What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2026-02-20 compared with 2025-02-21 · 733 added, 651 removed, 2313 unchanged (37% of the section changed)

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Critical Audit Matter Description

The Company’s regulated utilities are subject to regulation by various state and federal regulatory bodies (collectively the “Commissions”) which have jurisdiction with respect to the rates of electric and gas distribution companies in each respective state.

Management has determined the Company meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the Regulated Operations Topic of the Financial Accounting Standards Board’s Accounting Standard Codification.

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How the Critical Audit Matter Was Addressed in the Audit

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

• We tested the effectiveness of management’s controls over regulatory assets and liabilities, including management’s controls over the identification of costs recorded as regulatory assets and liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates.

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

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

We also tested the effectiveness of management’s controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

• We inquired of Company management and independently obtained and read:

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To assess completeness, we evaluated the information obtained and compared it to management’s recorded regulatory asset and liability balances.

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

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

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

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Other operation and maintenance 2,400.8 2,158.0 2,100.5

Impairment related to ICC disallowances 12.1 178.9 —

Impairments related to Illinois segment 130.0 12.1 178.9

Depreciation and amortization 1,478.5 1,354.5 1,264.2

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Preferred stock dividends of subsidiary 1.2 1.2 1.2

Net (income) loss attributed to noncontrolling interests 4.1 1.2 ( 0.4 )

Net loss attributed to noncontrolling interests 3.2 4.1 1.2

Net income attributed to common shareholders $ 1,557.5 $ 1,527.2 $ 1,331.7

Earnings per share

Basic $ 4.84 $ 4.83 $ 4.22

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Defined benefit plans

Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $ 0.1 , $( 0.2 ), and $( 1.3 ), respectively

0.1 ( 0.6 ) ( 3.5 )

Pension and OPEB adjustments arising during the period, net of tax 0.2 0.1 ( 0.6 )

Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax 0.2 0.1 —

Defined benefit plans, net 0.4 0.2 ( 0.6 )

Other comprehensive loss, net of tax ( 0.1 ) ( 0.9 ) ( 3.6 )

Other comprehensive income (loss), net of tax 0.2 ( 0.1 ) ( 0.9 )

Comprehensive income 1,555.7 1,524.2 1,330.8

Preferred stock dividends of subsidiary 1.2 1.2 1.2

Comprehensive (income) loss attributed to noncontrolling interests 4.1 1.2 ( 0.4 )

Comprehensive loss attributed to noncontrolling interests 3.2 4.1 1.2

Comprehensive income attributed to common shareholders $ 1,557.7 $ 1,527.1 $ 1,330.8

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Deferred income taxes and ITCs, net 368.5 529.0 219.4

Impairment related to ICC disallowances 12.1 178.9 —

Impairments related to Illinois segment 130.0 12.1 178.9

Contributions and payments related to pension and OPEB plans ( 13.7 ) ( 14.5 ) ( 16.7 )

Equity income in transmission affiliates, net of distributions ( 29.2 ) ( 57.4 ) ( 33.0 )

Net change in transmission regulatory assets and liabilities ( 22.8 ) 19.8 ( 85.8 )

Net loss (gain) on disposition of assets 0.7 ( 23.8 ) ( 66.2 )

Accounts receivable and unbilled revenues, net ( 411.8 ) ( 161.5 ) 340.6

Materials, supplies, and inventories 9.8 ( 38.0 ) 41.9

Prepaid taxes 36.1 ( 41.0 ) 27.9

Collateral on deposit ( 25.4 ) 84.3 22.1

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Accounts payable 46.4 99.7 ( 254.0 )

Amounts refundable to customers 43.6 ( 2.2 ) ( 9.0 )

Other current liabilities 86.5 13.8 56.5

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Capital expenditures ( 4,398.1 ) ( 2,781.1 ) ( 2,492.9 )

Acquisition of Hardin III, net of cash acquired of $ 0.2

( 406.1 ) — —

Acquisition of Delilah I, net of cash acquired of $ 0.6

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— — ( 257.3 )

Acquisition of Thunderhead, net of cash acquired of $ 0.5

— — ( 382.0 )

Capital contributions to transmission affiliates ( 142.4 ) ( 45.5 ) ( 63.7 )

Proceeds from the sale of assets 1.7 32.8 69.0

Insurance proceeds received for property damage 6.0 2.5 41.6

Reimbursement for ATC's transmission infrastructure upgrades 39.8 8.1 0.1

Other, net 32.1 9.7 13.3

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Net income attributed to common shareholders — — 1,331.7 — 1,331.7 — — 1,331.7

Net income attributed to noncontrolling interests — — — — — — 0.4 0.4

Net loss attributed to noncontrolling interests — — — — — — ( 1.2 ) ( 1.2 )

Other comprehensive loss — — — ( 0.9 ) ( 0.9 ) — — ( 0.9 )

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Acquisition of noncontrolling interests — — — — — — 114.9 114.9

Capital contributions from noncontrolling interest — — — — — — 1.1 1.1

Distributions to noncontrolling interests — — — — — — ( 6.0 ) ( 6.0 )

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Other comprehensive loss — — — ( 0.1 ) ( 0.1 ) — — ( 0.1 )

Issuance of common stock, net — 163.4 — — 163.4 — — 163.4

Common stock dividends of $ 3.34 per share

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Acquisition of noncontrolling interests — — — — — — 99.4 99.4

Purchase of additional ownership interest in Samson I from noncontrolling interest — 4.3 — — 4.3 — ( 32.4 ) ( 28.1 )

Distributions to noncontrolling interests — — — — — — ( 3.3 ) ( 3.3 )

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Net loss attributed to noncontrolling interests — — — — — — ( 3.2 ) ( 3.2 )

Other comprehensive loss — — — ( 0.1 ) ( 0.1 ) — — ( 0.1 )

Other comprehensive income — — — 0.2 0.2 — — 0.2

Issuance of common stock, net 0.1 761.8 — — 761.9 — — 761.9

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Acquisition of noncontrolling interests — — — — — — 45.1 45.1

Purchase of additional ownership interest in Samson I from noncontrolling interest — 4.3 — — 4.3 — ( 32.4 ) ( 28.1 )

Distributions to noncontrolling interests — — — — — — ( 9.6 ) ( 9.6 )

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The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs.

Finally, the rates of MGU include a rider to recover costs incurred to replace or modify natural gas facilities.

Finally, through the end of 2023 and effective again starting January 1, 2025, the rates of MGU include a rider to recover costs incurred to replace or modify natural gas facilities.

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

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We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment.

Bluewater owns underground natural gas storage facilities in southeastern Michigan and provides natural gas storage and hub services to customers.

Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers.

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Other Operating Revenues

Bespoke Resources Current Return

We recognize revenues monthly associated with carrying costs, including financing costs, during the construction period of bespoke resources assigned to WE's very large utility customers under payment and cancellation agreements.

These amounts are not considered revenues from contracts with customers as electricity is not yet being provided by WE.

Consistent with the timing of when we recognize revenue, customer billings for the bespoke resources that are subject to current return (as opposed to AFUDC) occur on a monthly basis, with payments typically due in full within 45 days.

Alternative Revenues

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The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand.

A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year.

A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual

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cost of service was for the year.

The true-up can result in an amount that we will recover from or refund to the customer.

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Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations.

Credit losses associated with our utility operations are

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analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned renewable generating facilities through agreements with several large high credit quality counterparties.

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For our larger customers, detailed credit review procedures may be performed in advance of any sales being made.

We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk.

We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, to mitigate credit risk.

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

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(g) Regulatory Assets and Liabilities — The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company.

When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet.

When this occurs, regulatory assets and liabilities are recorded on the balance sheet.

Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense.

Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

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liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities.

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See Note 6, Regulatory Assets and Liabilities, for more information.

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(h) Property, Plant, and Equipment — We record property, plant, and equipment at cost.

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AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

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The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS.

Approximately 50 % of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation.

The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements.

AFUDC rates are determined by their respective state commissions, each with specific requirements.

Average AFUDC rates are shown below:

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WBS 7.82 % N/A

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Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31:

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WPS 4.7 3.6 2.9

WG 1.0 3.4 1.4

UMERC 3.4 0.4 —

WG 0.5 0.5 3.4

WBS 0.2 0.1 0.1

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WPS 12.2 9.2 7.6

WG 2.9 9.8 3.9

UMERC 6.3 1.0 —

WG 1.2 2.9 9.8

WBS 0.5 0.3 0.4

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Total AFUDC-Equity $ 99.8 $ 59.8 $ 59.1

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

(j) Cloud Computing Hosting Arrangements that are Service Contracts — We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology.

These projects include, among other things, a centralized repository for data to improve analytics, reporting and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, and customer contact systems.

These projects include, among other things, a centralized repository for data to improve analytics, reporting, work and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, training, information technology service management, and customer contact systems.

We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received.

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During the third quarter of each year, we perform an annual impairment test for all of our reporting units that carried a goodwill balance.

The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value.

The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair

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An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value.

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An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar

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jurisdictions.

We also periodically assess the recoverability of our non-utility long-lived assets, which includes reviewing current activities, changes in the conditions of our renewable generating facilities, and market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis.

Indicators of potential impairment for a non-utility long-lived asset group, generally an individual renewable generation project, include adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in the forecasted operating revenues and earnings of our renewable generation projects, and deterioration in the performance of our renewable generation projects.

When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made.

The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss.

In 2024, we recorded a non-cash impairment loss of $ 12.1 million driven by an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs.

In 2023, we recorded a non-cash impairment loss of $ 178.9 million related to the disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC.

See Note 26, Regulatory Environment, for more information.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting.

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If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.

We recorded the following impairment losses on our income statements in the following segments during the years ended December 31:

(in millions) 2025 2024 2023

Illinois $ 130.0 (1)

Non-utility energy infrastructure (4)

Total impairment losses $ 145.9 $ 12.1 $ 178.9

(1) Represents a probable disallowance of certain capital costs at PGL under the QIP rider.

See Note 26, Regulatory Environment, for more information.

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(2) Represents a disallowance of certain previously incurred capital costs at PGL resulting from an ICC order received in August 2024 related to the 2016 annual prudency review of the QIP rider.

See Note 26, Regulatory Environment, for more information.

(3) Represents a disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC.

See Note 26, Regulatory Environment, for more information.

(4) Represents impairment losses related to storm damage at certain of WECI's renewable generation facilities.

(l) Asset Retirement Obligations — We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets.

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(m) Finite-Lived Intangible Asset and Liabilities — Our finite-lived intangible asset and liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which resulted from the acquisitions of renewable generation facilities by WECI in our non-utility energy infrastructure segment.

Our intangible asset and liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the related agreement.

Amortization of the revenue contract intangible asset and liabilities are recorded within operating revenues in the income statements.

Intangible asset and liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the related agreement.

Amortization of the revenue intangible asset and liabilities are recorded within operating revenues in the income statements.

Amortization of the interconnection agreement intangible liabilities is recorded within other operation and maintenance in the income statements.

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The amounts and useful lives assigned to the intangible asset and liabilities assumed impact the amount and timing of future amortization.

See Note 10, Goodwill and Intangibles, for more information .

(n) Stock-Based Compensation — In accordance with the Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees.

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Awards classified as liability awards are recorded at fair value each reporting period.

We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

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We account for forfeitures as they occur.

Stock Options

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Options expire no later than 10 years from the date of the grant.

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Our stock options are classified as equity awards.

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Stock-based compensation costs are generally recorded over the performance period, which is three years .

The ultimate number of performance units that will be paid out is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years , as well as other performance metrics, as may be determined by the Compensation Committee.

Under the terms of awards granted prior to 2023, participants may earn between 0 % and 175 % of the performance unit award based on our total shareholder return.

Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10 % based on our performance against additional performance measures, if any, adopted by the Compensation Committee.

The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023.

In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023, 2024, and 2025.

Pursuant to the terms of the WEC Energy Group Performance Unit Plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout of the performance unit awards.

The ultimate number of units that will be paid out will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years ( 55 %), and our performance against the weighted average authorized ROE of all of our utility subsidiaries ( 45 %).

In addition, the Compensation

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Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25 %.

In addition, the Compensation Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25 %.

In no event can the performance unit payout be greater than 200 % of the target award.

See Note 11, Common Equity, for more information on our stock-based compensation plans.

(o) Earnings Per Share — We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period.

Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities.

Our potentially dilutive securities include stock options and shares issuable upon the conversion of the 2027 Notes and 2029 Notes.

The dilutive impact from our in-the-money stock options is calculated using the treasury stock method.

The calculation of diluted earnings per share for the years ended December 31, 2024, 2023, and 2022 excluded 66,870 ;

and 653,323 stock options, respectively, that had an anti-dilutive effect.

Potentially dilutive common shares issuable upon conversion of the 2027 Notes and 2029 Notes are calculated using the if-converted method.

For the year ended December 31, 2024, there were no shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes included in our diluted earnings per share calculation as the impact was anti-dilutive.

(o) Earnings Per Share — We compute basic EPS by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period.

Diluted EPS is computed in a similar manner, but includes the exercise, settlement, and/or conversion of all potentially dilutive securities.

Our potentially dilutive securities include stock options, forward equity sales contracts, and shares issuable upon the conversion of our convertible debt instruments.

The dilutive impacts from our in-the-money stock options and forward equity sales contract are calculated using the treasury stock method.

The calculation of diluted EPS for the year ended December 31, 2025 excluded 58,533 shares issuable under our forward equity sales contract as their effect was anti-dilutive.

The calculation of diluted EPS for the years ended December 31, 2024 and 2023 excluded 66,870 and 1,716,286 stock options, respectively, that had an anti-dilutive effect.

No stock options had an anti-dilutive effect for the year ended December 31, 2025, and we did not have any forward equity sales contracts prior to 2025.

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Potentially dilutive common shares issuable upon conversion of our convertible debt instruments are calculated using the if-converted method.

For the year ended December 31, 2025, there were no shares of our common stock related to the potential conversion of the 2028 Notes (issued in June 2025) included in our diluted EPS calculation as the impact was anti-dilutive.

For the year ended December 31, 2024, there were no shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes (both issued in 2024) included in our diluted EPS calculation as the impact was anti-dilutive.

See Note 11, Common Equity, for more information on the computation of our basic and diluted EPS.

(p) Leases — We recognize a right of use asset and lease liability for operating and finance leases with a term of greater than one year .

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See Note 15, Leases, for more information.

(q) Income Taxes — We follow the liability method in accounting for income taxes.

(q) Income Taxes — In December 2023, the FASB issued ASU No.

2023-09, Income Taxes (Topic 740):

Improvements to Income Tax Disclosures.

The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table.

The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold.

For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold.

We adopted ASU No.

2023-09 on January 1, 2025, on a retroactive basis, with the required disclosures first included in our 2025 Annual Report on Form 10-K.

We follow the liability method in accounting for income taxes.

Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes.

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

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties.

In 2023 and 2024, under this transferability provision, we entered into agreements to sell substantially all of the PTCs we generated in 2023 and 2024 to third parties.

In October 2024, we entered into an agreement to sell the majority of the PTCs expected to be generated in 2025 to a third party.

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, we entered into agreements to sell the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties.

See Note 16, Income Taxes, for more information on the PTCs we sold.

We have also entered into an agreement to sell the majority of PTCs that we expect to generate in 2026 to third parties.

We elect to account for tax credits transferred under the scope of ASC 740.

We include the discount from the sale of tax credits as a component of income tax expense.

We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs.

We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs and ITCs.

The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must

We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return

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be capitalized for tax purposes.

We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return, which increased our deferred tax liabilities.

We are still evaluating whether this new guidance can be adopted by our remaining utilities.

and adopted the safe harbor method of accounting for our remaining utilities on our 2024 tax return, which increased our deferred tax liabilities.

See Note 16, Income Taxes, for more information.

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We elected not to net these items.

On our balance

On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities.

See Note 18, Derivative Instruments, for more information.

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sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities.

See Note 18, Derivative Instruments, for more information.

(t) Guarantees — We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception.

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We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed.

Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations, and we could recognize financial losses as a result.

Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues.

As a result, we did not have any significant concentrations of credit risk at December 31, 2024.

In addition, there were no customers that accounted for more than 10 % of our revenues for the year ended December 31, 2024 .

There were no customers that accounted for more than 10 % of our revenues for the year ended December 31, 2025.

As a result, for the majority of our utility companies, we did not have any significant concentrations of credit risk at December 31, 2025.

However, WE has contracts with a small number of customers to provide power to large-scale data centers to support AI and other technology capabilities.

This concentration of business with a small number of customers in an industry based on emerging technologies presents several risks.

WE is incurring significant costs to construct bespoke resources to serve these customers.

Although WE requires these customers to enter into payment and cancellation agreements, WE may still experience significant losses or delayed recovery of these costs.

Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers, which would reduce our forecasted revenues.

Significant capital spend to build out required infrastructure or a downturn in business could weaken their financial condition, liquidity and/or creditworthiness, including their ability to satisfy their reimbursement obligations to us.

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NOTE 2— ACQUISITIONS

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See Note 10, Goodwill and Intangibles, for more information.

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Acquisition of a Solar Generation Facility in Ohio

In February 2025, WECI completed the acquisition of a 90 % ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for approximately $ 405.9 million.

Upon commercial operation in February 2025, WECI completed the acquisition of a 90 % ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for $ 406.1 million.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation.

Hardin III qualifies for PTCs and is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.

(in millions)

Net property, plant, and equipment $ 526.5

Other current assets 0.2

Other current liabilities ( 0.4 )

Other long-term liabilities ( 75.1 )

Noncontrolling interest ( 45.1 )

Total purchase price $ 406.1

Acquisitions of Solar Generation Facilities in Texas

In December 2024, WECI completed the acquisition of a 90 % ownership interest in Delilah I, a 300 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas.

Upon commercial operation in December 2024, WECI completed the acquisition of a 90 % ownership interest in Delilah I, a 300 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas.

Delilah I was acquired for $ 462.5 million, which included transaction costs and was net of cash acquired.

1 unchanged sentence

Delilah I qualifies for PTCs and is included in the non-utility energy infrastructure segment.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the original acquisition.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.

(in millions)

10 unchanged sentences

In January 2024, WECI acquired an additional 10 % ownership interest in Samson I for $ 28.1 million.

2025 Form 10-K 105

WEC Energy Group, Inc.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the original acquisition.

10 unchanged sentences

Acquisitions of Electric Generation Facilities in Illinois

In November 2024, WECI completed the acquisition of a 90 % ownership interest in Maple Flats, a 250 MW solar generating facility in Clay County, Illinois.

Upon commercial operation in November 2024, WECI completed the acquisition of a 90 % ownership interest in Maple Flats, a 250 MW solar generating facility in Clay County, Illinois.

Maple Flats was acquired for $ 431.2 million, which included transaction costs and was net of cash acquired.

1 unchanged sentence

Maple Flats qualifies for PTCs and is included in the non-utility energy infrastructure segment.

2024 Form 10-K 117

WEC Energy Group, Inc.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.

17 unchanged sentences

Total purchase price $ 442.6

2025 Form 10-K 106

WEC Energy Group, Inc.

Acquisitions of Electric Generation Facilities in Wisconsin

In December 2025, WE and WPS, along with an unaffiliated utility, signed an agreement to acquire Whitetail, a wind-powered electric generation project with a total capacity of 67.2 MW.

This project will be located in Grant County, Wisconsin and WE will own 80 % and WPS will own 10 %.

WE's share of the purchase price is expected to be approximately $ 178 million and WPS's share of the purchase price is expected to be approximately $ 22 million.

The project is expected to close in late 2027 and it is expected to qualify for PTCs.

In May 2024, WE completed the acquisition of an additional 100 MWs of West Riverside's nameplate capacity for $ 97.9 million.

1 unchanged sentence

In June 2023, WE completed the first acquisition of 100 MWs for $ 95.3 million.

Prior to each of the acquisitions, WPS received approval to transfer its ownership interest rights to WE.

After the second acquisition, WE owns 200 MWs, or 27.5 %, of West Riverside at a total cost of $ 193.2 million.

4 unchanged sentences

In January 2023, WE and WPS completed the acquisition of Whitewater, a commercially operational 236.5 MW dual fueled (natural gas and low sulfur fuel oil) combined cycle electric generation facility in Whitewater, Wisconsin, for $ 76.0 million.

Acquisition of a Wind Generation Facility in Nebraska

In September 2022, WECI completed the acquisition of a 90 % ownership interest in Thunderhead, a 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska.

The purchase price was $ 382.0 million, which includes transaction costs and is net of cash acquired.

Thunderhead achieved commercial operation in November 2022.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation.

Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment.

2024 Form 10-K 118

WEC Energy Group, Inc.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.

(in millions)

Accounts receivable $ 0.2

Other prepayments 0.3

Net property, plant, and equipment 692.3

Other long-term assets 5.1

Other current liabilities ( 0.2 )

Other long-term liabilities ( 273.2 )

Noncontrolling interest ( 42.5 )

Total purchase price $ 382.0

NOTE 3— DISPOSITIONS

NOTE 3— DISPOSITION

Wisconsin Segment

3 unchanged sentences

The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

Illinois Segment

Sale of Certain Real Estate by The Peoples Gas Light and Coke Company

In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $ 55.1 million, which is net of closing costs.

The real estate was located in Chicago, Illinois.

As a result of the sale, a pre-tax gain in the amount of $ 54.5 million was recorded within other operation and maintenance expense on our income statement.

The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

2025 Form 10-K 107

84 unchanged sentences

Total natural gas utility operating revenues $ 1,402.4 $ 1,499.6 $ 419.7 $ 3,321.7

2025 Form 10-K 109

WEC Energy Group, Inc.

(in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues

7 unchanged sentences

Total natural gas utility operating revenues $ 1,606.7 $ 1,480.5 $ 493.7 $ 3,580.9

2024 Form 10-K 121

WEC Energy Group, Inc.

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

(2) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022.

As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

See Note 26, Regulatory Environment, for more information.

(2) For our Illinois segment, includes a $ 75.0 million reduction in revenues recorded in the fourth quarter of 2025 for future billing credits to customers, based on the terms of a proposed settlement in February 2026 to resolve open QIP and UEA proceedings.

Other Non-Utility Operating Revenues

11 unchanged sentences

(in millions) 2025 2024 2023

Late payment charges $ 48.1 $ 48.5 $ 56.5

Bespoke resources current return (1)

Alternative revenues (2)

( 67.7 ) 79.8 47.0

Late payment charges 48.5 56.5 55.6

Other 60.0 3.9 4.2

Total other operating revenues $ 44.5 $ 132.2 $ 107.7

(1) Bespoke resources current return consists of carrying costs earned during the construction of bespoke resources assigned to WE's VLCs.

See Note 1(d), Operating Revenues, for more information.

(2) Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups.

1 unchanged sentence

For more information about our alternative revenues, see Note 1(d), Operating Revenues.

2025 Form 10-K 110

WEC Energy Group, Inc.

NOTE 5— CREDIT LOSSES

12 unchanged sentences

94.6 % 100.0 % — % 89.9 % — % — % 89.9 %

2024 Form 10-K 122

WEC Energy Group, Inc.

(in millions) Wisconsin Illinois Other States Total Utility

23 unchanged sentences

Balance at December 31, 2025 $ 61.7 $ 82.3 $ 4.7 $ 148.7

On a consolidated basis, there was a $ 30.7 million decrease in the allowance for credit losses during the year ended December 31, 2024, largely driven by customer write-offs.

We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions during most of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

On a consolidated basis, there was a $ 14.1 million decrease in the allowance for credit losses during the year ended December 31, 2025.

This decrease is largely driven by customer write-offs in Wisconsin in addition to a decrease in past due account balances in Wisconsin that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears.

2025 Form 10-K 111

WEC Energy Group, Inc.

(in millions)

6 unchanged sentences

Balance at December 31, 2024 $ 73.6 $ 83.9 $ 5.3 $ 162.8

On a consolidated basis, there was a $ 5.8 million decrease in the allowance for credit losses during the year ended December 31, 2023, primarily related to lower customer energy costs (driven by the warmer weather during the fourth quarter of 2023 when compared to the same quarter in 2022 and lower natural gas prices), which contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

Customer write-offs also contributed to the decrease in the allowance for credit losses.

2024 Form 10-K 123

WEC Energy Group, Inc.

On a consolidated basis, there was a $ 30.7 million decrease in the allowance for credit losses during the year ended December 31, 2024, largely driven by customer write-offs.

(in millions)

6 unchanged sentences

Balance at December 31, 2023 $ 77.4 $ 109.7 $ 6.4 $ 193.5

On a consolidated basis, there was a $ 1.0 million increase in the allowance for credit losses during the year ended December 31, 2022.

We believe that the high energy costs that customers were seeing, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.

The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers.

Customer write-offs also contributed to the decrease in the allowance for credit losses.

2025 Form 10-K 112

WEC Energy Group, Inc.

NOTE 6— REGULATORY ASSETS AND LIABILITIES

4 unchanged sentences

$ 768.6 $ 810.5

Pension and OPEB costs (4)

684.9 731.7 20, 26

Environmental remediation costs (4)

566.0 570.1 24

Income tax related items 438.5 449.9 1(q), 16

Pension and OPEB costs (5)

564.5 684.9 20, 26

Income tax related items 493.4 438.5 16

AROs 185.1 166.7 1(l), 9

Uncollectible expense 123.9 151.5 5

Decoupling 110.0 27.3 1(d)

Securitization 67.5 76.5 23

Bluewater (7)

Derivatives 57.7 38.2 1(s)

Energy efficiency programs (8)

Decoupling 43.8 110.0 1(d)

Bluewater (7)

Finance and operating leases 36.0 22.0 15

Electric transmission costs (8)

Energy efficiency programs (9)

Other, net 94.5 122.3

6 unchanged sentences

In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes.

This allowance was $ 26.7 million at both December 31, 2024 and 2023.

This allowance was $ 20.9 million and $ 26.7 million at December 31, 2025 and 2024, respectively.

(2) As of December 31, 2025, we had $ 183.1 million of regulatory assets not earning a return, $ 1.3 million of regulatory assets earning a return based on short-term interest rates, $ 106.1 million of regulatory assets earning a return based on long-term interest rates, and $ 5.5 million of regulatory assets earning a return based on the applicable utility's ROE.

The regulatory assets not earning a return primarily relate to decoupling mechanisms, certain environmental remediation costs, uncollectible expense, unamortized loss on reacquired debt, and PGL's invested capital tax rider.

The regulatory assets not earning a return primarily relate to certain environmental remediation costs, decoupling mechanisms, electric transmission costs, unamortized loss on reacquired debt, and uncollectible expense.

The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.

(3) At December 31, 2024, plant retirement related items included $ 121.3 million of capitalized retirement costs related to the new EPA CCR Rule that was enacted in April 2024.

2024 Form 10-K 124

WEC Energy Group, Inc.

(4) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans.

We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(3) Primarily represents the net book value of power plants we have both abandoned and retired.

For all of these plants, we have approval to collect a return of their remaining net book value.

We also have approval to collect a return on all but $ 100 million of their remaining net book value.

For information on the securitization of this $ 100 million, see Note 23, Variable Interest Entities.

These regulatory assets are amortized on a straight-line basis, using the composite depreciation rates approved before the plants were retired, and the amortization is included in depreciation and amortization in the income statement.

(4) As of December 31, 2025, we had made cash expenditures of $ 81.9 million related to these environmental remediation costs.

The remaining $ 484.1 million represents our estimated future cash expenditures.

(5) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans.

We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(6) This regulatory asset relates to WE's 2014 announcement to retire the PIPP.

5 unchanged sentences

As a result, our Wisconsin utilities defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

2025 Form 10-K 113

WEC Energy Group, Inc.

(8) In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(9) Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards.

7 unchanged sentences

301.5 308.5 20, 26

Proposed settlement related to QIP and UEA riders 125.0 — 26

Energy costs refundable through rate adjustments 119.2 160.8 1(d)

Uncollectible expense 73.1 47.2 5

Revenue requirements of renewable generation facilities (3)

Earnings sharing mechanisms 35.8 7.1 26

Derivatives 27.4 36.9 1(s)

Electric transmission costs (4)

MERC property tax tracker (3)

Revenue requirements of renewable generation facilities (4)

Other, net 103.5 95.7

9 unchanged sentences

We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.

(3) MERC defers as a regulatory asset or liability the difference between actual property tax expense and the amount included in rates until

recovery or refund is authorized in a future rate proceeding.

(4) These amounts represent the deferral of the incremental revenue requirement impact from the delayed in-service date of certain renewable generation facilities constructed by our electric utilities.

(4) In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

Oak Creek Power Plant Units 5-6

3 unchanged sentences

Not included in these amounts was $ 6.3 million of deferred tax liabilities previously recorded for the retired units.

Effective with its rate order issued by the PSCW in December 2022, WE received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates

2024 Form 10-K 125

WEC Energy Group, Inc.

approved by the PSCW before the units were retired.

The amortization is included in depreciation and amortization on the income statement.

WE also has FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired on April 10, 2018.

The net book value of this plant was $ 506.8 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation.

In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $ 15.4 million as of December 31, 2024.

The net amount of $ 491.4 million was classified as a regulatory asset on our balance sheet at December 31, 2024 due to the retirement of the plant.

This regulatory asset does not include certain other previously recorded deferred tax liabilities of $ 138.0 million related to the retired Pleasant Prairie power plant.

Pursuant to its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired.

The amortization is included in depreciation and amortization in the income statement.

WE also has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

WE received approval from the PSCW in December 2019 to collect a full return of the net book value of the Pleasant Prairie power plant and a return on all but $ 100 million of the net book value.

During May 2021, WE securitized the remaining $ 100 million of the Pleasant Prairie power plant's book value, the carrying costs accrued on the $ 100 million during the securitization process, and the related financing fees, in accordance with a written order issued by the PSCW in November 2020.

See Note 23, Variable Interest Entities, for more information on this securitization.

Presque Isle Power Plant

Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019.

The net book value of the PIPP was $ 142.6 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation.

In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $ 4.4 million as of December 31, 2024.

The net amount of $ 138.2 million was classified as a regulatory asset on our balance sheet at December 31, 2024 as a result of the retirement of the plant.

This regulatory asset does not include certain other previously recorded deferred tax liabilities of $ 38.7 million related to the retired PIPP.

After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers.

In WE's rate order issued by the PSCW in December 2019 and UMERC's rate order issued by the MPSC in October 2024, WE and UMERC received approval to collect a return of and on the net book value of the PIPP and, as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired.

This amortization is included in depreciation and amortization in the income statement.

WE also has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Pulliam Power Plant

In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018.

The net book value of the Pulliam units was $ 29.3 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation.

This amount was classified as a regulatory asset on our balance sheet at December 31, 2024 as a result of the retirement of the plant.

Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired.

The amortization is included in depreciation and amortization in the income statement.

WPS also has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Edgewater Generating Station Unit 4

The Edgewater 4 generating unit was retired on September 28, 2018.

The net book value of the generating unit was $ 1.0 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation.

This amount was classified as a regulatory asset on our balance sheet at December 31, 2024 as a result of the retirement of the plant.

Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the

2025 Form 10-K 114

WEC Energy Group, Inc.

Edgewater 4 generating unit and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2026, using the composite depreciation rates approved by the PSCW before this generating unit was retired.

The amortization is included in depreciation and amortization in the income statement.

WPS also has FERC approval to continue to collect the net book value of the Edgewater 4 generating unit using the approved composite depreciation rates, in addition to a return on the remaining net book value.

NOTE 7— PROPERTY, PLANT, AND EQUIPMENT

20 unchanged sentences

Net other property, plant, and equipment 7,483.3 7,137.5

Property under finance leases 351.8 291.3

Accumulated amortization 16.3 10.0

Net leased facilities 335.5 281.3

Total property, plant, and equipment $ 38,278.1 $ 34,645.4

7 unchanged sentences

Total severance liability at December 31 $ 12.7 $ 13.4 $ 17.8

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

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

Wisconsin Segment Plant to be Retired

2 unchanged sentences

Subsequently, we have received PSCW approval for several other renewable and other projects and have also acquired additional projects.

See Note 2, Acquisitions, for more information on the West Riverside acquisitions.

OCPP Units 7 and 8 are expected to be retired by late 2025.

On June 25, 2025, we announced plans to extend the lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through the end of 2026.

These units were originally scheduled to be retired at the end of 2025.

The total net book value of WE's ownership share of OCPP Units 7 and 8 was $ 621.7 million at December 31, 2025, which does not include deferred taxes.

This amount was classified as plant to be retired within property,

This amount was classified as plant to be retired within property, plant, and equipment

2025 Form 10-K 115

WEC Energy Group, Inc.

plant, and equipment on our balance sheet.

on our balance sheet.

These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

1 unchanged sentence

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable.

Columbia Units 1 and 2 are expected to be retired by the end of 2029, and we are exploring the conversion of at least one unit to natural gas.

The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $ 248.9 million at December 31, 2024, 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 WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson I Solar Energy Center LLC – Storm Damage

Through June 30, 2025, Columbia Units 1 and 2 were expected to be retired by the end of 2029 and, therefore, met the criteria to be considered probable of abandonment.

In conjunction with our new capital plan, we and the other co-owners currently plan to continue coal operations at Columbia Units 1 and 2 through at least 2029, and continue to evaluate the conversion of both units to natural gas.

As a result, we and the other co-owners concluded that Columbia Units 1 and 2 (net book value of WPS's ownership share of Columbia Units 1 and 2 was $ 236.8 million at December 31, 2025, which does not include deferred taxes) no longer meet the criteria necessary to be considered probable of abandonment.

At December 31, 2025, these units continue to be included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson Solar Energy LLC and Delilah Solar Energy LLC – Storm Damage

During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage.

As of December 31, 2024, we recognized an impairment of $ 2.7 million related to storm damage, which was offset by a $ 2.7 million receivable for future insurance recoveries.

Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from these storms.

The Peoples Gas Light and Coke Company and North Shore Gas Company Impairment

In November 2023, the ICC issued written rate orders that disallowed $ 177.2 million of previously incurred capital costs related to the construction and improvement of PGL’s service centers and $ 1.7 million of capital costs related to NSG's construction of a gas infrastructure project.

As a result of these disallowances, we recorded a $ 178.9 million non-cash impairment of our property, plant, and equipment in 2023.

We had previously recognized an impairment loss of $ 2.8 million related to damage from these storms, and recorded an offsetting $ 2.8 million receivable for future insurance recoveries.

However, in the second quarter of 2025, we determined it was no longer probable that we would receive insurance proceeds sufficient to recover our losses associated with the 2023 and 2024 storms.

As a result, the insurance receivable balance was written off, resulting in the recognition of the $ 2.8 million impairment loss within other operation and maintenance expense on our income statement.

In addition, in March 2025, both our Samson I and Delilah I solar facilities experienced damage from a storm.

In the second quarter of 2025, we recognized an impairment loss within other operation and maintenance expense on our income statement in the amount of $ 8.8 million, related to damage incurred associated with the March 2025 storm.

The impairment loss associated with the March 2025 storm was increased from $ 8.8 million to $ 12.0 million in the third quarter of 2025 as a result of ongoing damage assessment.

The Peoples Gas Light and Coke Company and North Shore Gas Company Impairments

In the fourth quarter of 2025, PGL recorded a $ 130.0 million impairment to property, plant, and equipment related to the terms of a proposed settlement that would resolve its open QIP proceedings.

In August 2024, the ICC issued a final order on PGL's 2016 QIP annual reconciliation, which included a disallowance of certain capital costs.

As a result, PGL recorded a $ 12.1 million impairment of property, plant, and equipment.

As a result, we recorded a $ 12.1 million impairment to property, plant, and equipment in 2024.

As a result of these disallowances, we recorded a $ 178.9 million non-cash impairment to property, plant, and equipment in 2023.

See Note 26, Regulatory Environment, for more information.

2025 Form 10-K 116

WEC Energy Group, Inc.

NOTE 8— JOINTLY-OWNED UTILITY FACILITIES

5 unchanged sentences

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

Information related to jointly owned utility facilities at December 31, 2024 was as follows:

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

Company Jointly-Owned Utility Facilities Ownership Share of Capacity (MW)

20 unchanged sentences

66.7 % 100.0 2023 WE 179.3 ( 11.8 ) —

WE, WPS Paris (solar portion) (4)

WE, WPS Paris Solar (4)

90.0 % 180.0 2024 WE 359.3 ( 11.0 ) —

WE, WPS Paris Battery

90.0 % 99.0 2025

236.8 ( 5.5 ) —

WE, WPS Darien Solar (4)

90.0 % 225.0 2025

460.1 ( 10.7 ) —

(1) We Power leases its ownership interest in ER 1 and ER 2 to WE.

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(2) Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year.

4 unchanged sentences

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

(5) These coal units are expected to be retired by the end of 2029.

See Note 7, Property, Plant, and Equipment, for more information.

(5) WE acquired a 13.8 % ownership interest in June 2023 and acquired an additional 13.7 % ownership interest in May 2024.

See Note 2, Acquisitions, for more information.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system.

The solar portion of this project went into service in December 2024 (see details in the table above) and construction of the battery storage is expected to be completed in 2025.

O nce fully constructed, WE and WPS will collectively own 90 %, or 99 MWs of battery storage of this project.

Our CWIP balance for Paris battery storage was $ 217.0 million as of December 31, 2024.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system.

Once constructed, WE and WPS will collectively own 90 %, or 225 MWs of solar generation and 68 MWs of battery storage of this project.

Commercial operation of the solar portion and the battery storage is expected to be completed in 2025 and 2026, respectively.

Our CWIP balance for Darien was $ 422.2 million as of December 31, 2024.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Koshkonong, a utility-scale solar-powered electric generating facility with a battery energy storage system.

Once fully constructed, WE and WPS will collectively own 90 %, or 270 MWs of solar generation and 149 MWs of battery storage of this project.

Commercial operation of the solar facility and the battery storage is expected to be completed in 2026 and 2027, respectively.

Our CWIP balance for Koshkonong was $ 140.3 million as of December 31, 2024.

2025 Form 10-K 117

WEC Energy Group, Inc.

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

Company Jointly-Owned Utility Facilities Ownership Share of Capacity (MW)

Date of Expected In-Service

(in millions, except for percentages and MW)

Koshkonong Solar

90.0 % 270.0 2026

Koshkonong Battery

90.0 % 149.0 2027

Darien Battery

90.0 % 68.0 2027

High Noon Solar

90.0 % 270.0 2027

High Noon Battery

90.0 % 149.0 2027

Ursa Solar Electric Generation Facility

90.0 % 180.0 2027

Saratoga Solar

90.0 % 135.0 2028

Saratoga Battery

90.0 % 45.0 2028

WE, WPS Badger Hollow Wind Energy Generation Facility

90.0 % 100.0 2027

WE, WPS Whitetail

90.0 % 60.0 2027

NOTE 9— ASSET RETIREMENT OBLIGATIONS

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the dismantling of wind and solar generation projects;

the removal and dismantlement of a battery storage facility;

the disposal of PCB-contaminated transformers;

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See Note 24, Commitments and Contingencies, for more information.

(2) AROs decreased primarily due to revisions made to estimated cash flows for changes in removal cost estimates and settlements dates for mains and services at PGL and NSG.

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(2) AROs decreased primarily due to revisions made to estimated cash flows for changes in removal cost estimates and settlements dates for mains and services at PGL and NSG.

NOTE 10— GOODWILL AND INTANGIBLES

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(in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total

Goodwill balance (1)

$ 2,104.3 $ 758.7 $ 183.2 $ 6.6 $ 3,052.8

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Other Indefinite-Lived Intangible Assets

At December 31, 2024 and 2023, we had $ 29.3 million of other indefinite-lived intangible assets, largely consisting of spectrum frequencies.

The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories.

At December 31, 2025 and 2024, we had $ 44.4 million and $ 29.3 million, respectively, of other indefinite-lived intangible assets included in other long-term assets on our balance sheets.

These assets consist of $ 24.1 million of spectrum frequencies, which enable our utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories.

We also have $ 5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition.

These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

In October 2025, we entered into an option agreement for exclusive rights to purchase land for future generation development in Wisconsin.

We made the first annual option payment and incurred costs of $ 15.1 million during 2025, with a right to exercise our option on or before December 31, 2030.

Finite-Lived Intangible Asset

At December 31, 2024, we had a finite-lived intangible asset of $ 13.0 million related to a PPA for Maple Flats acquired by WECI in November 2024.

At December 31, 2025 and 2024, we had a finite-lived intangible asset with a gross carrying amount of $ 18.8 million and $ 13.0 million, respectively, related to a PPA for Maple Flats acquired by WECI in November 2024.

The PPA will be amortized over a useful life of 15 years and expires in 2039.

At December 31, 2024, accumulated amortization related to the intangible asset was not material.

At December 31, 2025 and 2024, accumulated amortization related to the intangible asset was not material.

This finite-lived intangible asset is included in other long-term assets on our balance sheet.

Amortization expense related to the intangible asset was not material for the year ended December 31, 2024.

Amortization expense related to the intangible asset was not material for the year ended December 31, 2025 and 2024.

Amortization expense to be recorded as a decrease to operating revenues is expected to be $ 1.3 million in each of the next five years.

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Total intangible liabilities $ 763.1 $ ( 182.8 ) $ 580.3 $ 691.5 $ ( 124.7 ) $ 566.8

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky, and Delilah I expiring between 2030 and 2040.

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky, Delilah I, and Hardin III expiring between 2030 and 2040.

The weighted-average remaining useful life of the PPAs is 10 years.

See Note 2, Acquisitions, for more information on the acquisition of Delilah I in 2024.

See Note 2, Acquisitions, for more information on recent WECI acquisitions.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029.

The remaining useful life of the proxy revenue swap is four years .

The remaining useful life of the proxy revenue swap is three years .

2025 Form 10-K 119

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The intrinsic value of options exercised during the years ended December 31, 2025, 2024, and 2023 was $ 22.8 million, $ 11.2 million, and $ 5.2 million, respectively.

The actual tax benefit from option exercises for the same years was approximately $ 3.1 million, $ 1.4 million, and $ 8.0 million, respectively.

The tax benefit from option exercises for the same years was approximately $ 6.3 million, $ 3.1 million, and $ 1.4 million, respectively.

These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, approximately $ 1.4 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.7 years on a weighted-average basis.

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The intrinsic value of restricted stock released was $ 5.7 million, $ 8.6 million, and $ 5.8 million for the years ended December 31, 2025, 2024, and 2023, respectively.

The actual tax benefit from released restricted shares for the same years was $ 2.4 million, $ 1.6 million, and $ 2.1 million, respectively.

The tax benefit from released restricted shares for the same years was $ 1.6 million, $ 2.4 million, and $ 1.6 million, respectively.

These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, approximately $ 4.9 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.7 years on a weighted-average basis.

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Performance units with an intrinsic value of $ 15.4 million, $ 2.4 million, and $ 10.2 million were settled during 2025, 2024, and 2023, respectively.

The actual tax benefit from the distribution of performance units for the same years was $ 0.6 million, $ 2.6 million, and $ 5.1 million, respectively.

The tax benefit from the distribution of performance units for the same years was $ 3.8 million, $ 0.6 million, and $ 2.6 million, respectively.

At December 31, 2025, we had 502,733 performance units outstanding, including dividend equivalents.

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During the first quarter of 2026, we settled performance units with an intrinsic value of $ 25.2 million.

The actual tax benefit from the distribution of these awards was $ 3.4 million.

The tax benefit from the distribution of these awards was $ 5.7 million.

This amount and the tax benefits disclosed above do not account for the compensation limitations under Internal Revenue Code Section 162(m).

In January 2026, the Compensation Committee also awarded 182,146 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

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All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly.

In accordance with their most recent rate orders, WE, WPS, and WG may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall

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WEC Energy Group, Inc.

below their authorized level of 53.0 %.

A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level.

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The long-term debt obligations of WECI Wind Holding I, WECI Wind Holding II, and WECI Energy Holding III contain various conditions that must be met prior to them making any cash distributions.

Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater for the 12 -month period prior to the distribution.

WEC Energy Group has the option to defer interest payments on its 2024A Junior Notes and 2024B Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period.

Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater prior to the distribution.

WEC Energy Group has the option to defer interest payments on its 2024A Junior Notes, 2024B Junior Notes, and 2025 Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period.

During any period in which it defers interest payments, it may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, its common stock.

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As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensation plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

During 2023 and 2022, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans.

As such, no new shares of common stock were issued during the years ended December 31, 2023 and 2022.

On August 6, 2024, we entered into an EDA, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $ 1.5 billion through an at-the-market offering program, which includes an equity forward sales component.

During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans.

As such, no new shares of common stock were issued during the year ended December 31, 2023.

In August 2024, we entered into an EDA, under which we could offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $ 1.5 billion through an at-the-market offering program, which included an equity forward sales component.

This EDA was terminated on October 31, 2025.

Prior to its termination, we issued 7,610,457 shares of common stock under this EDA and received proceeds of $ 797.3 million, which was net of $ 9.2 million of commissions and other fees.

We did not enter into any forward sales agreements under the August 2024 EDA.

In connection with our termination of the August 2024 EDA, we entered into a new EDA on October 31, 2025, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $ 3.0 billion through an at-the-market offering program, which also includes an equity forward sales component and a collared forward sales component.

We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement.

The EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) August 31, 2027.

The October 2025 EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) October 31, 2028.

Actual sales of common stock under the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding.

Any shares offered and sold will be done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplement.

During the year ended December 31, 2024, we issued 1,030,674 shares of common stock under the EDA and received proceeds of $ 98.3 million, which is net of $ 1.7 million of commissions and other fees.

We have not entered into any forward sale agreements.

As of December 31, 2025, we had not issued any shares of common stock under the October 2025 EDA.

2025 Form 10-K 122

WEC Energy Group, Inc.

We had the following changes to our outstanding common stock during the year ended December 31, 2024 :

In November 2025, we entered into a forward sales contract pursuant to our October 2025 EDA.

Pursuant to the terms of the contract, 58,533 shares were sold with an initial forward price of $ 110.7748 per share.

The initial forward price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts as specified in the contract.

No amounts are recorded on our balance sheet with respect to this contract until actual settlement occurs.

The contract requires us to, at our election on or before June 30, 2027, either (i) physically settle the transaction by issuing shares of our stock in exchange for net cash proceeds at the then-applicable forward sales price or (ii) net settle the transaction through the delivery or receipt of cash or shares in accordance with the contract provisions.

As of December 31, 2025, no shares were settled under this contract.

At December 31, 2025, we could have settled this forward sales contract with physical delivery of 58,533 shares of common stock to the counterparties in exchange for cash proceeds of $ 6.5 million.

The forward sales contract could have alternatively been settled with delivery of approximately $ 0.3 million of cash or approximately 3,084 shares of common stock to us, if we had elected to net cash or net share settle, respectively, at December 31, 2025.

Any shares offered and sold under our EDAs were done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplements.

We had the following changes to our outstanding common stock during the years ended December 31, 2025 and 2024:

Common stock shares outstanding at beginning of period 317,680,855 315,434,531

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The dividend is payable on March 1, 2026, to shareholders of record on February 13, 2026.

In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65 - 70 % of earnings.

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WEC Energy Group, Inc.

Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the years ended December 31:

(in millions, except per share amounts) 2025 2024 2023

Net income attributed to common shareholders $ 1,557.5 $ 1,527.2 $ 1,331.7

Weighted average basic shares outstanding 321.9 316.2 315.4

Dilutive effect of stock-based compensation awards 0.6 0.3 0.5

Dilutive effect of convertible senior notes 1.3 — —

Weighted average diluted shares 323.8 316.5 315.9

Basic EPS $ 4.84 $ 4.83 $ 4.22

Diluted EPS $ 4.81 $ 4.83 $ 4.22

NOTE 12— PREFERRED STOCK

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160,000 — — —

2024 Form 10-K 134

WEC Energy Group, Inc.

NOTE 13— SHORT-TERM DEBT AND LINES OF CREDIT

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Amount outstanding at December 31 (1)

(1) Coyote Ridge, Tatanka Ridge, and Jayhawk have entered into operating expense loans.

(1) Coyote Ridge, Tatanka Ridge, Samson I, and Jayhawk have entered into operating expense loans.

In accordance with their limited liability company operating agreements, they received loans from the holders of their noncontrolling interests in proportion to their ownership interests.

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WEC Energy Group, Inc.

Our average amount of commercial paper borrowings based on daily outstanding balances during 2025, was $ 1,124.2 million with a weighted-average interest rate during the period of 4.43 %.

WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0 %, 65.0 %, 65.0 %, 65.0 %, and 65.0 % or less, respectively.

WEC Energy Group, WE, PGL, WPS, and WG have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0 %, 65.0 %, 65.0 %, 65.0 %, and 65.0 % or less, respectively.

As of December 31, 2025, all companies were in compliance with their respective ratio.

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Revolving credit facility (WEC Energy Group) (1) (2) (3)

September 2026 $ 1,500.0

Revolving credit facility (WEC Energy Group) October 2025 (2)

August 2030 $ 1,700.0

Revolving credit facility (WE) (1) (2)

September 2026 500.0

August 2030 800.0

Revolving credit facility (PGL) (1) (2)

August 2030 600.0

Revolving credit facility (WPS) (1) (2)

September 2026 400.0

August 2030 450.0

Revolving credit facility (WG) (1) (4)

September 2026 350.0

Revolving credit facility (PGL) (1)

September 2026 350.0

August 2030 350.0

Total short-term credit capacity $ 3,900.0

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Each extension is for a period of one year .

(2) On October 18, 2024, WEC Energy Group extended the maturity to October 28, 2025.

(2) In August 2025, the capacity of the credit facilities for each of WEC Energy Group, WE, PGL, and WPS was increased to $ 1,700.0 million, $ 800.0 million, $ 600.0 million, and $ 450.0 million, respectively, and the maturity for each facility was extended to August 2030.

(3) In August 2025, WEC Energy Group terminated its $ 200.0 million bilateral credit facility.

(4) In August 2025, WG extended the maturity of its credit facility to August 2030.

The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets.

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Total long-term debt $ 18,498.1 $ 17,178.1

(1) In December 2024, we redeemed the remaining outstanding balance of our 2007 Junior Notes.

The variable rate for our 2007 Junior Notes was 7.75 % as of December 31, 2023.

(1) In November 2025, we issued our 2025 Junior Notes.

Our 2025 Junior Notes are fixed-to-fixed reset rate junior subordinated notes.

The rate for our 2025 Junior Notes was 5.625 % as of December 31, 2025.

The rate for our 2025 Junior Notes will reset on May 15, 2031;

provided the reset rate will not be less than 5.625 %.

(2) In December 2024, we issued our 2024A Junior Notes and 2024B Junior Notes.

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Final approval and issuance of a loan guarantee by the DOE is subject to numerous conditions, including negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and the satisfaction of other conditions.

In addition, in January 2025, President Trump issued an executive order that requires all federal agencies to immediately halt the disbursement of funds under the IRA and to review their processes for issuing, among other things, loan guarantees.

There can be no assurance that the DOE will issue the loan guarantee for WE.

While we continue to work with the DOE, there can be no assurance that the DOE will issue the loan guarantee for WE.

WEC Energy Group, Inc.

In January and February 2024, pursuant to a tender offer, we purchased $ 122.1 million aggregate principal amount of the $ 500.0 million outstanding of our 2007 Junior Notes for $ 115.2 million with proceeds from issuing commercial paper.

We recorded a $ 6.4 million gain related to the early settlement.

Additionally, in May 2024, we repurchased $ 19.0 million aggregate principal amount of the $ 377.9 million outstanding of our 2007 Junior Notes for $ 18.7 million, plus accrued interest, with proceeds received from issuing commercial paper.

We recorded a $ 0.2 million gain related to the early settlement.

In December 2024, we redeemed the remaining $ 358.9 million outstanding principal at par, plus accrued interest, of our 2007 Junior Notes with the proceeds we received from the issuance of our 2024A Junior Notes and 2024B Junior Notes.

In March 2024, our $ 600.0 million of 0.80 % Senior Notes, due March 15, 2024, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

In December 2024, we issued $ 254.0 million of 6.69 % Junior Notes, due June 15, 2055 and $ 496.0 million of 6.74 % Junior Notes due June 15, 2055 and used the net proceeds to repay the remaining aggregate principal amount of our 2007 Junior Notes and for other general corporate purposes.

In December 2024, pursuant to a tender offer, we repurchased $ 250.0 million aggregate principal amount of the $ 600.0 million outstanding of our 5.60 % Senior Notes due September 12, 2026 and repurchased $ 150.0 million aggregate principal amount of the $ 450.0 million outstanding of our 1.80 % Senior Notes due October 15, 2030, for $ 380.9 million, plus accrued interest, with proceeds received from issuing commercial paper.

As a result of the repurchase, we recorded a $ 16.5 million gain on debt extinguishment.

In June 2025, the remaining $ 120.0 million outstanding of our 3.55 % Senior Notes, due June 15, 2025, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In September 2025, our $ 500.0 million of 5.00 % Senior Notes due September 27, 2025, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In November 2025, we issued $ 600.0 million of 5.625 % 2025 Junior Notes due May 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In January 2026, our $ 1,000.0 million of 4.75 % Senior Notes due January 9, 2026, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

Convertible Senior Notes

In June 2025, we issued $ 900.0 million of 2028 Notes.

The 2028 Notes are senior unsecured obligations and bear interest at an annual rate of 3.375 %, payable semiannually beginning on December 1, 2025.

Proceeds from the offering were used to repay short-term debt and for other general corporate purposes.

The 2028 Notes will mature on June 1, 2028, unless earlier converted or repurchased in accordance with their terms.

No sinking fund is provided for the 2028 Notes.

Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2028 Notes.

We may not redeem the 2028 Notes prior to their maturity date.

Any fundamental change repurchases of the 2028 Notes will be at a price equal to 100 % of the principal amount, plus accrued and unpaid interest.

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WEC Energy Group, Inc.

Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2028, only under the following circumstances:

• During any calendar quarter commencing after the calendar quarter ending on September 30, 2025, (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130 % of the conversion price of such series of notes on each applicable trading day;

• During the five consecutive business day period immediately after any ten consecutive trading day period (measurement period) in which the trading price per $ 1,000 principal amount of notes, as determined following a request by a holder or holders, for each trading day of the measurement period was less than 98 % of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;

• Upon the occurrence of specified corporate events, as defined in the related indenture.

Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2028, until the close of business on the second scheduled trading day immediately preceding the maturity date.

Upon conversion, we will pay cash up to the aggregate principal amount of the notes to be converted and pay or deliver cash, shares of our common stock, or a combination of cash and shares of our common stock, at our election, in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted.

The initial conversion rate for the 2028 Notes is 7.7901 shares of common stock per $ 1,000 principal amount, which is equivalent to an initial conversion price of approximately $ 128.37 per share of our common stock.

The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for any accrued and unpaid interest.

In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

2027 Notes and 2029 Notes

In the second quarter of 2024, we issued $ 862.5 million of 2027 Notes and $ 862.5 million of 2029 Notes.

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The 2027 Notes will mature on June 1, 2027, and the 2029 Notes will mature on June 1, 2029, unless earlier converted or repurchased in accordance with their terms, or in the case of the 2029 Notes, redeemed by us.

No sinking fund is provided for either

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WEC Energy Group, Inc.

series of the notes.

No sinking fund is provided for either series of the notes.

Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2027 or 2029 Notes.

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• During any calendar quarter commencing after the calendar quarter ending on September 30, 2024 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130 % of the conversion price of such series of notes on each applicable trading day;

• During the five consecutive business day period immediately after any ten consecutive trading day period (measurement period) in which the trading price per $ 1,000 principal amount of notes of such series for each trading day of the measurement period was less than 98 % of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;

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was less than 98 % of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;

• Upon the occurrence of specified corporate events, as defined in the related indenture;

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As of December 31, 2024, none of the conditions allowing holders to convert their notes were met.

In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes and 2029 Notes were accounted for in their entirety as a liability on our balance sheet.

As of December 31, 2025, the conditions allowing holders to convert their notes were not met.

In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes, 2028 Notes, and 2029 Notes were accounted for in their entirety as a liability on our balance sheet.

The following is a summary of our convertible debt instruments as of December 31, 2025:

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$ 862.5 $ ( 4.7 ) $ 857.8 $ 977.8

2028 Notes 900.0 ( 8.5 ) 891.5 912.6

862.5 ( 6.8 ) 855.7 1,011.7

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See Note 1(r), Fair Value Measurements, for more information on the levels of the fair value hierarchy.

2024 Form 10-K 138

WEC Energy Group, Inc.

The following table provides a summary of the interest expense recorded for each of the 2027 Notes and 2029 Notes for the year ended December 31:

The following table provides a summary of the interest expense recorded for each of the 2027 Notes, 2028 Notes, and 2029 Notes for the year ended December 31:

(in millions) 2025 2024

Contractual interest expense

$ 37.7 $ 22.3

Amortization of debt issuance costs

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Total interest expense – 2028 Notes 18.8 —

Contractual interest expense

Amortization of debt issuance costs

Total interest expense – 2029 Notes $ 39.7 $ 23.5

2025 Form 10-K 129

WEC Energy Group, Inc.

Wisconsin Electric Power Company

In May 2024, WE issued $ 350.0 million of 5.00 % Debentures, due May 15, 2029, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In September 2024, WE issued $ 300.0 million of 4.60 % Debentures due October 1, 2034 and $ 300.0 million of 5.05 % Debentures due October 1, 2054, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In December 2024, WE's $ 300.0 million 2.05 % Debentures due December 15, 2024, matured and the outstanding principal and accrued interest were paid with the proceeds received from issuing commercial paper.

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

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

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

Wisconsin Public Service Corporation

In December 2024, WPS issued $ 300.0 million of 4.55 % Senior Notes due December 1, 2029, and used the net proceeds to repay short-term debt.

In November 2025, WPS's $ 300.0 million of 5.35 % Senior Notes, due November 10, 2025, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

In January 2026, WPS issued $ 300.0 million of 4.25 % Senior Notes, due January 15, 2031, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Gas LLC

In October 2024, WG issued $ 100.0 million of 4.86 % Debentures due November 1, 2029 and $ 100.0 million of 5.18 % Debentures due November 1, 2034, and used the net proceeds to repay short-term debt.

In November 2024, WG's $ 150.0 million 2.38 % Debentures due November 1, 2024, matured, and the outstanding principal and accrued interest were paid with the proceeds we received from the issuance of WG's Debentures in October 2024.

The Peoples Gas Light and Coke Company

In November 2024, PGL's $ 75.0 million 2.64 % Bonds, series HHH, due November 1, 2024, matured, and the outstanding principal and accrued interest were paid with the proceeds received from issuing commercial paper.

In September 2025, WG issued $ 175.0 million of 4.70 % Debentures, due October 1, 2030, and $ 125.0 million of 5.39 % Debentures, due October 1, 2035, and used the net proceeds to repay $ 200.0 million of WG's 3.53 % Debentures that matured on September 30, 2025, and to repay short-term debt and for other general limited liability company purposes.

Minnesota Energy Resources Corporation

In April 2025, MERC issued $ 50.0 million of 5.20 % Senior Notes, due May 1, 2030, and used the net proceeds to repay MERC's $ 50.0 million of 2.69 % Senior Notes that matured on May 1, 2025.

Michigan Gas Utilities Corporation

In October 2024, MGU issued $ 10.0 million of 4.85 % Senior Notes due November 1, 2029 and $ 15.0 million of 5.23 % Senior Notes due November 1, 2034, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys.

Bluewater Gas Storage, LLC

In October 2024, Bluewater issued $ 25.0 million of 5.41 % Senior Notes due November 1, 2041, and used the net proceeds for general limited liability company purposes.

In April 2025, MGU issued $ 75.0 million of 5.20 % Senior Notes, due May 1, 2030, and used the net proceeds to repay MGU's $ 60.0 million of 2.69 % Senior Notes that matured on May 1, 2025 and intercompany short-term debt to its parent, Integrys.

Upper Michigan Energy Resources Corporation

In August 2025, UMERC issued $ 80.0 million of 5.31 % Senior Notes, due August 14, 2030, and $ 40.0 million of 5.93 % Senior Notes, due August 14, 2035, and used the net proceeds to repay intercompany short-term debt to its parent, WEC Energy Group, and for other general corporate purposes.

ATC Holding LLC

In December 2025, ATC's $ 85.0 million of 4.18 % Debentures, due December 20, 2025, matured, and outstanding principal and accrued interest were paid with a contribution received from WEC Energy Group.

2025 Form 10-K 130

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WEC Infrastructure Energy Holding III LLC

In December 2024, WECI Energy Holding III issued $ 488.7 million of 5.73 % Senior Notes due December 31, 2039, and used the net proceeds to return a portion of WECI's previously invested capital in the subsidiaries of WECI Energy Holding III.

Maturities of Long-Term Debt Outstanding

2 unchanged sentences

Principal Amount

MGU Senior Notes (unsecured) 2.69 % May $ 60.0

MERC Senior Notes (unsecured) 2.69 % May 50.0

WE Debentures (unsecured) 3.10 % June 250.0

WEC Energy Group Senior Notes (unsecured) 3.55 % June 120.0

WEC Energy Group Senior Notes (unsecured) 4.75 % January $ 1,000.0

WEC Energy Group Senior Notes (unsecured) 5.60 % September 350.0

WG Debentures (unsecured) 3.53 % September 200.0

WPS Senior Notes (unsecured) 5.35 % November 300.0

ATC Holding (unsecured) 4.18 % December 85.0

WEPCo Environmental Trust (secured, nonrecourse) 1.58 % Semi-annually 9.3

18 unchanged sentences

NOTE 15— LEASES

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our leases is modified to conform to the rate treatment.

The difference between the lease expense that is allowed for rate-making purposes and the unadjusted lease expense calculated under Topic 842 is deferred as a regulatory asset on our balance sheets.

For our finance leases, amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes in accordance with Subtopic 980-842.

Obligations Under Operating Leases

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

2024 Form 10-K 140

WEC Energy Group, Inc.

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

• Land we are leasing related to our utility and non-utility solar generation projects through December 2074.

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

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property.

Certain of our leases contain options for early termination or to renew past the initial term, as set forth in the lease agreements.

Certain of our leases contain options for early termination or to renew past the initial term, as

2025 Form 10-K 131

WEC Energy Group, Inc.

set forth in the lease agreements.

These options are included in our calculation of the lease obligations if it is reasonably certain that they will be exercised.

Obligations Under Finance Leases

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our finance leases is modified to conform to the rate treatment.

Amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes.

The difference between this lease expense and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842.

Land Leases – Utility Solar Generation

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Each lease has an initial term and one or more optional extensions.

We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term of approximately 50 years.

We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term which can range from 40 to 50 years.

Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased.

Our payments related to these leases are being recovered through rates.

Power Purchase Commitment

In 1997, WE entered into a 25 -year PPA with LSP-Whitewater Limited Partnership.

The contract, for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements.

The PPA expired on May 31, 2022;

however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022.

Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility and the acquisition closed effective January 1, 2023.

See Note 2, Acquisitions, for more information.

Both the PPA and the tolling agreement were accounted for as a finance lease prior to the acquisition.

Land Leases – Non-Utility Energy Infrastructure Solar Generation

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We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term of approximately 50 years.

2024 Form 10-K 141

WEC Energy Group, Inc.

Amounts Recognized in the Financial Statements and Other Information

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Long-term lease liabilities $ 73.0 $ 327.3 $ 43.3 $ 1.4 $ 372.0

On February 11, 2025, WECI closed on its acquisition of a 90 % ownership interest in Hardin III, a solar generating facility.

As a result of this asset acquisition, we acquired various land leases.

We are currently evaluating the impact these leases will have on our financial statements and related disclosures.

See Note 2, Acquisitions, for more information.

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

NOTE 16— INCOME TAXES

We adopted the new disclosure provisions of ASU No.

2023-09, Income Taxes (Topic 740):

Improvements to Income Tax Disclosures, effective January 1, 2025.

See Note 1(q), Income Taxes, for more information on the adoption of this ASU.

2025 Form 10-K 133

WEC Energy Group, Inc.

NOTE 16— INCOME TAXES

Income Tax Expense

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

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

(in millions) 2025 2024 2023

Current tax expense (benefit)

Deferred income taxes, net 538.7 229.9 278.5

ITCs ( 9.7 ) ( 10.5 ) ( 5.8 )

Federal $ ( 242.5 ) $ ( 178.5 ) $ ( 36.7 )

State ( 8.0 ) ( 128.5 ) 21.9

Deferred tax expense, net

Federal 240.9 386.2 130.1

State 135.6 152.5 99.8

ITCs, net ( 8.0 ) ( 9.7 ) ( 10.5 )

Total income tax expense $ 118.0 $ 222.0 $ 204.6

3 unchanged sentences

(in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate

Statutory federal income tax $ 367.3 21.0 % $ 322.6 21.0 % $ 363.5 21.0 %

State income taxes net of federal tax benefit 108.0 6.2 % 94.3 6.1 % 109.7 6.3 %

Income before income taxes

$ 1,673.5 $ 1,746.3 $ 1,536.3

US federal statutory income tax rate

$ 351.9 21.0 % $ 367.3 21.0 % $ 322.6 21.0 %

State and local income taxes net of federal tax effect (1)

101.2 6.0 % 108.0 6.2 % 94.3 6.1 %

PTCs, net (2)

Federal excess deferred tax amortization (1)

( 261.3 ) ( 15.6 ) % ( 200.1 ) ( 11.5 ) % ( 168.2 ) ( 10.9 ) %

Other ( 8.2 ) ( 0.5 ) % ( 10.0 ) ( 0.6 ) % ( 10.9 ) ( 0.7 ) %

Nontaxable or nondeductible items

AFUDC-Equity (3)

( 21.0 ) ( 1.3 ) % ( 12.6 ) ( 0.7 ) % ( 12.4 ) ( 0.8 ) %

Other 11.0 0.7 % 4.0 0.2 % 4.4 0.2 %

Changes in unrecognized tax benefits

( 2.0 ) ( 0.1 ) % ( 0.4 ) — % ( 1.8 ) ( 0.1 ) %

Other adjustments

Federal excess deferred tax amortization (4)

( 43.0 ) ( 2.6 ) % ( 36.7 ) ( 2.1 ) % ( 37.6 ) ( 2.4 ) %

Other, net ( 10.6 ) ( 0.5 ) % 2.5 0.2 % 14.2 0.9 %

Total income tax expense $ 118.0 7.1 % $ 222.0 12.7 % $ 204.6 13.3 %

(1) The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements.

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

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

(3) AFUDC-Equity represents the cost of capital (i.e.

ROE) that is added to the construction cost of an asset while it is being built.

The tax benefit for regulated utilities from AFUDC-Equity is a regulatory gross-up to allow the recovery of income taxes on the equity portion of construction costs, even though it is not a tax deductible expense.

(4) The Tax Legislation required our regulated utilities to remeasure their 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.

2025 Form 10-K 134

WEC Energy Group, Inc.

Deferred Income Tax Assets and Liabilities

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Deferred tax liability, net $ 5,891.7 $ 5,514.7

2024 Form 10-K 144

WEC Energy Group, Inc.

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

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Balance as of December 31, 2025

$ 685.6 $ 240.9 $ ( 1.1 )

2024 (in millions)

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Balance as of December 31, 2024

$ 107.5 $ 165.4 $ ( 1.1 )

Unrecognized Tax Benefits

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Additions for tax positions of prior years 0.1 — 0.2

Additions based on tax positions related to the current year — — 0.4

Reductions for tax positions of prior years ( 1.5 ) ( 0.2 ) ( 1.9 )

Balance as of December 31 $ 3.0 $ 4.4 $ 4.6

2025 Form 10-K 135

WEC Energy Group, Inc.

The amount of unrecognized tax benefits as of December 31, 2025 and 2024, excludes deferred tax assets related to uncertainty in income taxes of $ 0.7 million and $ 1.0 million, respectively.

3 unchanged sentences

Balance as of January 1 $ 0.9 $ 0.6 $ 0.5

Interest expense related to unrecognized tax benefits 0.3 0.1 0.4

Interest expense (income) related to unrecognized tax benefits ( 0.6 ) 0.3 0.1

Balance as of December 31 $ 0.3 $ 0.9 $ 0.6

1 unchanged sentence

At December 31, 2025 and 2024, we had no amounts accrued for penalties related to unrecognized tax benefits.

Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $ 1.8 million associated with statutes of limitations on certain tax years.

We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months.

We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota.

We also file tax returns in other state and local jurisdictions

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WEC Energy Group, Inc.

with varying statutes of limitations.

We also file tax returns in other state and local jurisdictions with varying statutes of limitations.

As of December 31, 2025, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2021 through 2025 tax years in our major operating jurisdictions as follows:

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Wisconsin 2021–2025

Cash Received For Income Taxes, Net

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

(in millions) 2025 2024 2023

$ ( 256.3 ) (1)

$ ( 265.0 ) (2)

$ ( 75.0 ) (3)

( 25.0 ) 0.8 16.1

Total income taxes received, net

$ ( 281.3 ) $ ( 264.2 ) $ ( 58.9 )

(1) Includes $ 256.3 million related to 2025 and 2024 PTCs that were sold to third parties.

(2) Includes $ 269.1 million related to 2024 and 2023 PTCs that were sold to third parties.

(3) Includes $ 75.0 million related to 2023 PTCs that were sold to third parties.

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

(in millions) 2025 2024 2023

$ ( 25.0 ) $ — (1)

(1) Jurisdiction below the threshold for the period presented.

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WEC Energy Group, Inc.

NOTE 17— FAIR VALUE MEASUREMENTS

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Natural gas contracts $ 23.3 $ 8.4 $ — $ 31.7

FTRs and TCRs — — 0.8 0.8

Total derivative liabilities $ 23.3 $ 8.4 $ 0.8 $ 32.5

December 31, 2024

3 unchanged sentences

FTRs and TCRs — — 7.8 7.8

Coal contracts — 0.3 — 0.3

Total derivative assets $ 19.6 $ 13.7 $ 7.8 $ 41.1

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Natural gas contracts $ 7.1 $ 6.8 $ — $ 13.9

Coal contracts — 20.3 — 20.3

Total derivative liabilities $ 70.1 $ 36.3 $ — $ 106.4

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.

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These investments are included in other long-term assets on our balance sheets.

During the years ended December 31, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $ 9.0 million and $ 10.0 million, respectively.

For the year ended December 31, 2022, we recorded $ 12.7 million of net unrealized losses in earnings related to the investments held at the end of the period.

2024 Form 10-K 146

WEC Energy Group, Inc.

During the years ended December 31, 2025, 2024, and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $ 5.8 million, $ 9.0 million, and $ 10.0 million, respectively.

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

2 unchanged sentences

Purchases 23.7 28.7 21.0

Net realized and unrealized gains (losses) included in earnings (1)

Net realized and unrealized losses included in earnings (1)

— ( 0.7 ) ( 0.5 )

Sales ( 1.0 ) — —

Settlements ( 24.8 ) ( 27.4 ) ( 21.1 )

Balance at the end of the period $ 5.7 $ 7.8 $ 7.2

Net unrealized gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)

Net unrealized gains included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)

$ 0.1 $ — $ 0.5

1 unchanged sentence

These net realized and unrealized gains and losses are recorded in operating revenues on our income statements.

2025 Form 10-K 137

WEC Energy Group, Inc.

Fair Value of Financial Instruments

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FTRs and TCRs 6.5 0.8 7.8 —

Coal contracts — — 0.3 10.9

Total current 26.2 30.8 37.0 13.9

Natural gas contracts 0.1 1.7 4.1 —

Coal contracts — — — 9.4

Total long-term 4.1 — 0.1 17.4

Total $ 26.3 $ 32.5 $ 41.1 $ 13.9

2024 Form 10-K 147

WEC Energy Group, Inc.

Realized gains and losses on derivatives used in our regulatory utility operations are recorded in cost of sales upon settlement;

Realized gains and losses on derivatives used in our regulated utility operations are 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 utilities’ fuel and natural gas cost recovery mechanisms.

Realized gains and losses on FTRs and TCRs used in our non-utility operations are recorded in operating revenues on the income statements.

Our estimated notional sales volumes and realized gains and losses were as follows for the years ended:

Our realized gains and losses and the estimated notional volumes related to these settlements were as follows for the years ended:

December 31, 2025 December 31, 2024 December 31, 2023

(in millions) Volumes Gains (Losses) Volumes Gains (Losses) Volumes Gains

(in millions) Volumes Gains (Losses) Volumes Gains (Losses) Volumes Gains (Losses)

Natural gas contracts 202.4 Dth

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$ ( 127.8 ) 198.0 Dth

FTRs and TCRs 29.7 MWh

FTRs and TCRs

Regulated utility operations 26.3 MWh

18.9 28.4 MWh

Non-utility operations 0.7 MWh

( 0.1 ) 1.3 MWh

( 0.1 ) 0.9 MWh

Total $ ( 0.4 ) $ ( 119.6 ) $ ( 233.2 )

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We had also received cash collateral of $ 4.2 million at December 31, 2024.

2025 Form 10-K 138

WEC Energy Group, Inc.

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

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Gross amount not offset on the balance sheet ( 2.0 ) ( 23.8 ) (1)

( 7.3 ) ( 3.1 ) ( 71.0 ) (2)

Net amount $ 24.3 $ 8.7 $ 29.6 $ 6.6

(1) Includes cash collateral received of $ 4.2 million.

(1) Includes cash collateral posted of $ 21.8 million.

(2) Includes cash collateral received of $ 4.2 million.

Cash Flow Hedges

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Other guarantees (3)

11.3 — — 11.3

Total guarantees $ 244.3 $ 77.1 $ 30.3 $ 136.9

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(3) Related to workers compensation coverage for which a liability was recorded on our balance sheets.

2024 Form 10-K 148

WEC Energy Group, Inc.

NOTE 20— EMPLOYEE BENEFITS

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We expense the costs of these benefits as incurred.

Other than those employees who receive a contribution to their 401(k) savings plan as described below, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit.

Employees who started before 1996 receive a benefit based upon years of service and final average salary.

Generally, other than those employees who receive a contribution to their 401(k) savings plan as described below, former Wisconsin Energy Corporation employees receive a benefit based on a percentage of their annual salary plus an interest credit.

Wisconsin Energy Corporation management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

2025 Form 10-K 139

WEC Energy Group, Inc.

For former Integrys employees, the defined benefit pension plans are closed to all new hires.

11 unchanged sentences

Participant contributions — — 11.5 11.2

Plan amendments — — ( 0.4 ) —

Actuarial (gain) loss 8.2 ( 99.6 ) 28.3 6.9

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Funded status at December 31 $ 500.9 $ 415.1 $ 411.1 $ 389.1

(1) Employer contribution includes a $ 50.0 million transfer out of the WEC Energy Group Retiree Welfare Plan, in 2023, associated with the overfunded position of this plan.

In 2024, we had actuarial gains related to our pension benefit obligations of $ 99.6 million and actuarial losses in 2023 of $ 81.9 million.

In 2025, we had actuarial losses related to our pension benefit obligations of $ 8.2 million and actuarial gains in 2024 of $ 99.6 million.

The primary driver for the actuarial loss was the decrease in discount rate.

The primary driver for the actuarial gain was a higher discount rate in 2024.

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The discount rate for our pension benefits was 5.50 %, 5.69 %, and 5.19 % in 2025, 2024, and 2023, respectively.

2024 Form 10-K 149

WEC Energy Group, Inc.

In 2024 and 2023, we had actuarial losses related to our OPEB benefit obligation of $ 6.9 million and $ 45.9 million, respectively, both of which were driven by claims and premium updates and changes to medical trend assumptions.

Partially offsetting the losses, was a higher discount rate in 2024.

In 2025 and 2024, we had actuarial losses related to our OPEB benefit obligation of $ 28.3 million and $ 6.9 million, respectively, both of which were driven by changes to medical trend assumptions and claims and premium updates.

The 2025 loss was also driven by a lower discount rate.

Partially offsetting the loss in 2024, was a higher discount rate.

The discount rate for our OPEB benefits was 5.54 %, 5.71 %, and 5.16 % in 2025, 2024, and 2023, respectively.

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The accumulated benefit obligation for all defined benefit pension plans was $ 2,112.5 million and $ 2,156.8 million as of December 31, 2025 and 2024, respectively.

2025 Form 10-K 140

WEC Energy Group, Inc.

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets.

18 unchanged sentences

Net actuarial loss (gain) $ 11.6 $ 12.3 $ ( 1.0 ) $ ( 1.1 )

Prior service credits — — — —

Total $ 12.3 $ 12.7 $ ( 1.1 ) $ ( 1.2 )

Net regulatory assets (liabilities) (2)

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(2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities.

2024 Form 10-K 150

WEC Energy Group, Inc.

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

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Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs.

As a result, as of December 31, 2024 and 2023, our balance sheet included a $ 24.9 million and a $ 6.0 million regulatory asset for pension costs, respectively, and a $ 38.2 million and a $ 14.8 million regulatory asset for OPEB costs, respectively.

As a result, as of December 31, 2025 and 2024, our balance sheet included a $ 14.7 million regulatory liability and a $ 24.9 million regulatory asset for pension costs, respectively, and a $ 0.7 million and a $ 38.2 million regulatory asset for OPEB costs, respectively.

2025 Form 10-K 141

WEC Energy Group, Inc.

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

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Year ultimate trend rate is reached (Post 65) 2030 2030 2031

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market

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WEC Energy Group, Inc.

returns for each of the major target asset categories utilized in the trust.

For 2026, the expected return on assets assumption is 6.61 % for the pension plans and 6.50 % for the OPEB plans.

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The target asset allocations are 25 % equity investments, 55 % fixed income investments, and 20 % private equity and real estate investments for both the legacy Wisconsin Energy Corporation and legacy Integrys pension trusts.

The legacy Wisconsin Energy Corporation OPEB trust target asset allocations are 45 % equity investments, 45 % fixed income investments, and 10 % real estate investments.

The legacy Wisconsin Energy Corporation OPEB trust target asset allocations are 45 % equity investments, 45 % fixed income investments, and 10 % real estate

2025 Form 10-K 142

WEC Energy Group, Inc.

The two largest legacy OPEB trusts for Integrys have the same target asset allocations of 45 % equity investments, 45 % fixed income investments, and 10 % real estate investments.

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

2024 Form 10-K 152

WEC Energy Group, Inc.

December 31, 2024

14 unchanged sentences

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

2025 Form 10-K 143

WEC Energy Group, Inc.

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

United States Bonds

(in millions) Pension OPEB

Beginning balance at January 1, 2025

Purchases 1.4 0.1

Ending balance at December 31, 2025 $ 1.4 $ 0.1

We expect to contribute $ 16.5 million to the pension plans and $ 2.8 million to the OPEB plans in 2026, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

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The 401(k) savings plans include an Employee Stock Ownership Plan.

Certain employees receive an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service.

Certain employees receive a retirement contribution in lieu of receiving a pension benefit.

Total costs incurred under all of these plans were $ 67.3 million, $ 61.6 million, and $ 57.5 million in 2025, 2024, and 2023, respectively.

2024 Form 10-K 153

WEC Energy Group, Inc.

NOTE 21— INVESTMENT IN TRANSMISSION AFFILIATES

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We also own approximately 75 % of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint.

ATC's corporate manager has a ten -member board of directors, and ATC Holdco's corporate manager has a four -member board of directors.

ATC's corporate manager has an 11 -member board of directors, and ATC Holdco's corporate manager has a four -member board of directors.

We have one representative on each board.

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Balance at December 31 $ 2,256.9 $ 23.5 $ 2,280.4

2025 Form 10-K 144

WEC Energy Group, Inc.

(in millions) ATC ATC Holdco Total

3 unchanged sentences

Distributions 146.7 3.4 150.1

Other 0.1 — 0.1

Balance at December 31 $ 2,085.1 $ 23.8 $ 2,108.9

6 unchanged sentences

The ROE allowed by the FERC helps determine how much transmission owners, such as ATC, earn on their transmission assets as well as how much consumers pay for those assets.

Two complaints were filed arguing the base ROE for MISO transmission owners was too high.

In regards to the first ROE complaint, the D.C.

Circuit Court of Appeals issued an opinion in August 2022 that resulted in ATC recording a reserve for potential refunds based on a 9.88 % base ROE.

In November 2013, a complaint was filed arguing the base ROE for MISO transmission owners was too high.

Circuit Court of Appeals issued an opinion in August 2022 for this ROE complaint that resulted in ATC recording a reserve for potential refunds based on a 9.88 % base ROE.

In response to this opinion, the FERC issued an order in October 2024 that required ATC to adopt a 9.98 % base ROE.

Due to the change between the 9.88 % base ROE originally reflected in ATC's reserve and the 9.98 % base ROE authorized in the October 2024 FERC order, ATC reduced its refund liability, which increased our pre-tax equity earnings by $ 20.1 million during the fourth quarter of 2024.

In November 2019 and May 2020, the FERC issued orders that addressed the second complaint related to ATC's ROE.

In August 2022, the D.C.

Circuit Court of Appeals affirmed the FERC’s orders.

Therefore, during the third quarter of 2022, we reversed a $ 39.1 million liability for potential future refunds that ATC may have been required to provide, which increased our equity earnings from ATC.

We pay ATC for network transmission and other related services it provides.

2 unchanged sentences

ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.

2024 Form 10-K 154

WEC Energy Group, Inc.

The following table summarizes our significant related party transactions with ATC during the years ended December 31:

2 unchanged sentences

Charges from ATC for network transmission services 466.9 413.3 377.5

Net payment to ATC related to FERC ROE orders — — ( 0.1 )

Refund from ATC related to FERC ROE orders

As of December 31, 2025 and 2024, our balance sheets included the following receivables and payables for services provided to or received from ATC:

4 unchanged sentences

(1) The transmission infrastructure upgrades were primarily related to the construction of WE's, WPS's, and UMERC's renewable energy projects.

2025 Form 10-K 145

WEC Energy Group, Inc.

Summarized financial data for ATC is included in the tables below:

24 unchanged sentences

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, equity investment interests, as well as the revenue streams for the products or services provided to customers through electric, natural gas, and renewable operations.

See Note 4, Operating Revenues, for more

2024 Form 10-K 155

WEC Energy Group, Inc.

information on disaggregation of operating revenues, including intercompany eliminations.

See Note 4, Operating Revenues, for more information on disaggregation of operating revenues, including intercompany eliminations.

The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.

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• The other states segment includes the natural gas utility operations of MERC and MGU and the non-utility operations of MERC.

2025 Form 10-K 146

WEC Energy Group, Inc.

• The electric transmission segment includes our approximate 60 % ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75 % ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.

See Note 21, Investment in Transmission Affiliates, for more information on equity method investments.

See Note 21, Investment in Transmission Affiliates, for more information on ATC and ATC Holdco.

• The non-utility energy infrastructure segment includes:

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Other operation and maintenance 1,737.9 482.2 104.6 2,324.7 — 95.5 ( 10.2 ) ( 9.2 ) 2,400.8

Impairment related to ICC disallowances — 12.1 — 12.1 — — — — 12.1

Impairments related to Illinois segment — 130.0 — 130.0 — — — — 130.0

Depreciation and amortization 1,008.1 259.7 49.8 1,317.6 — 240.2 21.6 ( 100.9 ) 1,478.5

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Interest expense 638.7 88.9 19.2 746.8 19.3 123.1 359.0 ( 353.1 ) 895.1

Gain on debt extinguishments

— — — — — — ( 23.1 ) — ( 23.1 )

Income tax expense (benefit) 226.2 45.8 21.0 293.0 48.9 ( 122.9 ) ( 101.0 ) — 118.0

27 unchanged sentences

Other operation and maintenance 1,547.9 461.5 93.9 2,103.3 — 75.1 ( 11.3 ) ( 9.1 ) 2,158.0

Impairment related to ICC disallowances — 178.9 — 178.9 — — — — 178.9

Impairments related to Illinois segment — 12.1 — 12.1 — — — — 12.1

Depreciation and amortization 919.9 255.4 47.0 1,222.3 — 198.4 22.3 ( 88.5 ) 1,354.5

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Other operation and maintenance 1,531.3 397.9 94.5 2,023.7 — 80.1 5.8 ( 9.1 ) 2,100.5

Impairments related to Illinois segment — 178.9 — 178.9 — — — — 178.9

Depreciation and amortization 851.5 237.3 43.3 1,132.1 — 188.7 20.9 ( 77.5 ) 1,264.2

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Interest expense 601.0 88.9 15.9 705.8 19.4 94.3 258.1 ( 350.2 ) 727.4

Gain on debt extinguishments — — — — — — ( 0.5 ) — ( 0.5 )

Income tax expense (benefit) 237.4 48.6 16.3 302.3 39.0 ( 68.4 ) ( 68.3 ) — 204.6

Preferred stock dividends of subsidiary 1.2 — — 1.2 — — — — 1.2

Net income attributed to noncontrolling interests

— — — — — ( 0.4 ) — — ( 0.4 )

Net loss attributed to noncontrolling interests — — — — — 1.2 — — 1.2

Net income (loss) attributed to common shareholders $ 851.3 $ 140.0 $ 48.1 $ 1,039.4 $ 119.1 $ 336.0 $ ( 162.8 ) $ — $ 1,331.7

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We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures.

In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the

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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

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Current portion of long-term debt 9.3 9.2

Accounts payable 0.1 —

Other current liabilities (accrued interest) 0.1 0.1

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As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance.

Therefore, we account for ATC Holdco as an equity method investment.

At December 31, 2024 and 2023, our equity investment in ATC Holdco was $ 23.8 million and $ 25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 21, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

Therefore, we account for ATC Holdco as an equity

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method investment.

At December 31, 2025 and 2024, our equity investment in ATC Holdco was $ 23.5 million and $ 23.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 21, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

NOTE 24— COMMITMENTS AND CONTINGENCIES

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

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• the protection of wetlands and waterways, biodiversity including threatened and endangered species, and cultural resources associated with construction projects;

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• the beneficial use of ash and other products from coal-fired and biomass generating units;

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• the remediation of former manufactured gas plant sites;

• the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure;

• the tracking and reporting of GHG emissions to comply with federal clean air rules.

• the tracking and reporting of GHG emissions.

Federal Deregulatory Actions

In March 2025, the EPA announced a large-scale deregulatory effort that will likely take multiple years to complete.

Of the proposed deregulatory actions, those that would apply to us include actions impacting the Good Neighbor Rule, MATS, the PM2.5 Standard, the GHG Power Plant Rule, the Mandatory Greenhouse Gas Reporting Rule, the ELG, and the CCR Rule.

Any EPA actions will require formal rulemaking proceedings and are likely to be subject to legal challenges.

We continue to monitor and evaluate these deregulatory actions for potential risks and benefits.

In February 2026, the EPA published a final rule rescinding the 2009 declaration that determined that CO 2 and other GHGs endanger public health and welfare.

The "endangerment finding" has been the legal underpinning of a host of climate regulations under the CAA.

The rule is expected to face litigation.

Cross State Air Pollution Rule – Good Neighbor Rule

In March 2023, the EPA issued its final Good Neighbor Rule, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities.

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

Our RICE units in the Upper Peninsula of Michigan and Wisconsin are not currently subject to the final rule as each unit is less than 25 MWs.

To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026.

The EPA has exempted LDCs from the final rule.

In February 2024, the Supreme Court heard oral arguments regarding stay applications related to the EPA's Good Neighbor Rule.

In June 2024, the Supreme Court granted a stay of the Good Neighbor Rule pending disposition of the applicants' petitions for review at the D.C.

Circuit Court of Appeals.

Circuit Court of Appeals litigation has been held in abeyance since September 2024, when the court granted the EPA's motion for partial voluntary remand so that it could address issues of severability raised in the Supreme Court's June 2024 opinion granting the petitions for stay of the rule.

Pursuant to an order of the D.C.

Circuit Court of Appeals, the parties filed motions to govern future proceedings in December 2024.

In January 2025, the D.C.

Circuit Court of Appeals issued an order returning the consolidated cases to the court's active docket and establishing a schedule for supplemental briefing on the issue of severability that extends through early March 2025.

We will continue to monitor this case as arguments at the D.C.

Circuit Court of Appeals move forward.

In November 2024, the EPA issued a Good Neighbor Interim Final Rule that administratively stayed the effectiveness of the Good Neighbor Rule in all states to which it originally applies and ensured implementation of good neighbor obligations previously established to address the 2008 ozone NAAQS while the process works through the courts.

We are well positioned to comply with the rule's requirements.

In 2023, the EPA issued a final Good Neighbor Rule, which required significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities.

In June 2024, the rule was stayed by the Supreme Court with respect to the specific applicant states, pending ongoing judicial review.

In response to the Supreme Court's order, in November 2024, the EPA administratively stayed the effectiveness of the Good Neighbor Rule through an interim final rule which extends a stay to all states to which the rule originally applied, including states in which we operate.

The interim final rule also includes provisions to ensure that covered facilities in states with previously established requirements to mitigate interstate air pollution with respect to the 2008 ozone NAAQS will remain subject to equivalent requirements while the Good Neighbor Rule's effectiveness is stayed.

Regardless of the outcome, we believe we are well positioned to comply with either standard.

See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants.

In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units.

In May 2024, the EPA published a final rule in the Federal Register lowering the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu.

We are well positioned to comply with the rule's requirements.

The EPA issued the MATS rule to limit emissions of mercury, acid gases, and other hazardous air pollutants.

In May 2024, the EPA finalized amendments to the MATS rule (the "2024 Amendments") which among other things, lowered the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu.

We believe we are well positioned to comply with the requirements of the 2024 Amendments.

In June 2025, the EPA proposed to repeal the 2024 Amendments which would result in a return of the PM limit to 0.03 lb/MMBtu.

In December 2025, the EPA submitted a draft of the rule to the OMB for interagency review.

Following completion of the OMB review process, the EPA has stated it expects the rule to be finalized in the first quarter of 2026.

National Ambient Air Quality Standards

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The 2015 ozone standard lowered the 8-hour limit for ground-level ozone.

In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting reconsideration of the 2015 standard.

The EPA staff initially issued a draft Policy Assessment in March 2023 that also supported the reconsideration;

however, in August 2023, the EPA announced that it was instead restarting its ozone standard evaluation.

The EPA released the first two volumes of its Integrated Review Plan in December 2024.

This new review is anticipated to take 3 to 5 years to complete.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized.

The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard.

The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023.

The EPA's initial nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved.

The 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

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2015 standard.

In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 2022.

The most recent attainment evaluation date was in August 2024.

The moderate attainment deadline was not met, so in December 2024 the EPA published a final determination reclassifying the nonattainment areas in Wisconsin to a "serious" classification effective January 16, 2025.

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

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 territories are in attainment with current 2012 standards for fine PM2.5.

Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m 3 , while retaining the 24-hour standard of 35 µg/m 3 .

In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m 3 .

The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged.

The EPA has until February 2026 to designate areas as attainment and nonattainment with the new standard.

The WDNR will need to draft and submit a SIP for the EPA's approval.

All counties within our service territories 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/m 3 to 9 µg/m 3 (the "2024 PM2.5 Standard").

In February 2025, the WDNR submitted a State Implementation Plan to the EPA recommending Wisconsin be designated as an attainment area under the 2024 PM2.5 Standard.

The EPA has not yet issued its attainment designations and has indicated it may extend the designation period.

A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment.

With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units.

With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect the 2024 PM2.5 Standard to have a material impact on our units.

In November 2025, the EPA filed a motion with the D.C.

Circuit Court of Appeals to vacate the 2024 PM2.5 Standard.

The 2024 PM2.5 Standard remains in effect while the motion is being considered.

See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

New Source Performance Standards

Nitrogen Oxides

In January 2026, the EPA released a pre-publication version of its final rule regulating NOx for CTs constructed, modified, or reconstructed after December 13, 2024.

The final rule, which became effective January 15, 2026 and established NOx emissions standards for several subcategories of new, modified, and reconstructed CTs based on the size, rates of utilization, design efficiency, and fuel type of these turbines.

We believe we are well positioned to comply with this rule.

Climate Change

In May 2023, the EPA proposed GHG performance standards for fossil-fired steam generating and natural gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan.

The final rule, known as the Greenhouse Gas Power Plant Rule, was published in May 2024.

Pursuant to the final rule, there are no applicable standards for coal plants until the end of 2031 and after 2031, the applicable standard is dependent upon the unit's retirement date.

Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029.

For new combined cycle natural gas plants above a 40 % capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031.

For new simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20 %.

Our RICE units in Michigan and the new Weston RICE units are not affected under the rule because the rule excludes RICE units that are less than 25 MWs.

Numerous parties have challenged the Greenhouse Gas Power Plant Rule through litigation pending in the D.C.

Circuit Court of Appeals.

In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule.

At that time, the EPA indicated it would work on new rulemaking phases, focusing on CO 2 emissions, as well as NOx and hazardous air pollutants (formaldehyde) emissions.

In November 2024, the EPA released the first proposed rule of the three rule "packages" to address NOx emissions from existing combustion turbines.

The proposed rule for turbines that operate at a greater than 20 % capacity factor, will require more stringent NOx limits and control requirements for new, modified, or reconstructed turbines.

For turbines that operate at a capacity of 20 % or lower, less restrictive standards and the use of combustion controls would apply.

Our combined cycle facilities and the new Oak Creek combustion turbines are well positioned to comply with the proposed rule.

As the EPA will not finalize this proposal until late 2025, it could be revised or repealed under the new presidential administration.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98, which includes updates to the global warming potentials to determine CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption.

The revisions will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities.

In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems.

Under the final rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities.

Our capital plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and reliable, efficient natural gas-fueled generation.

We have already retired nearly 2,500 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 PIPP, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating unit.

We expect to retire approximately 1,200 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8, the jointly-owned Columbia Units 1 and 2 while investigating conversion of at least one unit to

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 CO 2 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 which version is finalized, would result in either a broad repeal of GHG emissions standards or a more narrow repeal of the rule's carbon capture and storage requirements.

We do 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.

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natural gas, and Weston Unit 3.

See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements.

In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60 % by the end of 2025 and by 80 % by the end of 2030, both from a 2005 baseline.

We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan.

Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

We also believe we will be in a position to eliminate coal as an energy source by the end of 2032.

We will also continue to focus on methane emissions reductions by improving our natural gas distribution systems, and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

We plan to achieve our net-zero goal through an effort that includes continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility distribution systems.

In addition, subject to regulatory approval and market conditions, we expect to procure RTCs.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, which includes updates to the global warming potentials to determine CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption.

In its current form, the rule will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities.

In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems.

Under the current form of this rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities;

however, under the Federal Deregulatory Actions discussion above, in September 2025, the EPA released a proposal to amend the GHG Reporting Program to permanently remove program obligations for most source categories, including our generation facilities.

The EPA is also proposing to suspend program reporting requirements that would be applicable to our underground storage, LNG, and transmission affiliates until 2034.

We continue to monitor the status of these deregulatory actions.

Our 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 2,500 MWs of fossil-fueled generation since the beginning of 2018.

We expect to retire approximately 900 MWs of additional coal-fired generation by the end of 2031.

In conjunction with our new capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2029, and continue to evaluate the conversion of both units to natural gas.

See Note 7, Property, Plant, and Equipment, for more information related to Columbia Units 1 and 2 and our planned power plant retirements.

We have a long-term goal to achieve net carbon-neutral electric generation by the end of 2050.

We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan.

As part of our path toward this goal, we started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4 in 2025.

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

We also continue to focus on methane emission reductions by improving and upgrading our natural gas distribution systems and using RNG throughout our natural gas utility systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

Section 316(b) of the CWA became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts.

The 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.

Effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code.

The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities.

These BTA requirements are incorporated into WPDES permits for WE and WPS facilities.

We have received final or interim BTA determinations for all generation facilities where Section 316(b) is applicable.

The most recent BTA determination was for Weston Units 3 and 4.

In accordance with the requirements in the CWA, the WDNR reissued the Weston WPDES permit in June 2024 (effective July 1, 2024) that includes a determination that existing technology (wet cooling towers) installed at the units represents BTA for minimizing adverse environmental impacts.

With respect to OCPP Units 7 and 8, we believe the WDNR will reach the same BTA determination decision when the WPDES permit for those units is reissued, which is expected in 2025.

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 2015 final ELG rule, which took effect in January 2016 (2015 ELG rule), was modified in 2020 (2020 ELG rule), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule.

These rules establish federal technology-based requirements for several types of power plant wastewaters.

The three requirements that affect WE and WPS facilities relate to discharge limits for BATW, FGD wastewater, and CRL (landfill leachate).

Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP, ERGS, and Weston to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule.

Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $ 105 million in capital investment.

The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date.

The Supplemental ELG Rule also kept one existing and created one new “permanent cessation of coal” subcategory.

Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively.

For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025.

All WE and WPS coal-fueled units fully meet the 2020 ELG rule requirements.

Based on current electrical generation resource planning, we plan to file a Notice of Planned Participation by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for both the ERGS and Weston coal-fired facilities.

A Notice of Privacy Practice also may be filed for the OCPP, PWGS, and VAPP facilities because this ELG rule option will allow the company to qualify for more reasonable requirements to address the CRL provisions at our landfills that served these former coal-fired facilities.

The EPA's 2024 Supplemental ELG Rule (the "2024 ELG Rule") established ZLD requirements for bottom ash transport water, flue gas desulfurization, and combustion residual leachate wastewaters at coal-fueled facilities.

The 2024 ELG Rule also established a new subcategory, providing an alternative compliance pathway for facility owners that commit to the PCCC at a particular facility by December 31, 2034.

In exchange for this commitment, ZLD technologies will not be required and less stringent standards will apply at applicable facilities.

The 2024 ELG Rule also allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2034 if needed for reliability concerns (i.e., energy emergencies and reliability must run agreements) as determined by the United States DOE, a public utility commission, or independent system operator.

Based on current electric generation resource planning, in December 2025, we filed Notice of Planned Participations to opt into the PCCC subcategory for certain of our past and current coal-fueled facilities.

In December 2025, the EPA published a final rule, effective March 2, 2026, that extends the deadline for facility owners to opt into a subcategory under the 2024 ELG Rule, allowing them more time to assess potential compliance pathways to continue producing low-cost electricity into the future while meeting wastewater standards.

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The final Supplemental ELG Rule allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2028 or 2034, required by either the 2015 or the 2020 ELG Rule, respectively, if needed for reliability concerns (i.e., energy emergencies, reliability must run agreements, etc.) as determined by the DOE, a public utility commission, or independent system operator.

We are still evaluating the Supplemental ELG Rule CRL provisions to determine the applicability and potential compliance costs for inactive/closed landfills.

Numerous parties have challenged the rule through litigation pending in the U.S.

Court of Appeals for the 8th Circuit.

This rule remains in effect during the pendency of the legal challenge.

When the deadline extension rule was proposed, the EPA also solicited public comments related to the economic achievability and technical availability of ZLD technologies.

Additional ELG rulemaking is anticipated that may lead to substantive changes to the ZLD technology-based requirements established in the 2024 ELG Rule.

In addition, numerous parties have challenged the 2024 ELG Rule through litigation in SWEPCO v.

EPA pending in the United States Court of Appeals for the Eighth Circuit, which has been held in abeyance since February 2025.

The 2024 ELG Rule, as well as the deadline extension rule, remain in effect during the pendency of the legal challenge.

The outcome of this case may affect our compliance plans.

Manufactured Gas Plant Remediation

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We have also identified other sites that may have been impacted by historical manufactured gas plant activities.

Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program.

We are also working with various state jurisdictions in our investigation and remediation planning.

Our natural gas utilities are responsible for the environmental remediation of these sites.

We are working with the EPA as well as various state jurisdictions, as applicable, in our investigation and remediation planning and efforts.

These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program.

This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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.

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(in millions) 2025 2024

Regulatory assets $ 570.1 $ 596.8

Regulatory assets for environmental remediation costs $ 566.0 $ 570.1

Reserves for future environmental remediation 484.1 445.8

Coal Combustion Residuals Rule

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

The rule will regulate previously exempt closed landfills.

The final rule, which became effective in November 2024 will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs.

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.

We expect the cost of the additional remediation would be recovered through future rates.

See Note 9, Asset Retirement Obligations, for more information on the estimated cost of the additional remediation.

In December 2025, the D.C.

Circuit Court of Appeals granted the EPA's motion to extend the ongoing abeyance while the EPA reconsiders certain aspects of the rule.

In February 2026, the EPA published a final rule extending certain deadlines and making various corrections to the 2024 CCR rule.

The EPA has stated it plans to publish a new final rule by the end of 2026.

See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Renewables, Efficiency, and Conservation

1 unchanged sentence

In 2005, Wisconsin enacted Act 141, which established a goal that 10 % of all electricity consumed in Wisconsin be generated by renewable resources annually.

WE and WPS have achieved their required renewable energy percentages of 8.27 % and 9.74 %, respectively, by constructing various wind parks, solar parks, a biomass facility, and by also relying on renewable energy purchases.

WE and WPS have achieved their required renewable energy percentages of 8.27 % and 9.74 %, respectively, by constructing various wind and solar facilities, a biomass facility, and by also relying on renewable energy purchases.

WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing basis.

14 unchanged sentences

They require a utility to file a plan every two years until 2025, then every three years thereafter.

In February 2025, we filed an AREP with the MPSC addressing UMERC's compliance with the Act 235 renewable portfolio standards.

At the same time, we are working with a coalition of members of the Michigan legislature to seek exemption from Act 235 for our new RICE units.

In December 2025, the MPSC issued an order denying UMERC's AREP, requiring UMERC to file a new AREP in October 2026.

Enforcement and Litigation Matters

1 unchanged sentence

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.

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009.

WPS entered into a Consent Decree with the EPA resolving this NOV.

This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.

With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018.

See Note 6, Regulatory Assets and Liabilities, for more information about the retirement.

Following our significant engagement with the EPA, the agency conditionally terminated the Consent Decree in December 2024.

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, WE (former co-owner of an Edgewater unit), and WPS.

The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants.

WPS, along with WPL, MG&E, and WE, entered into a Consent Decree with the EPA resolving this NOV.

This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013.

As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater Unit 4 generating unit was retired in September 2018.

See Note 6, Regulatory Assets and Liabilities, for more information about the retirement.

WPL started the process to close out this Consent Decree.

2024 Form 10-K 166

WEC Energy Group, Inc.

NOTE 25— SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions

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

Year Ended December 31

1 unchanged sentence

Cash paid for interest, net of amount capitalized $ 858.5 $ 785.7 $ 653.4

Cash paid (received) for income taxes, net (1)

Cash received for income taxes, net

( 281.3 ) ( 264.2 ) ( 58.9 )

5 unchanged sentences

Liabilities accrued for software licensing agreements 21.1 0.2 —

(1) Cash received for income taxes in 2024 and 2023 includes $ 269.1 million and $ 75.0 million, respectively, related to 2023 and 2024 PTCs that were sold to third parties.

Restricted Cash

Cash, Cash Equivalents, and Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash.

7 unchanged sentences

• Cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans.

• Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WECI Wind Holding I, WECI Wind Holding II, and WEPCo Environmental Trust.

• Cash related to WECI's ownership interests in certain renewable generation projects.

These projects are required to deposit into an escrow account annually in order to fund future decommissioning.

• Cash used by WE and WPS during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin.

This cash was included in other long-term assets at December 31, 2022.

See Note 2, Acquisitions, for more information on the purchase of this facility.

2025 Form 10-K 157

WEC Energy Group, Inc.

• Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WECI Wind Holding I, WECI Wind Holding II, WECI Energy Holding III, and WEPCo Environmental Trust.

• Cash related to WECI's ownership interests in certain renewable generation projects.

These projects are required to deposit into an escrow account in order to fund future decommissioning.

NOTE 26— REGULATORY ENVIRONMENT

Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC

Very Large Customer and Bespoke Resources Tariffs

In March 2025, WE filed an application with the PSCW requesting approval to implement a VLC Tariff and a Bespoke Resources Tariff.

WE subsequently filed testimony in October 2025 slightly modifying the initial proposals.

Under these proposed inter-connected tariffs, VLCs (new customers using 500 MWs or more, such as large data centers) will have access to reliable power to meet their needs and will directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them and operating and transmission costs allocated to their usage.

The proposed tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

The two new tariffs will work in tandem as VLCs will be required to sign a service agreement and subscribe to a portion of one or more "Bespoke Resources," including renewable generation facilities, battery storage, and natural gas generation units.

Under these agreements, if a VLC terminates or downsizes its plans, it will still be required to pay for the Bespoke Resources and dedicated distribution facilities that have been built to support its forecasted load, unless the facilities can be repurposed, subject to PSCW approval.

Service agreements under the Bespoke Resources Tariff will be effective for the depreciable life of the resource, except for wind or solar resources which will have a term of 20 years.

As currently proposed, the ROE (can range from 10.48 % to 10.98 % as agreed upon with the customer) and equity ratio ( 57 %) will both be fixed for the entire term of the agreement, and the revenue and costs recovered through the tariffs will be excluded from future rate case proceedings and earnings sharing mechanisms.

We expect a decision from the PSCW in the second quarter of 2026.

Prior to the PSCW approving the tariffs, for infrastructure investments that have not received regulatory approval, WE requires VLCs to enter into payment and cancellation agreements which obligate the VLC to reimburse WE for all costs associated with projects, including any associated costs incurred by ATC for transmission infrastructure projects, requested by the customer until service agreements are executed under the approved tariffs.

Reimbursement is required if, among other things, the VLC terminates the payment and cancellation agreement or reduces its anticipated load, or regulatory approval is not received for the construction of a project.

2025 and 2026 Rates

2 unchanged sentences

The requested increases in natural gas rates were driven by the companies' ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.

On December 19, 2024, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2025 and 2026, as applicable.

2025 Form 10-K 158

WEC Energy Group, Inc.

In December 2024, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2025 and 2026, as applicable.

The final written orders reflected the following:

14 unchanged sentences

and (iii) 100.0 % of any remaining excess earnings is required to be refunded to ratepayers.

WPS and WG are required to maintain their current earnings sharing mechanism.

Under the current mechanism, if the utility earns above its authorized ROE:

WPS and WG were required to maintain their then current earnings sharing mechanism.

Under this mechanism, if the utility earns above its authorized ROE:

(i) the utility retains 100.0 % of earnings for the first 15 basis points above the authorized ROE;

7 unchanged sentences

WE's and WG's LNG projects were placed into service in November 2023 and February 2024, respectively.

2024 Form 10-K 168

WEC Energy Group, Inc.

In December 2023, the PSCW issued final written orders approving electric and natural gas rate increases and decreases, effective January 1, 2024.

9 unchanged sentences

The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage;

capital investments in natural gas generation;

capital investments

2025 Form 10-K 159

WEC Energy Group, Inc.

in natural gas generation;

reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather;

21 unchanged sentences

WE and WPS also collectively contributed $ 4.0 million to the Keep Wisconsin Warm Fund.

• WE, WPS, and WG were required to implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024.

• WE, WPS, and WG were required to implement escrow accounting treatment for pension and OPEB costs.

As a result, they defer as a regulatory asset or liability, the difference between actual pension and OPEB costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

• As discussed above, WE and WPS were authorized to file a limited electric rate case re-opener for 2024, and WE and WG were authorized to file a limited natural gas rate case re-opener for 2024.

The Peoples Gas Light and Coke Company and North Shore Gas Company

2026 Rate Application

In January 2026, PGL and NSG filed requests with the ICC to increase their natural gas base rates.

They are requesting rate increases of $ 201.3 million ( 20.95 %) and $ 12.7 million ( 12.2 %), respectively.

The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system.

PGL's rate request includes the estimated revenue requirements associated with its PRP projects.

As discussed below, projects completed under PGL's PRP are to meet the ICC's directive to retire all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035.

PGL's rate request includes the revenue requirements associated with approximately $ 360 million of capital investments planned under its PRP in 2027.

Higher operating costs, driven by inflation, and increases in the cost of capital, also drove the requested rate increases.

Both companies are requesting an ROE of 10.10 % and a common equity component average of 54.0 %.

An ICC decision is anticipated in the fourth quarter of 2026, with new rates expected to be effective by January 1, 2027.

2025 Form 10-K 160

WEC Energy Group, Inc.

In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that allowed them to maintain their electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year .

In connection with the request, the three utilities also entered into an agreement, dated March 23, 2021, with various stakeholders.

Pursuant to the terms of the agreement, the stakeholders fully supported the application.

In September 2021, the PSCW issued written orders approving the application.

The final orders reflected the following:

• WE, WPS, and WG amortized, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies.

• WG deferred interest and depreciation expense associated with capital investments since its last rate case that otherwise would have been added to rate base in a 2022 test-year rate case.

• WE, WPS, and WG were able to defer any increases in tax expense due to changes in tax law that occurred in 2021 and/or 2022.

• WE, WPS, and WG maintained their earnings sharing mechanisms, with modification.

The Peoples Gas Light and Coke Company and North Shore Gas Company

2023 Rate Order

3 unchanged sentences

PGL did not request an extension of the QIP rider as PGL returned to the traditional rate making process to recover the costs of necessary infrastructure improvements.

On November 16, 2023, the ICC issued final written orders approving base rate increases for PGL and NSG.

In November 2023, the ICC issued final written orders approving base rate increases for PGL and NSG.

The written orders were subsequently amended for various technical corrections.

The amended written orders approved the following base rate increases:

• A $ 304.6 million ( 43.5 %) base rate increase for PGL’s natural gas customers.

This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider.

PGL's new rates were effective December 1, 2023.

• A $ 304.6 million ( 43.5 %) base rate increase for PGL’s natural gas customers, effective December 1, 2023.

This amount includes the recovery of costs that were previously being recovered under its QIP rider.

• An $ 11.0 million ( 11.6 %) base rate increase for NSG’s natural gas customers.

2 unchanged sentences

As part of its decisions, the ICC, among other things, disallowed $ 236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $ 1.7 million of capital costs related to NSG's construction of a gas infrastructure project.

In addition, the ICC ordered PGL to pause spending on its SMP until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In accordance with the written order, the ICC initiated the proceeding in January 2024.

On February 20, 2025, the ICC issued an order setting expectations for PGL's prospective operations under its SMP.

The ICC directed us to focus on replacing all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035.

The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute.

We are evaluating the impact of this order on our operations and capital plan.

In addition, the ICC ordered PGL to pause spending on its projects to upgrade its natural gas delivery system until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 2023 written orders.

The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of SMP projects that started in 2023 and emergency repairs needed to ensure the safety and reliability of PGL's delivery system.

On May 30, 2024, the ICC issued a written order on the rehearing.

The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of projects to upgrade PGL's natural gas delivery system that started in 2023 and emergency repairs needed to ensure the safety and reliability of the delivery system.

In May 2024, the ICC issued a written order on the rehearing.

The order approved $ 28.5 million of additional spending for emergency work, representing a $ 1.6 million increase to PGL's annual revenue requirement.

2024 Form 10-K 170

WEC Energy Group, Inc.

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $ 178.9 million non-cash impairment of our property, plant, and equipment during the fourth quarter of 2023.

1 unchanged sentence

The remaining disallowance of capital costs at PGL related to expected future spend.

On June 7, 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 16, 2023 and May 30, 2024 orders.

The appeal includes the ICC's $ 237.9 million combined disallowance of capital costs at PGL and NSG discussed above, along with the $ 116.0 million disallowance of SMP capital investments needed to meet safety and reliability requirements.

Although the ICC ordered PGL to complete safety and reliability work in 2024, it denied the recovery of these costs.

In June 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 2023 and May 2024 orders.

The appeal includes the ICC's $ 237.9 million combined disallowance of capital costs at PGL and NSG discussed above, along with the $ 116.0 million disallowance of capital investments needed to meet safety and reliability requirements of PGL's natural gas delivery system.

Although the ICC ordered PGL to complete safety and reliability work in 2024, it denied the recovery of these costs in the current rates.

In accordance with the November 2023 rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure.

In February 2025, the ICC issued an order setting expectations for PGL's prospective operations.

The ICC directed us to focus on retiring all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035.

The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute.

PGL is working to retire this cast and ductile iron pipe through its PRP.

Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases.

In addition, the program will be overseen by a safety monitor hired by the ICC.

As discussed above, PGL initiated a general rate case proceeding in January 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated with the PRP.

2025 Form 10-K 161

WEC Energy Group, Inc.

Illinois Riders

Uncollectible Expense Adjustment Rider

2 unchanged sentences

In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation.

The order required a $ 15.4 million and $ 0.7 million refund to ratepayers at PGL and NSG, respectively.

The order required a $ 15.4 million and $ 0.7 million refund to customers at PGL and NSG, respectively.

These amounts were refunded over a period of nine months , which began on September 1, 2023.

In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC order.

On November 7, 2024, the Illinois Appellate Court issued an opinion affirming the ICC order and the related disallowance.

PGL and NSG petitioned the Illinois Supreme Court on December 12, 2024 seeking review and reversal of the May 2023 order.

As of December 31, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2024, will be deemed recoverable by the ICC.

The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $ 10 million to $ 40 million during these open reconciliation years.

Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Upon appeal by PGL and NSG, the Illinois Appellate Court affirmed the ICC order and the related disallowance.

The Illinois Supreme Court denied a subsequent petition for review and reversal of the order in March 2025.

As of December 31, 2025, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years will be deemed recoverable by the ICC.

Future disallowances by the ICC could be material.

The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $ 10 million to $ 40 million.

However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Qualifying Infrastructure Plant Rider

7 unchanged sentences

The charge was recorded on the income statement as a $ 12.9 million reduction in revenues for the amounts previously collected from customers, a $ 12.1 million increase to operating expenses for the impairment of PGL's property, plant, and equipment, and a $ 0.3 million increase to interest expense related to the amounts due to customers.

On October 25, 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August order.

In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2017 through 2022, is still pending.

The aggregate capital costs included in the rider during the open reconciliation years, which include 2017 through 2023, along with any previously recognized return on these investments, totaled approximately $ 2.8 billion as of December 31, 2024.

There can be no assurance that all of these costs and the previously recognized returns will be deemed recoverable by the ICC.

Further disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

In October 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order;

however, in January 2026, PGL filed an unopposed motion to stay the appeal, which was granted by the court.

PGL's QIP reconciliations from 2017 through 2023 are still pending.

Future disallowances by the ICC could be material.

The aggregate capital costs included in the rider during the open reconciliation years, along with any previously recognized return on these investments, totaled approximately $ 3.0 billion as of December 31, 2025.

However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement

In February 2026, PGL and NSG agreed on the terms of a proposed settlement with the Illinois Attorney General that, if approved by the ICC, would resolve all open proceedings related to the UEA and QIP riders.

PGL and NSG agreed to refund $ 49.0 million and $ 1.0 million, respectively, to customers as bill credits over a period of three years between 2026 and 2028 to resolve the open UEA proceedings.

In order to resolve the open QIP proceedings, PGL agreed to permanently remove $ 130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $ 75.0 million to customers as bill credits over a period of three years between 2026 and 2028.

As a result of this agreement, we recorded a $ 205.0 million charge to income during the fourth quarter of 2025.

The charge was recorded as a $ 130.0 million impairment to PGL's net property, plant, and equipment and a $ 75.0 million reduction to revenues.

The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at December 31, 2025 is $ 255.0 million.

This includes the $ 205.0 million charge to income recorded during 2025 and a $ 50.0 million charge to income recorded in prior years.

This proposed settlement is subject to ICC approval following a public review process.

2025 Form 10-K 162

6 unchanged sentences

In November 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors.

The settlement agreement reflects a natural gas base rate increase of $ 28.8 million ( 7.1 %), along with a 9.65 % ROE and a common equity component average of 53.0 %.

The settlement agreement reflected a natural gas base rate increase of $ 28.8 million ( 7.1 %), along with a 9.65 % ROE and a common equity component average of 53.0 %.

The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs.

3 unchanged sentences

These amounts were refunded to customers during the second quarter of 2024.

Recovery of Natural Gas Costs

In February 2021, MERC incurred approximately $ 75 million of natural gas costs in excess of the benchmark set in its GCRM.

In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs.

In accordance with the order, MERC recovered $ 10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $ 65 million was to be recovered over a period of 27 months, both beginning in September 2021.

Recovery of these costs and the issue of prudence was referred to a contested-case proceeding.

In October 2022, the MPUC issued a written order approving a settlement agreement entered into by MERC and various parties related to the recovery of the extraordinary natural gas costs incurred in February 2021.

Under the settlement agreement, MERC agreed to not seek recovery of $ 3 million of these costs.

MERC recovered the remaining $ 62 million of extraordinary natural gas costs over the previously approved 27 -month recovery period.

Michigan Gas Utilities Corporation

2026 Rate Application

On December 19, 2025, MGU provided notification to the MPSC of its intent to file an application requesting an increase to its natural gas rates.

The application is expected to be filed in March 2026 and to request new rates be effective January 1, 2027.

MGU is currently in the process of evaluating its rate request.

2024 Rate Order

In March 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates.

In September 2024, the MPSC issued a final order approving a settlement agreement, which authorizes MGU to increase its natural gas base rates by $ 7.0 million ( 3.88 %).

The rate increase reflects a 9.86 % ROE and a common equity component average of 50.0 %.

The rate increase is primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates over the past few years.

The order also authorizes MGU to defer any expenses incurred to implement the PHMSA's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."

In September 2024, the MPSC issued a final order approving a settlement agreement, which authorized MGU to increase its natural gas base rates by $ 7.0 million ( 3.88 %).

The rate increase was primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates over the past few years.

The rate increase reflected a 9.86 % ROE and a common equity component average of 50.0 %.

The new rates became effective January 1, 2025.

The order also authorized MGU to defer any expenses incurred to implement the PHMSA's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."

2023 Rate Order

7 unchanged sentences

MRP costs were recovered in base rates in 2024.

2024 Form 10-K 172

WEC Energy Group, Inc.

The rate increase was primarily driven by capital investments made to strengthen the safety and reliability of MGU's natural gas distribution system and to provide service to additional customers.

1 unchanged sentence

The new rates were effective January 1, 2024.

2025 Form 10-K 163

WEC Energy Group, Inc.

Upper Michigan Energy Resources Corporation

Amended Renewable Energy Plan

In accordance with Michigan Public Act 235, UMERC filed an AREP with the MPSC in February 2025.

UMERC's AREP addressed its compliance with the Act 235 renewable portfolio standards and its proposal to recover the projected compliance costs through an incremental renewable energy surcharge.

The projected compliance costs included the purchase of Michigan-sourced renewable energy credits and the revenue requirements for UMERC's previously approved investment in Renegade, a 100 MW utility-scale solar-powered electric generating facility, and any other incremental renewable generation resources required to meet the Act 235 renewable portfolio standards.

On December 18, 2025, the MPSC issued an order denying UMERC's AREP and requiring UMERC to file a new AREP by October 15, 2026.

Renegade is currently interconnected and delivering power to MISO, and it is expected to achieve commercial operation in the first quarter of 2026.

The estimated cost of Renegade is approximately $ 226 million.

As UMERC's proposal to recover the annual revenue requirement of Renegade through a renewable energy surcharge was denied, UMERC will recover a portion of these costs through its power supply cost recovery mechanism, and the MPSC advised UMERC to seek deferral accounting treatment for the remainder.

UMERC filed its request for deferral accounting with the MPSC on January 27, 2026.

2024 Rate Order

In May 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers.

On October 10, 2024, the MPSC issued a final order approving a settlement agreement, which authorizes UMERC to increase electric base rates for non-mine customers by $ 6.6 million ( 8.2 %).

The rate increase reflects a 9.86 % ROE and a common equity component average of 50.0 %.

The rate increase is primarily driven by the construction of the now in-service RICE generation facilities located in the Upper Peninsula of Michigan and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates.

A reduction of operation and maintenance costs partially offset these impacts.

In October 2024, the MPSC issued a final order approving a settlement agreement, which authorized UMERC to increase electric base rates for non-mine customers by $ 6.6 million ( 8.2 %).

The new rates became effective January 1, 2025.

The rate increase reflected a 9.86 % ROE and a common equity component average of 50.0 %.

The rate increase was primarily driven by the construction of the now in-service RICE generation facilities located in the Upper Peninsula of Michigan and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates.

A reduction of operation and maintenance costs partially offset these impacts.

NOTE 27— OTHER INCOME, NET

1 unchanged sentence

(in millions) 2025 2024 2023

Non-service components of net periodic benefit costs $ 83.7 $ 97.7 $ 104.4

AFUDC-Equity $ 99.8 $ 59.8 $ 59.1

Gains from investments held in rabbi trust 8.1 11.7 13.7

Interest income 5.9 17.2 3.9

Gains (losses) from investments held in rabbi trust 11.7 13.7 ( 12.6 )

Non-service components of net periodic benefit costs 2.7 83.7 97.7

Earnings (losses) from equity method investments (1)

4 unchanged sentences

NOTE 28— 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.

2025 Form 10-K 164

WEC Energy Group, Inc.

Accounting for Government Grants

In December 2025, the FASB issued ASU No.

2025-10, Government Grants (Topic 832) Accounting for Government Grants Received by Business Entities.

The amendments establish the accounting for a government grant received by a business entity, including guidance for a grant related to an asset and a grant related to income.

The amendments also require disclosures, including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant.

The amendments are effective for annual periods beginning after December 15, 2028, and interim periods within those annual periods, with early adoption permitted.

We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Disaggregation of Income Statement Expenses

6 unchanged sentences

We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2027, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No.

2023-09, Income Taxes (Topic 740):

Improvements to Income Tax Disclosures.

The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table.

The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold.

The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted.

2025 Form 10-K 165

WEC Energy Group, Inc.

adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU No.

2023-07, Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures.

The amendments require additional disclosures about reportable segments on an annual and interim basis.

The amendments require disclosure of significant segment expenses that are (1) regularly provided to the CODM and (2) included in the reported measure of segment profit or loss.

The amendments also require disclosure of an amount for other segment items and a description of its composition.

The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources.

The update was effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.

We adopted these amendments beginning with our fiscal year ending on December 31, 2024.

See Note 22, Segment Information, which reflects the implementation of this update in our disclosures about our reportable segments.

2024 Form 10-K 174

WEC Energy Group, Inc.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data