Depreciation and amortization		165.4		150.9
Property and revenue taxes		34.0		30.9
Total operating expenses		965.2		833.5

Operating income		358.3		345.6

Other income, net		31.3		10.8
Interest expense		123.7		124.7
Other expense		(92.4)		(113.9)

Income before income taxes		265.9		231.7
Income tax expense		30.4		35.3
Net income		235.5		196.4

Preferred stock dividend requirements		0.3		0.3
Net income attributed to common shareholder		$	235.2	$	196.1

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, 2026		December 31, 2025
Assets
Current assets

Accounts receivable and unbilled revenues, net of reserves of $38.8 and $39.7, respectively	$	670.2	$	742.2
Accounts receivable from related parties	108.0		120.5
Materials, supplies, and inventories	296.3		322.7
Prepaid taxes	84.3		115.8
Other prepayments	25.4		30.1

Other	38.0		24.3
Current assets	1,222.2		1,355.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $6,494.6 and $6,373.9, respectively	15,590.9		15,208.6
Regulatory assets (March 31, 2026 and December 31, 2025 include $65.5 and $67.5, respectively, related to WEPCo Environmental Trust)	2,928.1		2,941.0
Pension and OPEB assets	106.8		105.8
Other	91.4		85.4
Long-term assets	18,717.2		18,340.8
Total assets	$	19,939.4	$	19,696.4

Liabilities and Equity
Current liabilities
Short-term debt	$	135.0	$	680.6
Current portion of long-term debt (March 31, 2026 and December 31, 2025 include $9.3 related to WEPCo Environmental Trust)	9.3		9.3
Current portion of finance lease obligations	118.1		113.4
Accounts payable	382.4		530.8
Accounts payable to related parties	215.1		214.7
Accrued taxes	55.1		19.9
Accrued payroll and benefits	52.4		54.5
Accrued interest	69.5		31.9
Other	67.1		126.0
Current liabilities	1,104.0		1,781.1

Long-term liabilities
Long-term debt (March 31, 2026 and December 31, 2025 include $67.4 related to WEPCo Environmental Trust)	4,813.2		4,516.0
Finance lease obligations	2,710.9		2,715.4
Deferred income taxes	1,693.2		1,666.6
Regulatory liabilities	1,771.7		1,759.0

Other	486.2		478.7
Long-term liabilities	11,475.2		11,135.7

Commitments and contingencies (Note 18)

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	4,354.0		3,948.6
Retained earnings	2,642.9		2,467.7
Common shareholder's equity	7,329.8		6,749.2

Preferred stock	30.4		30.4
Total liabilities and equity	$	19,939.4	$	19,696.4

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)	2026		2025
Operating activities
Net income	$	235.5	$	196.4
Reconciliation to cash provided by operating activities
Depreciation and amortization	165.4		150.9
Deferred income taxes and ITCs, net	(4.9)		(38.1)


Change in –
Accounts receivable and unbilled revenues, net	74.9		1.0
Materials, supplies, and inventories	26.4		49.8
Prepaid taxes	31.5		52.4



Other current assets	(9.5)		1.3
Accounts payable	(72.6)		(120.2)
Accrued taxes	35.2		50.2

Accrued interest	37.6		33.2

Other current liabilities	(50.7)		6.2
Other, net	12.5		8.6
Net cash provided by operating activities	481.3		391.7

Investing activities
Capital expenditures	(531.1)		(417.9)



Reimbursement for ATC's transmission infrastructure upgrades	—		33.1




Other, net	(15.0)		(5.8)
Net cash used in investing activities	(546.1)		(390.6)

Financing activities
Change in short-term debt	(545.6)		(151.9)
Issuance of long-term debt	299.4		—

Payments for finance lease obligations	(27.7)		(23.8)
Equity contribution from parent	405.0		300.0
Payment of dividends to parent	(60.0)		(60.0)
Other, net	(3.7)		(0.3)
Net cash provided by financing activities	67.4		64.0

Net change in cash, cash equivalents, and restricted cash	2.6		65.1
Cash, cash equivalents, and restricted cash at beginning of period	2.6		2.5
Cash, cash equivalents, and restricted cash at end of period	$	5.2	$	67.6

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 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, 2025	$	332.9	$	3,948.6	$	2,467.7	$	6,749.2	$	30.4	$	6,779.6
Net income attributed to common shareholder	—		—		235.2		235.2		—		235.2
Payment of dividends to parent	—		—		(60.0)		(60.0)		—		(60.0)
Equity contribution from parent	—		405.0		—		405.0		—		405.0
Stock-based compensation and other	—		0.4		—		0.4		—		0.4
Balance at March 31, 2026	$	332.9	$	4,354.0	$	2,642.9	$	7,329.8	$	30.4	$	7,360.2


	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

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, 2026

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, 2025. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2026, are not necessarily indicative of expected results for 2026 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITIONS

Pending Acquisitions of Electric Generation Facilities in Wisconsin

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

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


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NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source 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)	2026		2025
Wisconsin Electric Power Company
Electric utility	$	1,015.7	$	935.3
Natural gas utility	298.1		240.8
Total revenues from contracts with customers	1,313.8		1,176.1
Other operating revenues	9.7		3.0
Total operating revenues	$	1,323.5	$	1,179.1

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2026		2025
Residential	$	420.5	$	401.9
Small commercial and industrial	329.0		306.9
Large commercial and industrial	167.6		145.0
Other	5.6		5.7
Total retail revenues	922.7		859.5
Wholesale	14.4		14.1
Resale	63.6		48.6
Steam	13.8		12.5
Other utility revenues	1.2		0.6
Total electric utility operating revenues	$	1,015.7	$	935.3

Natural Gas Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2026		2025
Residential	$	190.1	$	169.1
Commercial and industrial	85.4		77.9
Total retail revenues	275.5		247.0
Transportation	8.6		8.0
Other utility revenues (1)	14.0		(14.2)
Total natural gas utility operating revenues	$	298.1	$	240.8

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


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Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)	2026		2025
Bespoke resources current return (1)	$	4.3	$	—
Late payment charges	3.7		3.3
Rental revenues	1.3		0.3
Alternative revenues (2)	0.4		(0.6)
Total other operating revenues	$	9.7	$	3.0

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

(2) Alternative revenues consist of amounts to be recovered or refunded to customers subject to wholesale true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

NOTE 4—CREDIT LOSSES

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at March 31, 2026 and December 31, 2025.

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

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by the PSCW, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, to mitigate credit risk.

We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses.


(in millions)	March 31, 2026			December 31, 2025
Accounts receivable and unbilled revenues	$	709.0		$	781.9
Allowance for credit losses	38.8			39.7
Accounts receivable and unbilled revenues, net (1)	$	670.2		$	742.2

Total accounts receivable, net – past due greater than 90 days (1)	$	34.5		$	33.0
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	96.5		%	94.5		%

(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, 2026, $419.7 million, or 62.6%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.


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


	Three Months Ended March 31
(in millions)	2026		2025
Balance at January 1	$	39.7	$	46.9
Provision for credit losses	44.3		12.7
Provision for credit losses deferred for future recovery or refund	(27.6)		(6.0)
Write-offs charged against the allowance	(26.5)		(23.2)
Recoveries of amounts previously written off	8.9		7.5
Balance at March 31	$	38.8	$	37.9

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.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2026 and December 31, 2025. For more information on our regulatory assets and liabilities, see Note 7, Regulatory Assets and Liabilities, in our 2025 Annual Report on Form 10-K.


(in millions)	March 31, 2026		December 31, 2025
Regulatory assets
We Power finance leases	$	1,161.9	$	1,158.6
Plant retirement related items	623.3		634.3
Income tax related items	429.7		413.3
Pension and OPEB costs	280.3		289.0
System support resource	90.1		92.6
Uncollectible expense	87.1		114.7
Securitization	65.5		67.5
Asset retirement obligations	62.4		59.7
Other finance and operating leases	28.9		25.2
Electric transmission costs	22.6		15.3
Bluewater Natural Gas Holding, LLC	12.8		13.9
Other, net	63.5		56.9
Total regulatory assets	$	2,928.1	$	2,941.0


(in millions)	March 31, 2026		December 31, 2025
Regulatory liabilities
Removal costs	$	877.5	$	862.1
Income tax related items	656.5		663.5
Pension and OPEB benefits	113.3		114.6
Energy costs refundable through rate adjustments	48.1		47.2
Earnings sharing mechanism	28.5		29.3
Other, net	50.0		57.9
Total regulatory liabilities	$	1,773.9	$	1,774.6

Balance sheet presentation
Other current liabilities	$	2.2	$	15.6
Regulatory liabilities	1,771.7		1,759.0
Total regulatory liabilities	$	1,773.9	$	1,774.6


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NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Plant to be Retired

Oak Creek Power Plant Units 7-8

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

The total net book value of our ownership share of OCPP Units 7 and 8 was $613.3 million at March 31, 2026, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

NOTE 7—COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its other subsidiaries. See Note 11, Common Equity, in our 2025 Annual Report on Form 10-K for additional information on these and other restrictions.

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

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

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


(in millions, except percentages)	March 31, 2026			December 31, 2025
Commercial paper
Amount outstanding	$	135.0		$	680.6
Weighted-average interest rate on amounts outstanding	3.94		%	3.88		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2026 was $445.4 million with a weighted-average interest rate during the period of 3.85%.

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, 2026
Revolving credit facility	August 2030	$	800.0

Less:
Letters of credit issued inside credit facility		1.0
Commercial paper outstanding		135.0
Available capacity under existing credit facility		$	664.0


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NOTE 9—LONG-TERM DEBT

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

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	March 31, 2026		December 31, 2025
Materials and supplies	$	230.2	$	225.2
Fossil fuel	52.6		53.3
Natural gas in storage	13.5		44.2
Total	$	296.3	$	322.7

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

NOTE 11—INCOME TAXES

Statutory Rate Reconciliation

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


	Three Months Ended March 31, 2026				Three Months Ended March 31, 2025
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Income before income taxes	$	265.9			$	231.7
United States federal statutory income tax rate	$	55.8	21.0	%	$	48.6	21.0	%
State and local income taxes net of federal tax effect (1)	13.4		5.1	%	14.1		6.1	%
Tax credits
PTCs, net (2)	(14.0)		(5.3)	%	(13.0)		(5.6)	%
Other	(1.6)		(0.6)	%	(1.1)		(0.5)	%
Nontaxable or nondeductible items
AFUDC-Equity (3)	(12.4)		(4.7)	%	(5.0)		(2.2)	%
Other	2.1		0.8	%	1.1		0.5	%
Other adjustments
Federal excess deferred tax amortization (4)	(6.8)		(2.6)	%	(7.0)		(3.0)	%
Tax repairs (5)	(5.1)		(1.9)	%	(5.2)		(2.2)	%
Other, net	(1.0)		(0.4)	%	2.8		1.1	%
Total income tax expense	$	30.4	11.4	%	$	35.3	15.2	%

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

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

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

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

(5) Amounts reflect the net benefit related to the flow through of tax repairs in connection with various rate orders.


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The IRA contains a tax credit transferability provision that allows us to sell PTCs and ITCs produced after December 31, 2022, to third parties. Under this transferability provision, WEC Energy Group entered into agreements to sell the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties. WEC Energy Group has also entered into an agreement to sell the majority of PTCs that we expect to generate in 2026 to third parties. We elect to account for tax credits transferred under the scope of 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 and ITCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

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

NOTE 12—FAIR VALUE MEASUREMENTS

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

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives, such as FTRs, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our FTRs are valued using MISO auction prices.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:


	March 31, 2026
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.6	$	1.5	$	—	$	2.1
FTRs	—		—		1.1		1.1
Total derivative assets	$	0.6	$	1.5	$	1.1	$	3.2

Derivative liabilities
Natural gas contracts	$	10.1	$	0.4	$	—	$	10.5


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

Derivative liabilities
Natural gas contracts	$	5.9	$	1.8	$	—	$	7.7

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)	2026		2025
Balance at the beginning of the period	$	2.9	$	2.9

Sales	(0.1)		—
Settlements	(1.7)		(1.8)
Balance at the end of the period	$	1.1	$	1.1

Fair Value of Financial Instruments

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


	March 31, 2026				December 31, 2025
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	21.6	$	30.4	$	21.2
Long-term debt, including current portion	4,822.5		4,661.1		4,525.3		4,434.6

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

NOTE 13—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.


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On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities are included in the other current and other long-term line items on our balance sheets. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments.


	March 31, 2026				December 31, 2025
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	2.1	$	10.3	$	3.3	$	7.4
FTRs	1.1		—		2.9		—
Total current	3.2		10.3		6.2		7.4

Long-term
Natural gas contracts	—		0.2		—		0.3

Total	$	3.2	$	10.5	$	6.2	$	7.7

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


	Three Months Ended March 31, 2026			Three Months Ended March 31, 2025
(in millions)	Volumes	Gains (Losses)		Volumes	Gains
Natural gas contracts	18.9 Dth	$	9.4	18.2 Dth	$	1.5
FTRs	3.8 MWh	(0.1)		4.7 MWh	1.0
Total		$	9.3		$	2.5

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2026 and December 31, 2025, we had posted cash collateral of $27.3 million and $12.2 million, respectively. These amounts were recorded on our balance sheets in other current assets.

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


	March 31, 2026					December 31, 2025
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	3.2	$	10.5		$	6.2	$	7.7
Gross amount not offset on the balance sheet	(0.6)		(10.1)		(1)	(0.3)		(6.1)		(2)
Net amount	$	2.6	$	0.4		$	5.9	$	1.6

(1) Includes cash collateral posted of $9.5 million.

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

NOTE 14—GUARANTEES

As of March 31, 2026, we had $27.5 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, of which $27.4 million automatically renews each year unless proper termination notice is given and $0.1 million expires in less than one year. These amounts are not reflected on our balance sheets.


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NOTE 15—EMPLOYEE BENEFITS

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


		Pension Benefits
	Three Months Ended March 31
(in millions)			2026		2025
Service cost			$	2.7	$	2.6
Interest cost			10.9		11.7
Expected return on plan assets			(14.2)		(14.8)


Amortization of net actuarial loss			4.6		4.3
Net periodic benefit cost			$	4.0	$	3.8


		OPEB Benefits
	Three Months Ended March 31
(in millions)			2026		2025
Service cost			$	1.0	$	0.9
Interest cost			2.5		2.4
Expected return on plan assets			(2.7)		(2.7)
Amortization of prior service credit			(0.1)		—
Amortization of net actuarial gain			(0.6)		(0.8)
Net periodic benefit cost (credit)			$	0.1	$	(0.2)

During the three months ended March 31, 2026, we made contributions and payments of $0.9 million related to our pension plans and an insignificant amount related to our OPEB plans. During the remainder of 2026, we expect to make contributions and payments of $2.1 million related to our pension plans and $0.3 million related to our OPEB plans, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

We utilize escrow accounting for our current pension and OPEB costs, as approved by the PSCW. As of March 31, 2026 and December 31, 2025, our balance sheets included regulatory liabilities of $9.2 million and $9.8 million, respectively, for pension costs and regulatory assets of $7.4 million and $1.0 million, respectively, for OPEB costs. In accordance with our PSCW rate orders, we amortize the related regulatory assets and liabilities. The above tables do not reflect any adjustments for the creation or amortization of these regulatory assets and liabilities.

NOTE 16—SEGMENT INFORMATION

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

Our CODM allocates resources, such as employees, as well as financial and capital resources, to our segments during the annual review of budgets and the capital plan. Our CODM also reviews and revises the resources throughout the year during the monthly forecasting process in order to make timely decisions that align with our overall corporate strategy. The CODM uses each segment’s net income to evaluate performance by comparing actual results to budgeted and forecasted amounts, as well as the ROE earned.

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, as well as the revenue streams for the products or services provided to customers through electric and natural gas operations. See Note 3, Operating Revenues, for more information on disaggregation of operating revenues. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies, in our 2025 Annual Report on Form 10-K.

At March 31, 2026, we reported two segments, our utility segment and our other segment, which are described below. All of our operations are located within the United States.


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

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

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

No significant items were reported in the other segment during the three months ended March 31, 2026 and 2025.

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, 2026 and 2025.


	Three Months Ended March 31
(in millions)	2026		2025
Fuel and purchased power	$	309.8	$	276.2
Cost of natural gas sold	171.8		123.4

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 17—VARIABLE INTEREST ENTITIES

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

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

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the use of securitization to recover $100 million of undepreciated environmental control costs related to our retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized us to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is our wholly owned subsidiary.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from us. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from our retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders do not have any recourse to us or any of our affiliates.

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


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interest, and other ongoing financing costs. We remit all collections of the environmental control charge to WEPCo Environmental Trust's indenture trustee.

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

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


(in millions)	March 31, 2026		December 31, 2025
Assets
Other current assets (restricted cash)	$	4.6	$	2.0
Regulatory assets	65.5		67.5
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.3		9.3
Accounts payable	0.1		0.1
Accrued interest	0.4		0.1
Long-term debt	67.4		67.4

NOTE 18—COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2026, were approximately $8.1 billion.

Environmental Matters

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

Federal Deregulatory Actions

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

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


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Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

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

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

Mercury and Air Toxics Standards

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

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

National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. The EPA's initial ozone nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status based on the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 2022.

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

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

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

Particulate Matter

All counties within our service territory are currently in attainment with current 2012 NAAQS for PM2.5. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS from 12 µg/m3 to 9 µg/m3 (the "2024 PM2.5 Standard"). In February 2025, the Wisconsin Department of Natural Resources submitted a State Implementation Plan to the EPA recommending Wisconsin be designated as an attainment area under the 2024 PM2.5 Standard. The EPA has not yet issued its attainment designations and has indicated it may extend the designation period by 1 year due to a lack of adequate air monitoring data. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including


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the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect the 2024 PM2.5 Standard to have a material impact on our units.

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

New Source Performance Standards

Nitrogen Oxides

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

Climate Change

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

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

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

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

WEC Energy Group's capital plan includes the planned retirement of older, fossil-fueled generation, to be replaced with natural gas-fired generation and zero-carbon-emitting renewables. We have retired nearly 2,100 MWs of fossil-fueled generation since the beginning of 2018. WEC Energy Group expects to retire approximately 900 MWs of additional coal-fired generation by the end of 2031. See Note 6, Property, Plant, and Equipment, for more information related to our planned power plant retirements. WEC Energy Group has a long-term goal to achieve net carbon-neutral electric generation by the end of 2050. It expects to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. As part of our path toward this goal, we started implementing co-firing with natural gas at the ERGS coal-fired units in 2025. WEC Energy


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Group expects to use coal only as a backup fuel by the end of 2030 and to be in a position to eliminate coal as an energy source by the end of 2032.

WEC Energy Group also continues to focus on methane emission reductions by improving and upgrading its natural gas distribution systems and using RNG throughout its natural gas utility systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

The Clean Water Act Cooling Water Intake Structure Rule requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.

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

Steam Electric Effluent Limitation Guidelines

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

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

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

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

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are working with the state of Wisconsin in our investigation and remediation planning and efforts. These sites are at various stages of investigation, monitoring, remediation, and closure.


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The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

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


(in millions)	March 31, 2026		December 31, 2025
Regulatory assets	$	7.8	$	7.8
Reserves for future environmental remediation (1)	7.7		7.7

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

Coal Combustion Residuals Rule

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

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

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

Enforcement and Litigation Matters

We 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 19—SUPPLEMENTAL CASH FLOW INFORMATION

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


	Three Months Ended March 31
(in millions)	2026		2025
Cash paid for interest, net of amount capitalized	$	85.0	$	90.3
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	116.5		94.3


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Cash, Cash Equivalents, and Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. At March 31, 2026 and December 31, 2025, we had no cash and cash equivalents on our balance sheets. The following table reconciles the restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:


(in millions)	March 31, 2026		December 31, 2025

Restricted cash included in other current assets	$	4.6	$	2.0
Restricted cash included in other long-term assets	0.6		0.6
Restricted cash	$	5.2	$	2.6

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 17, Variable Interest Entities, for more information.

NOTE 20—REGULATORY ENVIRONMENT

2027 and 2028 Rate Case

On April 1, 2026, we filed a request with the PSCW to increase our retail electric, natural gas, and steam rates effective January 1, 2027 and January 1, 2028. The request reflected the following:



Proposed 2027 rate increase
Electric (2)	$	175.8	million	/	4.7%
Gas (3)	$	2.1	million	/	0.3%
Steam	$	0.1	million	/	0.2%
Proposed 2028 rate increase (1)
Electric (2)	$	179.5	million	/	4.5%
Gas (3)	$	33.3	million	/	4.9%
Steam	$	1.2	million	/	3.8%
Proposed ROE	9.9%
Proposed common equity component average on a financial basis	53.5%

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

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

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

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

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

We also proposed retaining our current earnings sharing mechanism, under which, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 25 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

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


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Very Large Customer and Bespoke Resources Tariffs

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

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

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

NOTE 21—OTHER INCOME, NET

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


(in millions)	2026		2025
AFUDC-Equity	$	36.3	$	12.9
Interest income	0.4		2.2
Non-service components of net periodic benefit costs	(5.4)		(4.6)
Other, net	—		0.3
Other income, net	$	31.3	$	10.8

NOTE 22—NEW ACCOUNTING PRONOUNCEMENTS

Improvements to Interim Reporting

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

Accounting for Government Grants

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


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annual periods, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Disaggregation of Income Statement Expenses

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


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

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our 2025 Annual Report on Form 10-K.

Introduction

We are a 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 16, Segment Information, for more information on our reportable business segments.

Corporate Strategy

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

Throughout its strategic planning process, WEC Energy Group takes into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability.

Supporting Economic Growth Within Our Communities

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

To meet the forecasted electric demand growth in the years ahead, greater capacity will be required to provide affordable, reliable, and clean energy for our communities. WEC Energy Group's capital plan addresses that demand with a range of planned investments in natural gas-fired generation, renewables, and battery storage. WEC Energy Group plans on investing approximately $5.4 billion from 2026 to 2030 in a combination of efficient natural gas-fired generation, including the following investments to be made by either us or WPS based on specific customer needs:

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

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

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

•3,850 MWs of utility-scale solar;

•2,130 MWs of battery storage; and

•555 MWs of wind.


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

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

As part of our path toward this goal, we have started implementing co-firing with natural gas at the ERGS coal-fired units. Additionally, WEC Energy Group has retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle power plant, and the 2018 retirement of the Pleasant Prairie power plant. WEC Energy Group expects to retire approximately 900 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirement of OCPP Units 7 and 8. See Note 6, Property, Plant, and Equipment, for more information related to the planned retirement of OCPP Units 7 and 8.

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

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

Reliability

We have made significant reliability-related investments in recent years, and in accordance with the WEC Energy Group capital plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.

Below are a few of the more significant projects that are proposed, currently underway, or recently completed.

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

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

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

WEC Energy Group expects to spend approximately $7.1 billion and $4.7 billion on reliability related to natural gas and electric distribution projects, respectively, from 2026 to 2030, with continued investment over the next decade. For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the WEC Energy Group capital plan. For example, we are making progress on our advanced metering infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks,


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and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for customer connections and enhances outage management capabilities.

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

WEC Energy Group continues to focus on integrating the resources of all its businesses and improving its business processes to find the best and most efficient processes possible, including evaluating the use of AI tools. WEC Energy Group expects these efforts to continue to drive operational efficiency and to put it in a position to effectively support plans for future growth.

Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, and quality credit ratings. We work to earn allowed rates of return through a focus on cost control and strategic investment.

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

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

A multiyear effort is driving a standardized, seamless approach to digital customer service across all of the WEC Energy Group companies. It has moved all utilities, including us, to a common platform for all customer-facing self-service options. Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service to customers.

Safety

Safety is one of our core values and a critical component of our culture. We are committed to keeping our employees and the public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors. To further protect public safety, we monitor the integrity of our distribution systems, have emergency response and business continuity plans in place, and provide key safety information to customers, contractors, and first responders.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across the WEC Energy Group companies.

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, 2026

Earnings

Our earnings for the first quarter of 2026 were $235.2 million, compared with $196.1 million for the same quarter in 2025. See below for information on the $39.1 million increase in earnings.

Expected 2026 Annual Effective Tax Rate

We expect our 2026 annual effective tax rate to be between 11.0% and 12.0%. 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 attributed to common shareholder for the first quarter of 2026, with the same quarter in 2025, including favorable or better, "B", and unfavorable or worse, "W", variances.


	Three Months Ended March 31
(in millions)	2026		2025		B (W)
Operating revenues	$	1,323.5	$	1,179.1	$	144.4

Operating expenses
Cost of sales (1)	481.6		399.6		(82.0)
Other operation and maintenance	284.2		252.1		(32.1)
Depreciation and amortization	165.4		150.9		(14.5)
Property and revenue taxes	34.0		30.9		(3.1)
Operating income	358.3		345.6		12.7

Other income, net	31.3		10.8		20.5
Interest expense	123.7		124.7		1.0
Income before income taxes	265.9		231.7		34.2

Income tax expense	30.4		35.3		4.9
Preferred stock dividend requirements	0.3		0.3		—
Net income attributed to common shareholder	$	235.2	$	196.1	$	39.1

(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)	2026		2025		B (W)
Operation and maintenance not included in line items below	$	90.3	$	95.1	$	4.8
Transmission (1)	102.5		94.5		(8.0)
Regulatory amortizations and other pass through expenses (2)	60.8		30.7		(30.1)
We Power (3)	31.4		32.6		1.2
Earnings sharing mechanism	(0.8)		(0.8)		—
Total other operation and maintenance	$	284.2	$	252.1	$	(32.1)

(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 2026 and 2025, $107.2 million and $95.6 million, respectively, of costs were billed to us by transmission providers.

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

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


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


	Three Months Ended March 31
Electric Sales Volumes (MWh - in thousands)	2026	2025	B (W)
Customer Class
Residential	1,954.5	1,954.7	(0.2)
Small commercial and industrial	2,170.0	2,155.1	14.9
Large commercial and industrial	1,656.1	1,551.2	104.9
Other	25.1	27.2	(2.1)
Total retail	5,805.7	5,688.2	117.5
Wholesale	191.2	199.9	(8.7)
Resale	657.3	1,012.3	(355.0)
Total sales in MWh	6,654.2	6,900.4	(246.2)


	Three Months Ended March 31
Natural Gas Sales Volumes (Therms - in millions)	2026	2025	B (W)
Customer Class
Residential	177.7	185.8	(8.1)
Commercial and industrial	99.7	104.2	(4.5)
Total retail	277.4	290.0	(12.6)
Transportation	84.6	85.2	(0.6)
Total sales in therms	362.0	375.2	(13.2)


	Three Months Ended March 31
Weather (Degree Days) (1)	2026	2025	B (W)
Heating (3,214 Normal)	3,153	3,283	(4.0)	%

(1)Normal degree days are based on a 20-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations within our service territory.


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Gross Margin GAAP and Utility Margin Non-GAAP

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


	Three Months Ended March 31
(in millions)	2026		2025		B (W)
Electric revenues	$	1,024.8	$	937.8	$	87.0
Natural gas revenues	298.7		241.3		57.4
Operating revenues	1,323.5		1,179.1		144.4

Operating expenses
Fuel and purchased power	(309.8)		(276.2)		(33.6)
Cost of natural gas sold	(171.8)		(123.4)		(48.4)
Other operation and maintenance (1)	(196.8)		(189.3)		(7.5)
Depreciation and amortization	(165.4)		(150.9)		(14.5)
Property and revenue taxes	(34.0)		(30.9)		(3.1)
Gross margin (GAAP)	445.7		408.4		37.3

Other operation and maintenance (1)	196.8		189.3		7.5
Depreciation and amortization	165.4		150.9		14.5
Property and revenue taxes	34.0		30.9		3.1
Utility margin (non-GAAP)	$	841.9	$	779.5	$	62.4

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

Gross margin (GAAP) at the utility segment increased $37.3 million during the first quarter of 2026, compared with the same quarter in 2025, and utility margin (non-GAAP) increased $62.4 million during the first quarter of 2026, compared with the same quarter in 2025. Both measures were driven by:

•A $53.5 million increase in margins driven by the impact of our rate order approved by the PSCW, effective January 1, 2026. See Note 24, Regulatory Environment, in our 2025 Annual Report on Form 10-K, for more information.

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

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

•A $14.5 million increase in depreciation and amortization expense; and

•An $8.0 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 $49.7 million during the first quarter of 2026, compared with the same quarter in 2025. The significant factors impacting the increase in other operating expenses were:

•A $30.1 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

•A $14.5 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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•An $8.0 million increase in transmission expense as approved by the PSCW in our rate order, effective January 1, 2026. See the notes under the other operation and maintenance table above for more information.

Other Income, Net

Other income, net at the utility segment increased $20.5 million during the first quarter of 2026, compared with the same quarter in 2025, driven by a $23.4 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the utility segment decreased $1.0 million during the first quarter of 2026, compared with the same quarter in 2025, driven by AFUDC-Debt that was $9.7 million higher quarter-over-quarter due to continued capital investment and lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made. These decreases were substantially offset by the impact of our long-term debt issuances in September and December 2025 and higher average short-term debt balances.

Income Tax Expense

Income tax expense at the utility segment decreased $4.9 million during the first quarter of 2026, compared with the same quarter in 2025. This decrease was driven by:

•A $7.4 million increase in income tax benefits associated with AFUDC-Equity, driven by continued capital investment; and

•A $3.9 million increase in income tax benefits associated with certain regulatory tax deferral items.

Partially offsetting these favorable income tax variances was higher pre-tax income.

See Note 11, Income Taxes, for more information.

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)	2026		2025		Change in 2026 Over 2025
Cash provided by (used in):
Operating activities	$	481.3	$	391.7	$	89.6
Investing activities	(546.1)		(390.6)		(155.5)
Financing activities	67.4		64.0		3.4

Operating Activities

Net cash provided by operating activities increased $89.6 million during the first quarter of 2026, compared with the same quarter in 2025, driven by a $130.4 million increase in cash from higher overall collections from customers during the first quarter of 2026, compared with the same quarter in 2025. This increase was driven by the impact of our rate order approved by the PSCW, effective January 1, 2026.


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

•A $20.8 million decrease in cash driven by collateral paid to counterparties during the first quarter of 2026, compared with collateral received from counterparties during the same quarter in 2025.

•A $19.2 million decrease in cash related to higher payments for other operation and maintenance expenses. During the first quarter of 2026, our payments were higher due to increased transmission costs, as well as higher payments associated with charitable commitments.

Investing Activities

Net cash used in investing activities increased $155.5 million during the first quarter of 2026, compared with the same quarter in 2025, driven by:

•A $113.2 million increase in cash paid for capital expenditures during the first quarter of 2026, which is discussed in more detail below.

•Proceeds of $33.1 million received for the reimbursement of ATC's transmission infrastructure upgrades during the first quarter of 2025. There were no proceeds received for the reimbursement of ATC's transmission infrastructure upgrades during the same quarter in 2026.

Capital Expenditures

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


(in millions)	2026		2025		Change in 2026 Over 2025
Capital expenditures	$	531.1	$	417.9	$	113.2

The increase in cash paid for capital expenditures during the first quarter of 2026, compared with the same quarter in 2025, was driven by higher payments for the CTs and LNG at OCPP, as well as for renewable energy projects.

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

Financing Activities

Net cash provided by financing activities increased $3.4 million during the first quarter of 2026, compared with the same quarter in 2025, driven by:

•A $299.4 million increase in cash due to the issuance of long-term debt during the first quarter of 2026. There were no issuances of long-term debt during the same quarter in 2025.

•A $105.0 million increase in equity contributions received from our parent during the first quarter of 2026, compared with the same quarter in 2025, to balance our capital structure.

These increases in cash were partially offset by a $393.7 million decrease in cash due to higher net repayments of commercial paper during the first quarter of 2026, compared with the same quarter in 2025.

Other Significant Financing Activities

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


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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 2025 Annual Report on Form 10-K for additional information regarding our significant cash requirements.

Significant Capital Projects

We have several capital projects and acquisitions that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental and regulatory requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, inflation, and interest rates. Our estimated capital expenditures and acquisitions for the next three years are reflected below. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 18, Commitments and Contingencies.


(in millions)
2026	$	3,212.1	(1)
2027	4,670.5
2028	4,666.0
Total	$	12,548.6

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

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


(in millions)	2026		2027		2028
Generation:
Solar	$	596.6	$	1,458.3	$	1,542.9
Wind	143.0		277.1		581.7
Battery	215.5		370.8		251.4
Thermal	878.8		1,345.6		1,206.6
Other	270.0		141.6		189.8
LNG	177.3		81.5		61.8
Distribution:
Electric distribution	702.5		655.6		643.2
Gas distribution	228.4		340.0		188.6
Total	$	3,212.1	$	4,670.5	$	4,666.0

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

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


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Long-Term Debt

See Note 9, Long-Term Debt, for information regarding the changes in our outstanding long-term debt during the three months ended March 31, 2026.

Common Stock Dividends

During the three months ended March 31, 2026, 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 18, Commitments and Contingencies, for information regarding our minimum future commitments related to purchase obligations for the procurement of fuel, power, and natural gas supply, as well as the related storage and transportation. There were no material changes to our other significant commitments outside the ordinary course of business during the three months ended March 31, 2026.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 8, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 17, 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 2026, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals, and other factors. We plan to maintain a capital structure consistent with that approved by the PSCW. For more information on our approved capital structure, see Item 1. Business – C. Regulation in our 2025 Annual Report on Form 10-K.

The issuance of our securities is subject to the approval of the PSCW. Additionally, with respect to the public offering of securities, we file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the PSCW, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

Although not the case as of March 31, 2026, our current liabilities sometimes exceed our current assets. If this occurs, we do not expect that it would have an impact on our liquidity, as we currently believe that our available capacity under our existing revolving 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.


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See Note 8, Short-Term Debt and Lines of Credit, for more information about our credit facility and commercial paper.

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. These trusts have investments consisting of fixed income and equity securities that are subject to the volatility of the stock market and interest rates. For more information, see Investments in Outside Trusts in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Sources of Cash in our 2025 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, 2026, 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 2025 Annual Report on Form 10-K for more information regarding our debt covenants.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of March 31, 2026. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If we had a sub-investment grade credit rating at March 31, 2026, we could have been required to post $109 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. This discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2025 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, competitive markets, environmental and regulatory matters, critical accounting policies and estimates, and other matters.

Regulatory, Legislative, and Legal Matters

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


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States and whether we will experience any further impacts to the timing and cost of our solar projects included in WEC Energy Group's long-term capital plan.

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

United States Department of Commerce Complaints

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

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

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

Renewable Energy Legislation

Infrastructure Investment and Jobs Act

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

Inflation Reduction Act

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


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Under the IRA transferability option, WEC Energy Group entered into agreements in April 2025 and September 2025 to sell the majority of the PTCs and ITCs we generated, or expect to generate, in 2026 to third parties. See Note 11, Income Taxes, for more information about these sales. The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases. Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us.

One Big Beautiful Bill Act

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

Environmental Matters

See Note 18, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Market Risks and Other Significant Risks

We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the risks described below. In addition, there is continuing uncertainty over the impact of increasing tensions between the United States and other countries and new, protracted or escalating regional and international conflicts on the global economy, supply chains, and fuel prices. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2025 Annual Report on Form 10-K for a discussion of market and other significant risks applicable to us.

Changes to United States Trade Policy (Tariff Activity)

The United States continues to implement changes to its international trade policy including changes to tariffs, port fees and other policies relating to exports from and imports into the United States. In response to these changes, foreign governments also continue to adjust their trade policies, including the imposition of additional tariffs. There remains significant uncertainty as to the ultimate scope of the United States and foreign trade policies. Both the United States and foreign trade policy changes could increase the cost of materials or disrupt supply chains, which could impact our ability to repair or maintain our infrastructure; the timing, cost or completion of our infrastructure projects; and/or our ability to execute 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.

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

Inflation and Supply Chain Disruptions

We continue to monitor the impact of inflation and supply chain disruptions. We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions. We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the materials and


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other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with WEC Energy Group's capital plan. For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below that are disclosed in Part I of our 2025 Annual Report on Form 10-K.

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

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

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our 2025 Annual Report on Form 10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 12, Fair Value Measurements, Note 13, Derivative Instruments, and Note 14, Guarantees, in this report for information concerning our market risk exposures.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the first quarter of 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2025 Annual Report on Form 10-K. See Note 18, Commitments and Contingencies, and Note 20, 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 18, Commitments and Contingencies, and Note 20, Regulatory Environment, we currently, and from time to time, are subject to claims and suits arising in the ordinary course of business. Although the results of these additional legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in Item 1A. Risk Factors in Part I of our 2025 Annual Report on Form 10-K.

ITEM 5. OTHER INFORMATION

During the three months ended March 31, 2026, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction, or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 of Regulation S-K).


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ITEM 6. EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company (File No. 001-01245). An asterisk (*) indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference.

Number	Exhibit
4	Instruments Defining the Rights of Security Holders, Including Indentures

	4.1*	Securities Resolution No. 25 of Wisconsin Electric Power Company, effective as of March 10, 2026, under the Indenture for Debt Securities, dated as of December 1, 1995, between Wisconsin Electric Power Company and U.S. Bank Trust Company, National Association (as successor to Firstar Trust Company), as Trustee. (Exhibit 4.1 to WE's Form 8-K filed March 13, 2026) (File No. 1-1245.)











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, 2026	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)


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