What changed in this filing

/stocks — the workspaceLOADING

Item 8. Financial Statements and Supplementary Data

2025-02-21 compared with 2024-02-22 · 757 added, 657 removed, 2207 unchanged (39% of the section changed)

33 unchanged sentences

(1) full recovery of the costs of providing utility service, (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment or (3) timely recovery of costs incurred.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the subjectivity involved in assessing the impact of future regulatory orders on the financial statements.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the impacted account balances and disclosures and the subjectivity involved in assessing the impact of future regulatory orders on the financial statements.

Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and/or (2) a refund to customers.

7 unchanged sentences

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

• We evaluated management’s analysis regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

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

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

48 unchanged sentences

Interest expense 815.3 727.4 515.1

Loss on debt extinguishment — — 36.3

Gain on debt extinguishments ( 23.1 ) ( 0.5 ) —

Other expense ( 406.5 ) ( 371.7 ) ( 191.6 )

20 unchanged sentences

Derivatives accounted for as cash flow hedges

Net derivative gain, net of tax — — 0.6

Reclassification of realized net derivative (gain) loss to net income, net of tax ( 0.3 ) ( 0.3 ) 0.9

Cash flow hedges, net ( 0.3 ) ( 0.3 ) 1.5

Reclassification of realized derivative gains to net income, net of tax ( 0.3 ) ( 0.3 ) ( 0.3 )

Defined benefit plans

3 unchanged sentences

Defined benefit plans, net 0.2 ( 0.6 ) ( 3.3 )

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

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

Comprehensive income 1,524.2 1,330.8 1,406.1

39 unchanged sentences

17,178.1 15,366.9

Finance lease obligations 303.3 145.9

Deferred income taxes 5,514.7 4,918.5

4 unchanged sentences

AROs 580.0 374.2

Pension and OPEB obligations 176.0 171.6

Other 838.1 835.3

4 unchanged sentences

650,000,000 shares authorized;

315,434,531 shares outstanding

317,680,855 and 315,434,531 shares outstanding, respectively

Additional paid in capital 4,315.8 4,115.9

20 unchanged sentences

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

Net gain on disposition of assets ( 23.8 ) ( 66.2 ) ( 6.2 )

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

Accounts receivable and unbilled revenues, net ( 161.5 ) 340.6 ( 342.1 )

Materials, supplies, and inventories ( 38.0 ) 41.9 ( 171.3 )

Amounts recoverable from customers 17.4 60.0 ( 82.3 )

Collateral on deposit 84.3 22.1 ( 108.1 )

6 unchanged sentences

Capital expenditures ( 2,781.1 ) ( 2,492.9 ) ( 2,314.9 )

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

( 462.5 ) — —

Acquisition of Maple Flats, net of cash acquired of $ 0.5

( 431.2 ) — —

Acquisition of West Riverside ( 97.9 ) ( 95.3 ) —

Acquisition of Red Barn ( 2.1 ) ( 143.8 ) —

Acquisition of Whitewater — ( 76.0 ) —

3 unchanged sentences

— ( 257.3 ) —

Acquisition of Red Barn ( 143.8 ) — —

Acquisition of West Riverside ( 95.3 ) — —

Acquisition of Thunderhead, net of cash acquired of $ 0.5

— — ( 382.0 )

Acquisition of Jayhawk — — ( 119.9 )

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

Proceeds from the sale of assets 1.7 32.8 69.0

Proceeds from the sale of investments held in rabbi trust 10.4 15.4 18.7

Payments for ATC's construction costs that will be reimbursed ( 19.8 ) ( 24.8 ) ( 7.0 )

Reimbursement for ATC's construction costs 0.1 10.2 —

Insurance proceeds received for property damage 6.0 2.5 41.6

3 unchanged sentences

Exercise of stock options 23.7 6.3 33.6

Issuance of common stock, net 163.4 — —

Purchase of common stock ( 3.2 ) ( 16.6 ) ( 69.2 )

2 unchanged sentences

Retirement of long-term debt ( 2,138.0 ) ( 1,005.4 ) ( 92.1 )

Repayment of short-term loan ( 0.8 ) — ( 340.0 )

Change in commercial paper ( 902.8 ) 373.7 ( 252.6 )

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

Payments for debt extinguishment and issuance costs ( 45.9 ) ( 14.2 ) ( 15.6 )

9 unchanged sentences

WEC Energy Group Common Shareholders' Equity

Common Stock Additional Paid In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total Common Shareholders' Equity Preferred Stock of Subsidiary Non-controlling Interests Total Equity

Common Stock Additional Paid In Capital Retained Earnings Accumulated Other Comprehensive Loss Total Common Shareholders' Equity Preferred Stock of Subsidiary Non-controlling Interests Total Equity

(in millions, except per share amounts)

1 unchanged sentence

Net income attributed to common shareholders — — 1,408.1 — 1,408.1 — — 1,408.1

Net loss attributed to noncontrolling interests — — — — — — ( 3.0 ) ( 3.0 )

Other comprehensive income — — — 3.6 3.6 — — 3.6

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

Other comprehensive loss — — — ( 3.6 ) ( 3.6 ) — — ( 3.6 )

Common stock dividends of $ 2.91 per share

8 unchanged sentences

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 )

4 unchanged sentences

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 )

4 unchanged sentences

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

3 unchanged sentences

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 )

97 unchanged sentences

The deferred balance is returned to or recovered from customers at intervals throughout the year.

However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations, and we were not allowed to recover all of the additional costs.

See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs.

In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

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

Finally, through the end of 2023, PGL's rates included a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs.

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

Finally, 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.

5 unchanged sentences

All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

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Other Non-Utility Operating Revenues

1 unchanged sentence

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

Most of these renewable generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with capacity and RECs.

Most of these renewable generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with

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capacity and RECs.

We consider bundled energy, capacity, and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace.

33 unchanged sentences

We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

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(e) Credit Losses — The following discussion includes our significant accounting policies related to credit losses.

1 unchanged sentence

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 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

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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.

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.

12 unchanged sentences

(in millions) 2024 2023

Natural gas in storage $ 327.8 $ 446.3

Materials and supplies $ 412.5 $ 320.0

Natural gas in storage 300.2 327.8

Fossil fuel 100.5 127.4

5 unchanged sentences

In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $ 3.10 at December 31, 2024, and $ 2.13 at December 31, 2023.

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

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

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

2 unchanged sentences

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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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.

1 unchanged sentence

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.

67 unchanged sentences

For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value.

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

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

No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2024, 2023, and 2022.

11 unchanged sentences

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 the fourth quarter of 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.

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.

16 unchanged sentences

See Note 9, Asset Retirement Obligations, for more information.

(m) Intangible Liabilities — Our finite-lived intangible 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.

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

Amortization of the revenue contract intangible liabilities is recorded within operating revenues in the income statements.

(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.

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

The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used.

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

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

(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.

33 unchanged sentences

Restricted shares granted to employees generally have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date.

Restricted shares granted to certain officers and all non-employee directors fully vest after one year .

Restricted shares granted to non-employee directors fully vest after one year .

Our restricted shares are classified as equity awards.

5 unchanged sentences

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

The ultimate number of units that will be awarded 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.

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.

2 unchanged sentences

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.

The ultimate number of units awarded 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 %).

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

5 unchanged sentences

(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, as calculated using the treasury stock method.

Such dilutive securities include in-the-money stock options.

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.

(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 .

18 unchanged sentences

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

In September 2023, under this transferability provision, we entered into an agreement to sell substantially all of our 2023 PTCs to a third party.

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.

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 will 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.

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

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

We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

See Note 16, Income Taxes, for more information.

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

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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.

See Note 16, Income Taxes, for more information.

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value.

29 unchanged sentences

We elected not to net these items.

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

On our balance

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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.

2 unchanged sentences

(u) Employee Benefits — The costs of pension and OPEB plans are expensed over the periods during which employees render service.

These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as

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These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable.

Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP.

30 unchanged sentences

It was determined that all of the below acquisitions met the criteria of asset acquisitions.

The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs.

The purchase price of certain acquisitions below includes intangibles recorded as long-term assets and long-term liabilities related to PPAs.

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

Acquisitions of Electric Generation Facilities in Wisconsin

In June 2023, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises.

West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin.

Prior to acquisition, WPS received approval to transfer its ownership interest rights to WE.

WE's investment was $ 95.3 million.

In addition, WPS filed a request with the PSCW in September 2023 to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity.

As it did with the first option, in October 2023, WPS filed for approval to assign its ownership interest pursuant to this second option to WE.

If these approvals are obtained, WE's incremental share of this investment is expected to be approximately $ 100 million, with the transaction expected to close in 2024.

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In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility.

The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project.

WPS's share of the cost of this project was $ 143.8 million.

Red Barn qualifies for PTCs.

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 Solar Generation Facility in Texas

In February 2023, WECI completed the acquisition of an 80 % ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar County, Texas, for $ 257.3 million, which includes transaction costs and is net of cash acquired.

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.

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.

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.

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

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

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.

(in millions)

Other current assets $ 0.1

Net property, plant, and equipment 579.8

Other long-term assets 12.4

Other long-term liabilities ( 78.3 )

Noncontrolling interest ( 51.5 )

Total purchase price $ 462.5

In February 2023, WECI completed the acquisition of an 80 % ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas.

Samson I was acquired for $ 257.3 million, which included transaction costs and was net of cash acquired.

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 in May 2022.

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

12 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.

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

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.

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

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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 $ 469.5

Other long-term assets 44.5

Other long-term liabilities ( 34.9 )

Noncontrolling interest ( 47.9 )

Total purchase price $ 431.2

In February 2023, upon achievement of commercial operation, WECI completed the acquisition of a 90 % ownership interest in Sapphire Sky, a 250 MW wind generating facility in McLean County, Illinois, for a total investment of $ 442.6 million, which includes transaction costs and is net of cash acquired.

10 unchanged sentences

Total purchase price $ 442.6

In October 2022, WECI signed an agreement to acquire an 80 % ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $ 360 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.

The transaction is subject to FERC approval and commercial operation is expected to begin during the second half of 2024, at which time the transaction is expected to close.

Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

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Acquisitions of Electric Generation Facilities in Wisconsin

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

West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin.

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

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.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility.

The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project.

WPS's share of the cost of this project was $ 145.9 million.

Red Barn qualifies for PTCs.

Acquisition of a Wind Generation Facility in Nebraska

4 unchanged sentences

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

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

8 unchanged sentences

Total purchase price $ 382.0

Acquisition of a Wind Generation Facility in Kansas

In February 2021, WECI completed the acquisition of a 90 % ownership interest in Jayhawk, a 190 MW wind generating facility in Bourbon and Crawford counties, Kansas, for $ 119.9 million, which included transaction costs.

This project became commercially operational in December 2021.

Subsequent to the acquisition, WECI incurred an additional $ 161.3 million of capital expenditures as of December 31, 2022 for the project for a total investment of $ 281.2 million.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 10 years from the date of commercial operation.

Jayhawk qualifies for PTCs.

WECI is entitled to 99 % of the tax benefits related to this facility for the first 10 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest.

Jayhawk 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 $ 145.3

Other long-term liabilities ( 11.8 )

Long-term debt ( 7.3 )

Noncontrolling interest ( 6.3 )

Total purchase price $ 119.9

NOTE 3— DISPOSITIONS

4 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.

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Illinois Segment

4 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.

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NOTE 4— OPERATING REVENUES

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Total operating revenues $ 6,625.9 $ 1,557.8 $ 519.1 $ 8,702.8 $ 666.5 $ 0.1 $ ( 476.4 ) $ 8,893.0

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(in millions) Wisconsin Illinois Other States Total Utility

13 unchanged sentences

WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.

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Revenues from Contracts with Customers

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

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

16 unchanged sentences

Total natural gas utility operating revenues $ 1,980.7 $ 1,883.7 $ 601.8 $ 4,466.2

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(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.

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

(3) During 2021, in addition to costs related to the extreme weather event experienced in February 2021, we incurred higher natural gas costs as a result of an increase in the price of natural gas.

See Note 26, Regulatory Environment, for more information.

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(in millions) 2024 2023 2022

Late payment charges $ 56.5 $ 55.6 $ 54.9

Alternative revenues (1)

$ 79.8 $ 47.0 $ ( 30.3 )

Late payment charges 48.5 56.5 55.6

Other 3.9 4.2 4.0

Total other operating revenues $ 132.2 $ 107.7 $ 29.3

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WEC Energy Group, Inc.

(1) 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.

Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues.

Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups.

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

NOTE 5— CREDIT LOSSES

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93.8 % 100.0 % — % 93.2 % — % — % 93.2 %

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WEC Energy Group, Inc.

(in millions) Wisconsin Illinois Other States Total Utility

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As a result, at December 31, 2024, $ 1,029.0 million, or 61.6 %, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

See Note 26, Regulatory Environment, for more information on PGL and NSG's UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and amounts recovered in rates.

A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2024, 2023, and 2022, is included below:

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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

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WEC Energy Group, Inc.

the allowance for credit losses.

After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.

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.

(in millions)

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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.

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WEC Energy Group, Inc.

(in millions)

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Balance at December 31, 2022 $ 82.0 $ 111.0 $ 6.3 $ 199.3

The allowance for credit losses decreased during the year ended December 31, 2021, primarily related to normal collection practices resuming in April 2021 for our Wisconsin utilities and in June 2021 for our Illinois utilities.

Across all of our reportable segments, higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts.

2023 Form 10-K 110

WEC Energy Group, Inc.

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

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.

NOTE 6— REGULATORY ASSETS AND LIABILITIES

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Regulatory assets (1) (2)

Plant retirement related items (3)

$ 810.5 $ 646.2 24

Pension and OPEB costs (4)

684.9 731.7 20, 26

Plant retirement related items 646.2 688.6

Environmental remediation costs (5)

570.1 596.8 24

Income tax related items 449.9 461.9 16

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

AROs 166.7 162.0 1(l), 9

Derivatives 130.3 133.8 1(s)

Uncollectible expense 151.5 127.7 5

Decoupling 110.0 27.3 1(d)

Securitization 76.5 85.9 23

Bluewater (7)

Derivatives 38.2 130.3 1(s)

Energy efficiency programs (8)

Energy costs recoverable through rate adjustments 3.2 26.9 1(d)

MERC extraordinary natural gas costs (8)

Finance and operating leases 22.0 12.0 15

Other, net 122.7 112.5

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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 and $ 27.3 million at December 31, 2023 and 2022, respectively.

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

(2) As of December 31, 2024, we had $ 281.3 million of regulatory assets not earning a return, $ 2.3 million of regulatory assets earning a return based on short-term interest rates, $ 117.9 million of regulatory assets earning a return based on long-term interest rates, and $ 5.8 million of regulatory assets earning a return based on the applicable utility's ROE.

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

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 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.

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WEC Energy Group, Inc.

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

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

(8) Represents the extraordinary natural gas costs MERC incurred during February 2021 that were substantially recovered over 27 months, beginning in September 2021.

See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

2023 Form 10-K 111

WEC Energy Group, Inc.

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

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Energy costs refundable through rate adjustments 160.8 72.4 1(d)

Electric transmission costs (3)

Uncollectible expense 47.2 21.2 5

Revenue requirements of renewable generation facilities (3)

Derivatives 36.9 19.2 1(s)

Energy efficiency programs (4)

Decoupling — 20.2 1(d)

Electric transmission costs (4)

Other, net 102.4 71.2

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

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

(4) Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards.

Oak Creek Power Plant Units 5-6

In May 2024, OCPP Units 5 and 6 were retired.

Due to the retirement of these units and the determination that recovery was probable, their net book value of $ 75.3 million at December 31, 2024 was classified as a regulatory asset.

In addition, a $ 43.8 million cost of removal reserve related to the units continued to be classified as a regulatory liability at December 31, 2024.

Not included in these amounts was $ 8.6 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

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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

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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

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WEC Energy Group, Inc.

of these units were $ 4.8 million as of December 31, 2023.

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.

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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.

Effective with its rate order issued by the PSCW in December 2019, WE received approval to collect a return of and on its share of 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.

UMERC will also continue to amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired.

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.

UMERC will address the accounting and regulatory treatment related to the retirement of the PIPP with the MPSC in conjunction with a future rate case.

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 net book value.

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

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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 Unit 4

Edgewater Generating Station Unit 4

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

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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 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.

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

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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.

NOTE 7— PROPERTY, PLANT, AND EQUIPMENT

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Total severance liability at December 31 $ 13.4 $ 17.8 $ 16.2

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

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 5-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 5-8 became probable.

In early 2023, we received additional approvals for electric generation facilities, including Koshkonong and 100 MWs of West Riverside.

See Note 2, Acquisitions, for more information on the West Riverside acquisition, which was completed in June 2023.

OCPP Units 5 and 6 are expected to be retired by May 2024, while OCPP Units 7 and 8 are expected to be retired by late 2025.

The total net book value of WE's ownership share of OCPP Units 5-8 was $ 783.7 million at December 31, 2023, which does not include deferred taxes.

This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet.

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

Columbia Units 1 and 2

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 June 2026.

The total net book value of WPS's ownership share of Columbia

Oak Creek Power Plant Units 7 and 8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable.

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

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.

The total net book value of WE's ownership share of OCPP Units 7 and 8 was $ 657.4 million at December 31, 2024, which does not include deferred taxes.

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

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Units 1 and 2 was $ 259.8 million at December 31, 2023, which does not include deferred taxes.

plant, and equipment 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.

Columbia Energy Center Units 1 and 2

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

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

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

We anticipate appealing the ICC’s disallowance of these capital costs to the Illinois circuit court.

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.

See Note 26, Regulatory Environment, for more information.

Samson I Solar Energy Center LLC – Storm Damage

During wind storms in March and June 2023, certain sections of our Samson I solar facility incurred damage.

As of December 31, 2023, we recognized an impairment of $ 2.3 million related to storm damage, which was offset by a $ 2.3 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 this event.

Public Service Building and Steam Tunnel Assets

During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB.

The damage to the building and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations.

As of December 31, 2023, WE had incurred $ 95.3 million of costs related to these repairs and restorations.

In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base.

As a result, we do not currently expect a significant impact to our future results of operations.

NOTE 8— JOINTLY OWNED UTILITY FACILITIES

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70.0 % 383.4 2008 WPS 600.9 ( 230.7 ) 1.6

WPS Columbia Energy Center Units 1 and 2 (2) (5)

WPS Columbia Units 1 & 2 (2) (5)

27.5 % 307.5 1975 & 1978 WPL 436.5 ( 186.9 ) 4.0

8 unchanged sentences

WE West Riverside (2) (6)

13.8 % 84.9 2023

WE 108.7 ( 11.3 ) 0.9

27.5 % 190.5 2023 & 2024 WPL 217.8 ( 29.5 ) 3.2

WE Badger Hollow II (4)

66.7 % 100.0 2023 WE 179.4 ( 6.0 ) 0.4

WE, WPS Paris (solar portion) (4)

90.0 % 180.0 2024 WE 357.8 — 0.5

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

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(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 units are expected to be retired by June 2026.

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

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

(6 WE acquired its ownership interest in June 2023.

In September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity.

WPS subsequently filed for approval to assign its ownership interest pursuant to this second option to WE.

(6) 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 Koshkonong, a utility-scale solar-powered electric generating facility.

The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will c ollectively own 90 %, or 270 MWs of solar generation of this project.

Commercial operation of the solar facility is targeted for 2026.

Our CWIP balance for Koshkonong was not significant as of December 31, 2023.

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 project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 90 %, or 180 MWs of solar generation and 99 MWs of battery storage of this project.

Commercial operation of the solar facility is targeted for 2024 and construction of the battery storage is expected to be completed in 2025.

Our CWIP balance for Paris was $ 334.3 million as of December 31, 2023.

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

The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 90 %, or 225 MWs of solar generation of this project.

Commercial operation of the solar facility is targeted for 2024.

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.

NOTE 9— ASSET RETIREMENT OBLIGATIONS

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Revisions to estimated cash flows 6.4 ( 133.5 ) (2)

2.2 ( 84.9 ) (5)

Liabilities settled ( 12.1 ) ( 12.8 ) ( 13.8 )

Balance as of December 31 $ 580.0 $ 374.2 $ 479.3

(1) AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Red Barn wind-powered generation project, the Badger Hollow II solar generation project, and the Sapphire Sky and Samson I non-utility renewable generation projects.

(1) AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024.

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

2024 Form 10-K 129

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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.

(3) AROs increased primarily as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project.

(4) AROs increased as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility renewable generation projects.

(5) AROs decreased due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG.

Partially offsetting this decrease were revisions made to removal estimates for wind generation projects at WE and WPS and for fly ash landfills and ash ponds at WPS.

NOTE 10— GOODWILL AND INTANGIBLES

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No impairments resulted from these tests.

Intangible Assets

At December 31, 2023 and 2022, we had $ 29.3 million and $ 24.9 million, respectively, of indefinite-lived intangible assets, largely consisting of spectrum frequencies.

During 2023, we purchased additional spectrum frequencies for $ 4.4 million.

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.

1 unchanged sentence

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

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.

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.

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 to be recorded as a decrease to operating revenues is expected to be $ 0.9 million in each of the next five years.

See Note 2, Acquisitions, for more information on the acquisition of Maple Flats.

Intangible Liabilities

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Total intangible liabilities $ 691.5 $ ( 124.7 ) $ 566.8 $ 665.8 $ ( 71.0 ) $ 594.8

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, and Sapphire Sky expiring between 2030 and 2037.

(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.

The weighted-average remaining useful life of the PPAs is 11 years.

See Note 2, Acquisitions, for more information on the acquisitions of Samson I and Sapphire Sky in 2023.

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

(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 five years .

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

2024 Form 10-K 130

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The long-term debt obligations of UMERC, Bluewater Gas Storage, and ATC Holding contain a provision requiring them to maintain a total funded debt to capitalization ratio of 65 % or less.

WECI Wind Holding I's and WECI Wind Holding II's long-term debt obligations contain various conditions that must be met prior to them making any cash distributions.

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 2007 Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period.

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.

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

Share Purchases

During the years ended December 31, 2023, 2022, and 2021, we instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

As a result, no new shares of common stock were issued during these years.

As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under these plans.

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.

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.

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.

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WEC Energy Group, Inc.

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

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

Shares issued:

At-the-market offering program 1,030,674

Stock-based compensation 455,474

401(k) 336,800

Stock investment plan 423,376

Common stock shares outstanding at end of period 317,680,855

The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31:

(in millions) 2023 2022 2021

(in millions, except share amounts) 2024 2023 2022

Shares purchased 23,292 182,795 687,416

Cost of shares purchased $ 3.2 $ 16.6 $ 69.2

Common Stock Dividends

During the year ended December 31, 2024, our Board of Directors declared common stock dividends which are summarized below:

4 unchanged sentences

October 17, 2024 December 1, 2024 $ 0.835 Fourth quarter

2023 Form 10-K 120

WEC Energy Group, Inc.

On January 16, 2025, our Board of Directors declared a quarterly cash dividend of $ 0.8925 per share, which equates to an annual dividend of $ 3.57 per share.

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

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

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.

Our average amount of commercial paper borrowings based on daily outstanding balances during 2024, was $ 1,313.4 million with a weighted-average interest rate during the period of 5.38 %.

1 unchanged sentence

As of December 31, 2024, all companies were in compliance with their respective ratio.

2023 Form 10-K 121

WEC Energy Group, Inc.

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

17 unchanged sentences

Each extension is for a period of one year .

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

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

4 unchanged sentences

NOTE 14— LONG-TERM DEBT

The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31:

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

(in millions) Maturity Date Weighted Average Interest Rate Balance Weighted Average Interest Rate Balance

WEC Energy Group Senior Notes (unsecured) 2025-2033 4.13 % $ 6,045.0 3.68 % $ 5,320.0

2024-2033 3.68 % $ 5,320.0 2.44 % $ 3,970.0

WEC Energy Group Junior Notes (unsecured) (1) (2)

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WG Debentures (unsecured) 2025-2046 3.92 % 840.0 3.35 % 790.0

Integrys Junior Notes (unsecured) 2073 — % — 6.00 % 221.4

PGL First and Refunding Mortgage Bonds (secured) (3)

15 unchanged sentences

2025-2031 6.38 % 167.6 6.38 % 191.4

WECI Energy Holding III Senior Notes (secured, nonrecourse) (5) (9)

2025-2039 5.73 % 488.7 — % —

Total 19,023.9 16,724.3

Integrys acquisition fair value adjustment — 1.2

Jayhawk acquisition 7.5 7.5

2 unchanged sentences

Total long-term debt, including current portion 18,907.1 16,631.1

16,631.1 15,464.2

Current portion of long-term debt ( 1,729.0 ) ( 1,264.2 )

Total long-term debt $ 17,178.1 $ 15,366.9

(1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt).

Our 6.20 % Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC.

The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities.

The terms of the RCC have been previously satisfied.

(2) Variable interest rates reset quarterly.

The rates were 7.75 % and 6.72 % as of December 31, 2023 and 2022, respectively.

(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.

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

Our 2024A Junior Notes and 2024B Junior Notes are fixed-to-fixed reset rate junior subordinated notes.

The rate for our 2024A Junior Notes was 6.69 % as of December 31, 2024.

The rate for our 2024A Junior Notes will reset on June 15, 2030.

The rate for our 2024B Junior Notes was 6.74 % as of December 31, 2024.

The rate for our 2024B Junior Notes will reset on June 15, 2035.

(3) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented.

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Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

(5) The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, WEPCo Environmental Trust, and We Power's subsidiaries requires periodic principal payments.

(5) The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, WECI Energy Holding III, WEPCo Environmental Trust, and We Power's subsidiaries requires periodic principal payments.

(6) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable.

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(8) WECI Wind Holding II's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Wind Holding II.

(9) WECI Energy Holding III's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Energy Holding III.

(10) WEPCo Environmental Trust’s ETBs are secured by a pledge of and lien on environmental control property, which includes the right to impose, collect and receive a non-bypassable environmental control charge paid by all of WE's retail electric distribution customers, the right to obtain true-up adjustments of the environmental control charges, and all revenues or other proceeds arising from those rights and interests.

See Note 23, Variable Interest Entities, for more information.

(10) The amount of long-term debt on our balance sheets includes finance lease obligations of $ 145.9 million and $ 183.2 million at December 31, 2023 and 2022, respectively.

We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.

In March 2022, President Biden signed into law the Adjustable Interest Rate (LIBOR) Act.

This Act established a uniform process, on a nationwide basis, for replacing LIBOR in certain contracts that did not provide a clearly defined or practicable replacement benchmark rate.

Under the LIBOR Act, the Federal Reserve Board was required to determine an appropriate benchmark replacement based on SOFR, with applicable credit spread adjustments.

In December 2022, the Federal Reserve Board adopted the final rule to implement the LIBOR Act and established the SOFR-based benchmark replacements.

No contract modifications were required for qualifying contracts under the LIBOR Act as the benchmark replacement automatically overrode the existing contract language and became the applicable benchmark after June 30, 2023.

For our $ 500 million of 2007 Junior Notes, starting August 15, 2023, the benchmark replacement rate is the applicable tenor of three-month CME Term SOFR, as administered by the CME Group Benchmark Administration, and includes a credit spread adjustment of 0.26161 % per annum.

In accordance with the LIBOR Act, no contract modifications were required for our 2007 Junior Notes as the references to LIBOR were replaced by operation of law.

In December 2024, the DOE issued to WE a conditional commitment for a federal loan guarantee for up to $ 2.5 billion of borrowings that would be used by WE to fund a portion of the costs to construct certain utility-scale renewable generation projects.

The conditional commitment was issued pursuant to provisions of the IRA.

Under the conditional commitment, the guaranteed borrowings would be senior, unsecured borrowings of WE made through the Federal Financing Bank and reduce WE's issuance of senior, unsecured obligations in the capital markets.

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

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.

WEC Energy Group, Inc.

In January 2023, we issued $ 650.0 million of 4.75 % Senior Notes due January 9, 2026, and $ 450.0 million of 4.75 % Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other corporate purposes.

In April 2023, we issued an additional $ 350.0 million of our 4.75 % Senior Notes due January 9, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes.

In September 2023, we issued $ 600.0 million of 5.60 % Senior Notes due September 12, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes.

Subsequently, we repaid the outstanding principal and accrued interest on our $ 700.0 million of 0.55 % Senior Notes that matured on September 15, 2023.

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.

Integrys Holding, Inc.

In March 2023, Integrys repurchased $ 18.9 million of the $ 221.4 million outstanding of its 6.00 % 2013 Junior Notes, prior to maturity for $ 18.6 million.

Integrys recognized an insignificant gain on the early extinguishment of debt due to the debt being repurchased at a discount.

On August 1, 2023, Integrys redeemed the remaining $ 202.5 million outstanding of its 6.00 % 2013 Junior Notes, prior to maturity at par value.

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.

Convertible Senior Notes

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

The 2027 Notes and 2029 Notes are senior unsecured obligations and bear interest at an annual rate of 4.375 %, payable semiannually beginning on December 1, 2024.

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

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

2024 Form 10-K 137

WEC Energy Group, Inc.

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.

We may not redeem the 2027 Notes prior to their maturity date.

We may redeem for cash all or part of the 2029 Notes, at our option, on or after June 1, 2027 and on or before the 41 st scheduled trading day immediately preceding their maturity date, if the last reported sale price per share of our common stock has been at least 130 % of the conversion price of the 2029 Notes then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period.

Any redemptions or fundamental change repurchases of the 2027 Notes or 2029 Notes will be at a price equal to 100 % of the principal amount, plus accrued and unpaid interest.

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, 2027, in the case of the 2027 Notes, and March 1, 2029, in the case of the 2029 Notes, only under the following circumstances:

• 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;

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

• In the case of the 2029 Notes only, if we call any of the 2029 Notes for redemption, at any time prior to the close of business on the second scheduled trading day prior to the redemption date, but only with respect to the 2029 Notes called (or deemed called) for redemption.

Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2027, in the case of the 2027 Notes, or March 1, 2029, in the case of the 2029 Notes, until the close of business on the second scheduled trading day immediately preceding the maturity date of such series of notes.

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 both the 2027 Notes and 2029 Notes is 10.1243 shares of common stock per $ 1,000 principal amount, which is equivalent to an initial conversion price of approximately $ 98.77 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 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.

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.

The following is a summary of our convertible debt instruments as of December 31, 2024:

(in millions) Principal Amount

Unamortized Debt Issuance Costs

Net Carrying Amount

Fair Value Amount (1)

$ 862.5 $ ( 8.0 ) $ 854.5 $ 920.6

862.5 ( 8.8 ) 853.7 929.1

(1) The fair values are categorized in Level 2 of the fair value hierarchy.

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:

(in millions) 2024

Contractual interest expense

Amortization of debt issuance costs

Total interest expense – 2027 Notes 24.2

Contractual interest expense

Amortization of debt issuance costs

Total interest expense – 2029 Notes $ 23.5

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.

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.

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 2023, PGL issued $ 100.0 million of 5.82 % First and Refunding Mortgage Bonds, Series NNN due April 1, 2029, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

North Shore Gas Company

In November 2023, NSG issued $ 20.0 million of 5.82 % First Mortgage Bonds, Series T due April 1, 2029, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

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.

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.

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WEC Energy Group, Inc.

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

The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2023:

The following table shows the long-term debt securities maturing within one year of December 31, 2024:

(in millions) Interest Rate Maturity Date (1)

Principal Amount

WEC Energy Group Senior Notes (unsecured) 0.80 % March $ 600.0

WG Debentures (unsecured) 2.38 % November 150.0

PGL Bonds (secured) 2.64 % November 75.0

WE Debentures (unsecured) 2.05 % December 300.0

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) 5.00 % September 500.0

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 9.2

Bluewater Gas Storage Senior Notes (unsecured) 3.76 % Semi-annually 3.0

Bluewater Gas Storage Senior Notes (unsecured) 5.41 % Semi-annually 0.9

We Power Subsidiaries Notes – PWGS (secured, nonrecourse) 4.91 % Monthly 8.4

4 unchanged sentences

WECI Wind Holding II Senior Notes (secured, nonrecourse) 6.38 % Semi-annually 19.6

WECI Energy Holding III Senior Notes (secured, nonrecourse) 5.73 % Semi-annually 42.5

Total $ 1,729.0

(1) Maturity dates listed as semi-annually and monthly are associated with debt that requires periodic principal payments.

The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2023:

The following table shows the future maturities of our long-term debt outstanding as of December 31, 2024:

(in millions) Payments

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• 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 May 2073.

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

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

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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

We have various land leases related to our investments in non-utility solar generation.

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

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

2024 Form 10-K 141

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

(5) Because our leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

(5) Because our leases do not provide an implicit rate of return, we used an estimate of the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

2024 Form 10-K 142

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Finance lease right of use assets, net

Power purchase commitment (1)

Land leases – utility solar generation $ 235.8 $ 132.7

Land leases –non-utility energy infrastructure solar generation 43.5 —

Other 2.0 1.1

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Current finance lease liabilities

Power purchase commitment (1)

$ — $ 72.7 Current portion of long-term debt

Other $ 0.2 $ — Other current liabilities

Long-term finance lease liabilities

Land leases – utility solar generation $ 257.9 $ 144.8

Land leases –non-utility energy infrastructure solar generation 43.8 —

Other 1.6 1.1

Total long-term finance lease liabilities $ 145.9 $ 110.5 Long-term debt

(1) Effective January 1, 2023, WE and WPS closed on the acquisition of Whitewater.

See discussion above for more information.

Total long-term finance lease liabilities $ 303.3 $ 145.9 Finance lease obligations

(1) Amounts are net of accumulated amortization of $ 10.0 million and $ 6.1 million at December 31, 2024 and 2023, respectively.

Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2024, were as follows:

(in millions) Total Operating Leases Land Leases - Utility Solar Generation Other Total Finance Leases

(in millions) Total Operating Leases Land Leases - Utility Solar Generation Land Leases - Non-Utility Energy Infrastructure Solar Generation Other Total Finance Leases

2025 $ 6.0 $ 7.3 $ 3.3 $ 0.3 $ 10.9

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Long-term lease liabilities $ 37.5 $ 257.9 $ 43.8 $ 1.6 $ 303.3

As of February 22, 2024, we have not entered into any material leases that have not yet commenced.

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.

2024 Form 10-K 143

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2024 2023 2022

Effective Effective Effective

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

(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 %

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AFUDC-Equity ( 12.6 ) ( 0.7 ) % ( 12.4 ) ( 0.8 ) % ( 6.2 ) ( 0.4 ) %

Federal excess deferred tax amortization – Wisconsin unprotected (2)

( 0.8 ) ( 0.1 ) % ( 0.8 ) — % ( 77.9 ) ( 5.2 ) %

Other, net ( 3.9 ) ( 0.2 ) % 5.9 0.3 % 0.4 — %

2 unchanged sentences

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.

(2) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities amortized these unprotected deferred tax benefits over periods ranging from two years to four years , to reduce near-term rate impacts to their customers.

See Note 26, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate orders.

2023 Form 10-K 129

WEC Energy Group, Inc.

Deferred Income Tax Assets and Liabilities

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Deferred tax liability, net $ 5,514.7 $ 4,918.5

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.

22 unchanged sentences

Balance as of December 31 $ 4.4 $ 4.6 $ 6.3

2023 Form 10-K 130

WEC Energy Group, Inc.

The amount of unrecognized tax benefits as of December 31, 2024 and 2023, excludes deferred tax assets related to uncertainty in income taxes of $ 1.0 million and $ 1.1 million, respectively.

3 unchanged sentences

Balance as of January 1 $ 0.6 $ 0.5 $ 0.1

Interest expense (income) related to unrecognized tax benefits 0.1 0.4 ( 0.4 )

Interest expense related to unrecognized tax benefits 0.3 0.1 0.4

Balance as of December 31 $ 0.9 $ 0.6 $ 0.5

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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 with varying statutes of limitations.

We also file tax returns in other state and local jurisdictions

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WEC Energy Group, Inc.

with varying statutes of limitations.

As of December 31, 2024, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2020 through 2024 tax years in our major operating jurisdictions as follows:

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FTRs and TCRs — — 7.8 7.8

Coal contracts — 0.3 — 0.3

Total derivative assets $ 19.6 $ 13.7 $ 7.8 $ 41.1

2 unchanged sentences

Natural gas contracts $ 7.1 $ 6.8 $ — $ 13.9

Coal contracts — 20.3 — 20.3

Total derivative liabilities $ 70.1 $ 36.3 $ — $ 106.4

2023 Form 10-K 131

WEC Energy Group, Inc.

December 31, 2023

2 unchanged sentences

Natural gas contracts $ 2.2 $ 8.3 $ — $ 10.5

FTRs — — 7.8 7.8

FTRs and TCRs — — 7.2 7.2

Coal contracts — 0.3 — 0.3

3 unchanged sentences

Natural gas contracts $ 70.1 $ 16.0 $ — $ 86.1

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.

They also include FTRs and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets and the SPP Integrated Marketplace, respectively.

Integrated Marketplace, respectively.

We hold investments in the Integrys rabbi trust.

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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.

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

2 unchanged sentences

Purchases 28.7 21.0 23.7

Realized and unrealized net gains (losses) included in earnings (1)

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

( 0.7 ) ( 0.5 ) 0.5

1 unchanged sentence

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

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

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

$ — $ 0.5 $ ( 0.4 )

(1) Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment.

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

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

Fair Value of Financial Instruments

3 unchanged sentences

Long-term debt, including current portion 18,907.1 17,840.8 16,631.1 15,564.3

16,631.1 15,564.3 15,464.2 13,921.3

(1) The carrying amount of long-term debt excludes finance lease obligations of $ 145.9 million and $ 183.2 million at December 31, 2023 and 2022, respectively.

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

2023 Form 10-K 132

WEC Energy Group, Inc.

NOTE 18— DERIVATIVE INSTRUMENTS

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December 31, 2024 December 31, 2023

(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities

(in millions) Derivative

Assets Derivative

Liabilities Derivative

Assets Derivative

Natural gas contracts $ 29.2 $ 13.9 $ 10.4 $ 78.1

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Total $ 41.1 $ 13.9 $ 18.0 $ 106.4

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;

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December 31, 2024 December 31, 2023 December 31, 2022

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

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

Natural gas contracts 206.3 Dth

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25.9 27.2 MWh

11.8 28.2 MWh

Total $ ( 119.6 ) $ ( 233.2 ) $ 311.3

At December 31, 2024 and 2023, we had posted cash collateral of $ 16.0 million and $ 100.3 million, respectively.

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

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

December 31, 2024 December 31, 2023

(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities

(in millions) Derivative

Assets Derivative

Liabilities Derivative

Assets Derivative

Gross amount recognized on the balance sheet $ 41.1 $ 13.9 $ 18.0 $ 106.4

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Net amount $ 29.6 $ 6.6 $ 14.9 $ 35.4

(1) Includes cash collateral posted of $ 67.9 million.

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

(2) Includes cash collateral posted of $ 67.9 million.

Cash Flow Hedges

Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $ 250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes.

The swaps provided a fixed interest rate of 4.9765 % on $ 250.0 million of the $ 500.0 million of outstanding 2007 Junior Notes.

As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses were deferred in accumulated other comprehensive loss and were amortized to interest expense as interest was accrued on the 2007 Junior Notes.

We also previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys.

These swap agreements were settled in 2015, and we continue to

2023 Form 10-K 133

WEC Energy Group, Inc.

amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The derivative gains and losses related to these swap agreements recognized in other comprehensive income and reclassified from accumulated other comprehensive loss to interest expense during the years ended December 31, 2023, 2022, and 2021 were not significant.

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys.

These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the years ended December 31, 2024, 2023, and 2022 were not significant.

At December 31, 2024, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

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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.

Generally, 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, while employees who started before 1996 receive a benefit based upon years of service and final average salary.

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.

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.

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

2023 Form 10-K 134

WEC Energy Group, Inc.

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

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Participant contributions — — 11.2 11.8

Plan amendments — — — 0.2

Actuarial (gain) loss ( 99.6 ) 81.9 6.9 45.9

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(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 2023, we had actuarial losses related to our pension benefit obligations of $ 81.9 million and actuarial gains in 2022 of $ 682.3 million.

The primary driver for the actuarial loss was a lower discount rate in 2023.

Partially offsetting the loss in 2023, was higher than expected asset returns.

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.

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

Partially offsetting the gain in 2024, was lower than expected asset returns.

The discount rate for our pension benefits was 5.69 %, 5.19 %, and 5.49 % in 2024, 2023, and 2022, respectively.

In 2023, we had actuarial losses related to our OPEB benefit obligation of $ 45.9 million and actuarial gains in 2022 of $ 127.9 million.

The primary driver for the actuarial loss was changes to medical trend assumptions and a lower discount rate in 2023.

Partially offsetting the loss in 2023, was higher than expected asset returns.

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.

The discount rate for our OPEB benefits was 5.71 %, 5.16 %, and 5.50 % in 2024, 2023, and 2022, respectively.

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Pension and OPEB assets $ 562.4 $ 475.2 $ 406.1 $ 395.7

Pension and OPEB obligations 161.8 158.5 14.2 13.1

Other long-term liabilities 147.3 161.8 17.0 14.2

Total net assets $ 415.1 $ 313.4 $ 389.1 $ 381.5

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Fair value of plan assets 143.2 147.3

2023 Form 10-K 135

WEC Energy Group, Inc.

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

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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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Plan settlement 4.0 1.3 6.2 — — —

Plan curtailment — — — — — ( 6.4 )

Amortization of prior service cost (credit) ( 0.1 ) — 1.6 ( 13.5 ) ( 14.8 ) ( 15.9 )

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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, 2023, we recorded a $ 6.0 million regulatory asset for pension costs and a $ 14.8 million regulatory asset for OPEB costs.

The above table does not reflect any adjustments for the creation of these regulatory assets.

2023 Form 10-K 136

WEC Energy Group, Inc.

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.

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 2031 2028

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

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WEC Energy Group, Inc.

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

For 2025, the expected return on assets assumption is 6.61 % for the pension plans and 6.50 % for the OPEB plans.

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They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

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

The legacy Integrys pension trust target asset allocations are 25 % equity investments, 55 % fixed income investments, and 20 % private equity and real estate investments.

The legacy Wisconsin

2023 Form 10-K 137

WEC Energy Group, Inc.

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

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 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, 2023

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We expect to contribute $ 12.1 million to the pension plans and $ 2.6 million to the OPEB plans in 2025, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

2023 Form 10-K 138

WEC Energy Group, Inc.

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

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Total costs incurred under all of these plans were $ 61.6 million, $ 57.5 million, and $ 54.4 million in 2024, 2023, and 2022, respectively.

2024 Form 10-K 153

WEC Energy Group, Inc.

NOTE 21— INVESTMENT IN TRANSMISSION AFFILIATES

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Distributions 146.7 3.4 150.1

Other 0.1 — 0.1

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

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Balance at January 1 $ 1,766.9 $ 22.5 $ 1,789.4

Earnings (loss) from equity method investment 166.4 ( 8.3 ) 158.1

Earnings from equity method investment 192.6 2.1 194.7

Capital contributions 45.5 — 45.5

Distributions 120.4 — 120.4

Balance at December 31 $ 1,884.6 $ 24.6 $ 1,909.2

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

Due to the various petitions related to the complaint filed in February 2015, our financials at December 31, 2021 and 2020, included a $ 39.1 million liability for potential future refunds that ATC may have been required to provide.

In August 2022, a decision issued by

2023 Form 10-K 139

WEC Energy Group, Inc.

Circuit Court of Appeals affirmed the FERC’s previous orders related to the February 2015 complaint.

Therefore, during the third quarter of 2022, we reversed the liability that was previously recorded, which increased our equity earnings from ATC.

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 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.

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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:

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Charges from ATC for network transmission services 413.3 377.5 363.7

Net refund (payment) from (to) ATC related to FERC ROE orders — ( 0.1 ) 7.3

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

As of December 31, 2024 and 2023, our balance sheets included the following receivables and payables for services provided to or received from ATC:

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Amounts due from ATC for transmission infrastructure upgrades (1)

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

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

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

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NOTE 22— SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses.

Our President and CEO, who is our CODM, reviews financial information presented on a segment basis for purposes of making operating decisions and assessing performance.

The CODM regularly reviews net income attributed to common shareholders to measure segment profitability and to allocate resources, including assets, to our businesses.

Net income attributed to common shareholders best measures our segment profitability as it reflects all revenues and costs, including the impact on our tax provision from tax credits generated through investments in renewable generation facilities.

Our CODM allocates resources such as employees as well as financial and capital resources to our segments during the annual review of budgets and the capital plan.

Our CODM also reviews and revises the resources throughout the year during the monthly forecasting process in order to make timely decisions that align with our overall corporate strategy.

The CODM uses each segment’s net income to evaluate performance by comparing actual results to budgeted and forecasted amounts, as well as the ROE earned for each utility within the various utility segments.

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.

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

At December 31, 2024, we reported six segments, which are described below.

All of our operations are located within the United States.

• The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.

• The Illinois segment includes the natural gas utility operations of PGL and NSG.

2023 Form 10-K 140

WEC Energy Group, Inc.

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

• 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.

• The non-utility energy infrastructure segment includes:

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• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

All of our operations and assets are located within the United States.

2024 Form 10-K 156

WEC Energy Group, Inc.

The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2024, 2023, and 2022.

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2024 (in millions)

Wisconsin Illinois Other States Total Utility

Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling

Eliminations WEC Energy Group Consolidated

Wisconsin Illinois Other States Total Utility Operations

Electric Transmission Non-Utility Energy Infrastructure Corporate and Other

Reconciling Eliminations

WEC Energy Group Consolidated

External revenues $ 6,330.5 $ 1,602.4 $ 449.8 $ 8,382.7 $ — $ 217.2 $ — $ — $ 8,599.9

Intersegment revenues — — — — — 474.1 — ( 474.1 ) —

Fuel and purchased power

1,455.7 — — 1,455.7 — — — — 1,455.7

Cost of natural gas sold

661.9 376.7 198.6 1,237.2 — 9.1 — ( 46.0 ) 1,200.3

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

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

Property and revenue taxes

169.6 59.9 21.0 250.5 — 15.7 0.3 — 266.5

Equity in earnings of transmission affiliates — — — — 207.5 — — — 207.5

Other income, net (1)

146.6 7.6 0.3 154.5 — 1.0 54.4 ( 31.7 ) 178.2

Interest expense 637.3 94.7 16.4 748.4 19.4 99.7 310.0 ( 362.2 ) 815.3

Gain on debt extinguishments

— — — — — — ( 23.1 ) — ( 23.1 )

Income tax expense (benefit) 220.5 97.6 18.7 336.8 47.1 ( 82.4 ) ( 79.5 ) — 222.0

Net income (loss) 852.5 140.0 48.1 1,040.6 119.1 334.8 ( 162.8 ) — 1,331.7

Preferred stock dividends of subsidiary

1.2 — — 1.2 — — — — 1.2

Net loss attributed to noncontrolling interests

— — — — — 4.1 — — 4.1

Net income (loss) attributed to common shareholders $ 863.1 $ 252.1 $ 54.5 $ 1,169.7 $ 141.0 $ 380.8 $ ( 164.3 ) $ — $ 1,527.2

Other Segment Disclosures

Capital expenditures and asset acquisitions $ 2,347.1 $ 343.0 $ 118.3 $ 2,808.4 $ — $ 945.8 $ 20.6 $ — $ 3,774.8

Equity method investments

15.7 — — 15.7 2,108.9 — 67.0 — 2,191.6

Total assets (2)

30,622.7 8,168.8 1,646.0 40,437.5 2,126.0 7,316.0 1,037.3 ( 3,553.6 ) 47,363.2

(1) Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2) Total assets at December 31, 2024 reflect an elimination of $ 1,525.4 million for all lease activity between We Power and WE.

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2023 (in millions)

Wisconsin Illinois Other States Total Utility

Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling

Eliminations WEC Energy Group Consolidated

Wisconsin Illinois Other States Total Utility Operations

Electric Transmission Non-Utility Energy Infrastructure Corporate and Other

Reconciling Eliminations

WEC Energy Group Consolidated

External revenues $ 6,625.9 $ 1,557.8 $ 519.1 $ 8,702.8 $ — $ 190.1 $ 0.1 $ — $ 8,893.0

Intersegment revenues — — — — — 476.4 — ( 476.4 ) —

Fuel and purchased power

1,615.9 — — 1,615.9 — — — — 1,615.9

Cost of natural gas sold

894.7 443.0 277.2 1,614.9 — 20.5 — ( 60.1 ) 1,575.3

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

Impairment related to ICC disallowances — 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

Property and revenue taxes

179.2 29.9 24.4 233.5 — 16.5 0.2 — 250.2

Equity in earnings of transmission affiliates — — — — 177.5 — — — 177.5

Other income, net (1)

137.6 6.7 0.6 144.9 — — 53.3 ( 20.5 ) 177.7

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

Net income (loss) 759.6 226.9 39.7 1,026.2 129.5 324.8 ( 70.8 ) — 1,409.7

Preferred stock dividends of subsidiary

1.2 — — 1.2 — — — — 1.2

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

Other Segment Disclosures

Capital expenditures and asset acquisitions $ 2,134.4 $ 489.8 $ 103.5 $ 2,727.7 $ — $ 754.4 $ 25.8 $ — $ 3,507.9

Equity method investments

14.4 — — 14.4 2,005.9 — 61.3 — 2,081.6

Total assets (2)

28,527.3 7,970.2 1,571.5 38,069.0 2,006.0 6,404.7 1,100.1 ( 3,640.1 ) 43,939.7

(1) Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2) Total assets at December 31, 2023 reflect an elimination of $ 1,630.6 million for all lease activity between We Power and WE.

2024 Form 10-K 158

WEC Energy Group, Inc.

Utility Operations

2022 (in millions)

Wisconsin Illinois Other States Total Utility

Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling

Eliminations WEC Energy Group Consolidated

Wisconsin Illinois Other States Total Utility Operations

Electric Transmission Non-Utility Energy Infrastructure Corporate and Other

Reconciling Eliminations

WEC Energy Group Consolidated

External revenues $ 6,960.5 $ 1,890.9 $ 618.5 $ 9,469.9 $ — $ 127.0 $ 0.5 $ — $ 9,597.4

Intersegment revenues — — — — — 463.0 — ( 463.0 ) —

Fuel and purchased power

1,881.4 — — 1,881.4 — — — — 1,881.4

Cost of natural gas sold

1,327.4 792.5 391.6 2,511.5 — 17.9 — ( 51.9 ) 2,477.5

Other operation and maintenance 1,351.3 459.2 98.5 1,909.0 — 51.0 ( 12.9 ) ( 9.1 ) 1,938.0

Depreciation and amortization 754.7 230.9 40.9 1,026.5 — 139.2 25.0 ( 68.1 ) 1,122.6

Property and revenue taxes

182.6 38.6 23.3 244.5 — 9.1 0.1 — 253.7

Equity in earnings of transmission affiliates — — — — 194.7 — — — 194.7

Other income, net (1)

99.9 14.1 2.5 116.5 — — 14.6 ( 2.3 ) 128.8

Interest expense 555.9 73.8 13.9 643.6 19.4 68.9 119.4 ( 336.2 ) 515.1

Loss on debt extinguishment — — — — — — 36.3 — 36.3

Income tax expense (benefit) 247.5 83.1 13.1 343.7 45.8 ( 20.9 ) ( 45.7 ) — 322.9

Net income (loss) 707.7 223.0 35.8 966.5 106.3 276.2 ( 50.5 ) — 1,298.5

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

Net income attributed to noncontrolling interests

— — — — — ( 0.4 ) — — ( 0.4 )

Net income (loss) attributed to common shareholders $ 758.4 $ 226.9 $ 39.7 $ 1,025.0 $ 129.5 $ 324.4 $ ( 70.8 ) $ — $ 1,408.1

Other Segment Disclosures

Capital expenditures and asset acquisitions $ 1,610.8 $ 484.9 $ 101.1 $ 2,196.8 $ — $ 483.8 $ 16.3 $ — $ 2,696.9

Equity method investments

13.6 — — 13.6 1,909.2 — 59.1 — 1,981.9

Total assets (2)

27,384.0 8,101.0 1,639.6 37,124.6 1,909.4 5,320.6 774.0 ( 3,256.5 ) 41,872.1

(1) Includes amounts that are not material for interest income and other equity earnings from investments other than from transmission affiliates.

(2) Total assets at December 31, 2022 reflect an elimination of $ 1,632.9 million for all lease activity between We Power and WE.

2023 Form 10-K 142

WEC Energy Group, Inc.

NOTE 23— VARIABLE INTEREST ENTITIES

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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.

2024 Form 10-K 159

WEC Energy Group, Inc.

WEPCo Environmental Trust Finance I, LLC

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Therefore, WE is considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.

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

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

(in millions) December 31, 2024 December 31, 2023

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

At December 31, 2023 and 2022, our equity

2023 Form 10-K 143

WEC Energy Group, Inc.

investment in ATC was $ 1,980.8 million and $ 1,884.6 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

At December 31, 2024 and 2023, our equity investment in ATC was $ 2,085.1 million and $ 1,980.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

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.

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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.

Power Purchase Commitment

On May 31, 2022, WE's PPA with LSP-Whitewater Limited Partnership that represented a variable interest expired.

This agreement was for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we accounted for it as a finance lease.

In November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022, upon the expiration of the PPA.

Concurrent with the execution of the tolling agreement, WE and WPS also entered into an agreement to purchase the natural gas-fired cogeneration facility.

This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023.

See Note 2, Acquisitions, for more information on the acquisition of this facility.

The tolling agreement represented a variable interest until the facility was acquired since its terms were substantially similar to the terms of the PPA.

Based on the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we were not the primary beneficiary of the entity.

We did not hold an equity or debt interest in the entity, and there was no residual guarantee associated with the tolling agreement.

Similar to the PPA, we accounted for the tolling agreement as a finance lease.

2024 Form 10-K 160

WEC Energy Group, Inc.

NOTE 24— COMMITMENTS AND CONTINGENCIES

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In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

The generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced.

The renewable generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced.

In order to support these sales obligations, these companies enter into easements and other service agreements associated with the generating facilities.

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The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2024, including those of our subsidiaries:

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Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations.

Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs;

Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, ozone, mercury, and GHGs;

water intake and discharges;

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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 reporting of GHG emissions to comply with federal clean air rules.

Cross State Air Pollution Rule – Good Neighbor Plan

In March 2023, the EPA issued its final Good Neighbor Plan, 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 that we are well positioned to meet the requirements.

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

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.

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The EPA has exempted LDCs from the final rule.

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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.

Mercury and Air Toxics Standards

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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.

The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu.

The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu.

Adoption of either of these lower limits could have an adverse effect on our operations.

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.

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 the reconsideration of the 2015 standard.

The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration, however, in August 2023 it announced that it is instead restarting its ozone standard evaluation.

The EPA has indicated it plans to release its Integrated Review Plan in fall 2024.

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.

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The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023.

In April 2022, the EPA proposed to find that the Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and should be adjusted to "moderate" nonattainment status for the 2015 standard.

The EPA's initial nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved.

The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status based on the

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2015 standard.

In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022.

Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit timely SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard.

This action triggered a 24-month deadline for states to get their SIP approved or the EPA will issue a federal implementation plan.

Additionally, offset sanctions will take effect in 18 months if the SIP is not approved.

The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas.

We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules.

The most recent attainment evaluation date was in August 2024.

The moderate attainment deadline was not met, so in December 2024 the EPA published a final determination reclassifying the nonattainment areas in Wisconsin to a "serious" classification effective January 16, 2025.

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

Particulate Matter

In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine PM and determined that no revisions were necessary to the current annual standard of 12 µg/m 3 or the 24-hour standard of 35 µg/m 3 .

All counties within our service territories are in attainment with the current 2012 standards.

Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the PM NAAQS to below the current level of 12 µg/m 3 , while retaining the 24-hour standard.

In January 2023, the EPA announced its proposed decision to revise the primary (health-based) annual PM2.5 standard from its current level of 12 µg/m 3 to within the range of 9 to 10 µg/m 3 .

The EPA also proposed not to change the current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards.

The EPA did, however, take comments on the full range (between 8 and 11 µg/m 3 ) included in the CASAC's latest report.

The EPA finalized the rule on February 7, 2024 and lowered the primary annual PM2.5 level to 9 µg/m 3 , which could cause some nonattainment areas that may affect permitting at our facilities.

The secondary and 24-hour standards remain unchanged.

The EPA will designate areas as attainment and nonattainment with the new standard by early 2026.

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.

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.

Climate Change

In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan.

For coal plants, no standards

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

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would apply under the proposed version of the rule until 2032, and after 2032 the applicable standard would depend on the unit's retirement date.

For combined cycle natural gas plants above a 50 % capacity factor, the proposed rule is highly dependent on the use of hydrogen as an alternative fuel, and on carbon capture technology.

For simple cycle natural gas-fired combustion turbines, the proposed version of the rule does not include applicable limits as long as the capacity factor is less than 20 %.

Our RICE units in Michigan and the new Weston RICE project are not affected under the rule because each RICE unit is less than 25 MWs.

We continue to evaluate the proposed rule to understand the impacts to our operations.

A final rule is expected in the second quarter of 2024.

In May 2023, the EPA proposed to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants.

The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units.

New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load.

Our RICE units are not affected by this rule since each unit is below 25 MWs.

Our ESG Progress Plan is heavily focused on reducing GHG emissions.

The EPA has indicated that it anticipates a final rule in the second quarter of 2024.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022.

In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption.

The proposed revisions could impact the reporting required for our electric generation facilities, local natural gas distribution companies, and underground natural gas storage facilities.

In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024.

We are currently evaluating the potential impact of the proposed rule, if any, on our operations.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation.

We have already retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018.

We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3.

See Note 7, Property, Plant, and Equipment, for more information related to these planned power plant retirements.

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.

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Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

We also continue to reduce methane emissions 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 both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our utility systems.

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.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

The EPA issued a final regulation under Section 316(b) of the CWA that 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.

Section 316(b) of the CWA became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts.

The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.

Pursuant to a WDNR rule, which became effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code.

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 a final BTA determination for VAPP.

We have received interim BTA determinations for OCPP Units 5-8 and Weston Units 3 and 4.

We believe that existing technology installed at the OCPP facility meets the BTA requirements;

however, depending on the timing of the permit reissuance, all four generating units at the OCPP may be retired prior to the WDNR making a final BTA decision, anticipated in 2025.

In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance expected in the first quarter of 2024.

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The WDNR reissued the WPDES permit for PWGS effective October 2023.

This reissued permit includes a conditional BTA determination with conditions for the existing PWGS porous dike (rock breakwater) cooling water intake structure.

We do not anticipate compliance with these conditions will result in a material impact on our financial condition or the efficiency of power plant operations.

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.

Steam Electric Effluent Limitation Guidelines

The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters.

The two new requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater.

Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications are necessary to meet the ELG rule requirements.

Through 2023, compliance costs associated with the ELG rule required $ 105 million in capital investment.

An $ 8 million BATW modification to OCPP Units 7 and 8 was completed and placed in-service in mid-2021, and in December 2021, the PSCW issued a Certificate of Authority approving the $ 89 million ERGS FGD wastewater treatment system modification.

The BATW modifications, including $ 8 million of modifications at Weston Unit 3 completed in June 2023, did not require PSCW approval prior to construction.

All of these ELG required projects were placed in-service ahead of WPDES permit deadlines.

In March 2023, the EPA issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on:

2) FGD wastewater;

3) CCR leachate;

and 4) legacy wastewaters.

The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater.

Under the proposed rule, this new ZLD requirement must be met by a date determined by the permitting authority (the WDNR for WE) that is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029.

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule.

Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032.

Although the $ 89 million biological treatment system at ERGS is complete and was placed in service in December 2023 to meet the WPDES permit deadline, the timing of the project's completion did not comply with the deadline proposed by the EPA to qualify for the early adopter status.

In addition, we do not believe that the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed.

In May 2023, we submitted written comments to the EPA articulating these concerns, including the cost impact to our customers.

The EPA has indicated that it anticipates issuing the final rule in the second quarter of 2024.

If the supplemental ELG rule is finalized as proposed, we anticipate that our coal-fueled facilities, including ER 1 and ER 2 that were built with ELG-compliant dry BA transport systems, will meet the BATW rule provisions.

The EPA also proposed requirements for legacy wastewaters and landfill leachate.

We have reviewed the proposed requirements to determine potential costs and actions required for our facilities.

We submitted comments to the EPA regarding these proposed requirements.

Waters of the United States

In January 2023, the EPA and the Army Corps (the agencies) together released a final rule effective in March 2023 that established standards for identifying which wetland or surface drainage features qualify as WOTUS based on its pre-2015 definition.

The pre-2015 approach involved applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

In May 2023, in Sackett v.

EPA, the Supreme Court issued a decision significantly narrowing federal jurisdiction over wetlands to "traditional navigable waters" and wetlands or other waters that have a "continuous surface connection" with a traditional navigable water.

In August 2023, the agencies revised the final rule to conform the definition of WOTUS to the Supreme Court's May 2023 Sackett decision.

The conforming rule became effective upon publication in the Federal Register on September 8, 2023.

We anticipate this final rule revision based on the Sackett decision may lead to a decreased number of projects that require Army Corps federal wetland permits.

This decision also may affect the administration of some state programs.

At this point, our projects

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.

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requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts.

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.

Manufactured Gas Plant Remediation

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Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site.

As proposed, the rule would regulate previously exempt closed landfills.

We are actively engaged with our trade organizations and provided them information to include in their comments to the EPA.

The EPA has indicated that it anticipates issuing a final rule in the second quarter of 2024.

As proposed, the rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs.

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

The rule will regulate previously exempt closed landfills.

The final rule, which became effective in November 2024 will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs.

The rule is being challenged through litigation pending in the D.C.

Circuit Court of Appeals.

We expect the cost of the additional remediation would be recovered through future rates.

See Note 9, Asset Retirement Obligations, for more information on the estimated cost of the additional remediation.

Renewables, Efficiency, and Conservation

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The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2 % of its annual retail operating revenues.

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Michigan Legislation

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UMERC was in compliance with its requirements under this statute as of December 31, 2024.

The legislation continues

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to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

The legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

In November 2023, Michigan enacted Acts 229, 231 and 235.

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The proposed renewable energy targets include 15 % through 2029, 50 % from 2030 through 2034, and 60 % renewable energy by 2035 and thereafter.

The bill also sets clean energy standards of 80 % for 2035-2039 and 100 % after 2040.

The bill only allows natural gas to count as clean energy if it is accompanied with carbon capture and storage.

The MPSC has indicated that it will complete a study by December 2024 on the unique conditions influencing electric generation, transmission, and demand in the Upper Peninsula of Michigan, which includes the unique role of RICE units placed in service to facilitate the retirement of coal-fired generation in the Upper Peninsula of Michigan.

The bill also sets clean energy standards of 80 % from 2035 through 2039 and 100 % after 2040.

The acts only allow natural gas to count as clean energy if it is accompanied with carbon capture and storage.

The new acts also revise the requirement a utility must meet in filing its energy waste reduction plans.

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

We are working with the EPA on a closeout process for the Consent Decree and expect that process to begin in 2024.

Following our significant engagement with the EPA, the agency conditionally terminated the Consent Decree in December 2024.

Joint Ownership Power Plants – Columbia and Edgewater

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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 4 generating unit was retired in September 2018.

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.

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Accounts payable related to construction costs 285.7 171.3 197.4

Increase in receivables related to insurance proceeds 3.5 — 41.7

Liabilities accrued for software licensing agreement — 7.4 —

(1) Cash received for income taxes in 2023 includes $ 75 million related to PTCs that were sold to a third party.

Common stock issued for stock-based compensation plans 6.4 — —

Increase in receivables related to property damage insurance proceeds 2.3 3.5 —

Increase in receivables for corporate-owned life insurance proceeds 5.8 1.4 —

Liabilities accrued for software licensing agreements 0.2 — 7.4

(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

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Cash, cash equivalents, and restricted cash $ 42.2 $ 165.2 $ 182.2

Our restricted cash consisted of the following:

Our restricted cash primarily consisted of the following:

• 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 we received when WECI acquired ownership interests in certain renewable generation projects.

This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the renewable generation facilities.

• 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.

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See Note 2, Acquisitions, for more information on the purchase of this facility.

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WEC Energy Group, Inc.

NOTE 26— REGULATORY ENVIRONMENT

Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC

2025 and 2026 Rates

In April 2024, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable.

The primary drivers of the requested increases in electric rates were continued capital investments to transition our generation fleets from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW.

The requested increases in natural gas rates were driven by 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.

The final written orders reflected the following:

2025 rate increase

$ 144.0 million / 4.2 % $ 55.1 million / 4.5 % N/A

Gas $ 41.3 million / 7.1 % $ 14.9 million / 3.8 % $ 34.5 million / 4.2 %

Steam $ 1.5 million / 5.0 % N/A N/A

2026 rate increase (2)

$ 169.5 million / 4.5 % $ 30.0 million / 2.3 % N/A

Gas $ 29.8 million / 4.5 % $ 13.5 million / 3.1 % $ 23.5 million / 2.6 %

ROE 9.8 % 9.8 % 9.8 %

Common equity component average on a financial basis 53.0 % 53.0 % 53.0 %

(1) Amounts reflect the impact to our Wisconsin retail electric operations and include the incremental decrease resulting from updated fuel costs.

(2) The 2026 rate increases are incremental to the previously authorized revenue plus the approved rate increases for 2025.

Effective January 1, 2025, WE was required to implement a new earnings sharing mechanism, under which, if WE earns above its authorized ROE:

(i) it retains 100.0 % of earnings for the first 15 basis points above the authorized ROE;

(ii) 50.0 % of the next 25 basis points is required to be refunded to ratepayers;

and (iii) 100.0 % of any remaining excess earnings is required to be refunded to ratepayers.

WPS and WG are required to maintain their current earnings sharing mechanism.

Under the current 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;

(ii) 50.0 % of the next 60 basis points is required to be refunded to ratepayers;

and (iii) 100.0 % of any remaining excess earnings is required to be refunded to ratepayers.

2024 Limited Rate Case Re-Opener

In accordance with their rate orders approved by the PSCW in December 2022, WE, WPS, and WG filed requests for limited electric and natural gas rate case re-openers, as applicable, with the PSCW in May 2023.

The WE and WPS limited electric rate case re-openers included updated fuel costs and revenue requirements for the generation projects that were previously approved by the PSCW and were placed into service in 2023 or are expected to be placed into service in 2024.

WE's limited electric re-opener also included the projected savings from the retirement of the OCPP Units 5 and 6, which are expected to be retired in May 2024.

WE's limited electric re-opener also included the projected savings from the retirement of the OCPP Units 5 and 6, which were retired in May 2024.

WE and WG also filed a request for a limited natural gas rate case re-opener to reflect the additional revenue requirements associated with their previously approved LNG projects.

WE's LNG project was placed into service in November 2023, and WG's LNG project is expected to be placed into service in 2024.

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.

On December 20, 2023, the PSCW issued final written orders approving electric and natural gas rate increases and decreases, effective January 1, 2024.

In December 2023, the PSCW issued final written orders approving electric and natural gas rate increases and decreases, effective January 1, 2024.

The final orders reflected the following:

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The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.

In September 2022, WE, WPS, and WG entered into settlement agreements with certain intervenors to resolve most of the outstanding issues in each utility's respective rate case;

however, the PSCW declined to approve the settlement agreements.

In December 2022, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2023.

7 unchanged sentences

In addition to the above, the final orders included the following terms:

• The utilities will keep their current earnings sharing mechanisms, under which, if a utility earns above its authorized ROE:

(i) the utility retains 100.0 % of earnings for the first 15 basis points above the authorized ROE;

(ii) 50.0 % of the next 60 basis points is refunded to ratepayers;

and (iii) 100.0 % of any remaining excess earnings is required to be refunded to ratepayers.

• The utilities kept their then current earnings sharing mechanisms, under which, if a utility earned above its authorized ROE:

(i) the utility retained 100.0 % of earnings for the first 15 basis points above the authorized ROE;

(ii) 50.0 % of the next 60 basis points was refunded to ratepayers;

and (iii) 100.0 % of any remaining excess earnings was required to be refunded to ratepayers.

• WE and WPS were required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life.

• WE and WPS will not propose any changes to their real time pricing rates for large commercial and industrial electric customers through the end of 2024.

• WE and WPS were not allowed to propose any changes to their real time pricing rates for large commercial and industrial electric customers through the end of 2024.

• WE and WPS were required to lower monthly residential and small commercial electric customer fixed charges by $ 1.00 and $ 3.33 , respectively, from previously authorized rates.

• WE and WPS were required to offer an additional voluntary renewable energy pilot for commercial and industrial customers.

• WE and WPS will continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs.

• WE and WPS were required to continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs.

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.

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.

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• 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 for 2022, with modification.

The earnings sharing mechanisms were modified to authorize the utility to retain 100.0 % of the first 15 basis points of earnings above its then authorized ROE.

The earnings sharing mechanisms otherwise remained as previously authorized.

2020 and 2021 Rates

In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020.

In August 2019, all three utilities filed applications with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case.

In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and addressed the remaining outstanding issues that were not included in the settlement agreements.

The new rates were effective January 1, 2020.

The final orders reflected the following:

2020 Effective rate increase (decrease)

Electric (1) (2)

$ 15.3 million / 0.5 % $ 15.8 million / 1.6 % N/A

$ 10.4 million / 2.8 % $ 4.3 million / 1.4 % $ ( 1.5 ) million / ( 0.2 )%

Steam $ 1.9 million / 8.6 % N/A N/A

ROE 10.0 % 10.0 % 10.2 %

Common equity component average on a financial basis 52.5 % 52.5 % 52.5 %

(1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact.

The WE and WPS rate orders reflected the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years .

For WE, approximately $ 65 million of tax benefits were amortized in each of 2020 and 2021.

For WPS, approximately $ 11 million of tax benefits were amortized in 2020 and approximately $ 39 million were amortized in 2021.

The unprotected deferred tax benefits related to the unrecovered balances of certain of WE's retired plants and its SSR regulatory asset were used to reduce the related regulatory asset.

Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators.

(2) The WPS rate order was net of $ 21 million of refunds related to its 2018 earnings sharing mechanism.

These refunds were made to customers evenly over two years , with half returned in 2020 and the remainder returned in 2021.

(3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact.

The rate orders for all three gas utilities reflected all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years .

For WE, approximately $ 5 million of previously deferred tax expense was amortized each year.

For WPS and WG, approximately $ 5 million and $ 3 million, respectively, of previously deferred tax benefits was amortized each year.

Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

In accordance with its rate order, WE filed an application with the PSCW in July 2020 requesting a financing order to securitize $ 100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $ 100 million during the securitization process and the related financing fees.

In November 2020, the PSCW issued a written order approving the application.

The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs.

In May 2021, WEPCo Environmental Trust issued $ 118.8 million of

2023 Form 10-K 153

WEC Energy Group, Inc.

1.578 % ETBs due December 15, 2035.

See Note 23, Variable Interest Entities, for more information regarding WEPCo Environmental Trust.

The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $ 275 million level.

The total cost of the ReACT™ project was $ 342 million.

This regulatory asset is being collected from customers over eight years .

The PSCW approved all three Wisconsin utilities continuing to have an earnings sharing mechanism through 2021.

The earnings sharing mechanism was modified from its previous structure to one that was consistent with other Wisconsin investor-owned utilities.

Under this earnings sharing mechanism, if the utility earned above its authorized ROE:

(i) the utility retained 100.0 % of earnings for the first 25 basis points above the authorized ROE;

(ii) 50.0 % of the next 50 basis points were required to be refunded to customers;

and (iii) 100.0 % of any remaining excess earnings were required to be refunded to customers.

In addition, the rate orders also required WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.

• 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

On January 6, 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates.

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates.

The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system.

PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service.

PGL did not request an extension of the QIP rider as PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements.

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.

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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 has 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 on January 31, 2024.

On December 15, 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders.

On January 3, 2024, the ICC granted PGL and NSG a limited-scope rehearing.

The rehearing will be limited to:

• the authorized spending for the completion of SMP projects that started in 2023,

• the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system, and

• the timing of changes required to NSG's billing system.

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 in 2023.

This amount includes $ 177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $ 1.7 million of capital costs disallowed at NSG.

The remaining disallowance of capital costs at PGL related to expected future spend.

We anticipate appealing the ICC’s disallowance of PGL's and NSG's capital costs to the Illinois circuit court after the rehearing process is complete.

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 December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 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 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.

An ICC decision on our limited-scope rehearing is expected in the second quarter of 2024.

Third-Party Transaction Fee Adjustment Rider

In accordance with the Climate and Equitable Jobs Act that was signed into law in Illinois, effective September 15, 2021, Illinois utilities are prohibited from charging customers a fee when they elect to pay for service with a credit card.

Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism.

In December 2021, the ICC approved the use of a TPTFA rider for PGL.

The TPTFA rider allowed PGL to recover the costs incurred for these third-party transaction fees prior to them being included in base rates.

PGL began recovering costs under the rider on February 1, 2022.

Amounts deferred under the rider were being recovered over a period of 12 months and are subject to an annual reconciliation whereby costs are reviewed by the ICC for accuracy and prudency.

Effective December 1, 2023, PGL discontinued its use of the TPTFA rider and began recovering costs related to these third-party transaction fees through its base rates.

NSG began recovering these costs through its base rates, effective September 15, 2021.

North Shore Gas Company 2021 Rate Order

In October 2020, NSG filed a request with the ICC to increase its natural gas rates.

In September 2021, the ICC issued a written order authorizing a rate increase of $ 4.1 million ( 4.5 %).

The rate increase reflected a 9.67 % ROE and a common equity component average of 51.58 %.

The natural gas rate increase was primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 28, 2015.

The new rates were effective September 15, 2021.

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.

This amount included $ 177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $ 1.7 million of capital costs disallowed at NSG.

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.

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC.

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.

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.

Qualifying Infrastructure Plant Rider

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Costs previously incurred under PGL's QIP rider are still subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency.

In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending.

Annual costs included in the rider have ranged from $ 192 million to $ 348 million.

As of December 31, 2023, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC.

Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $ 14.8 million of certain capital costs.

PGL recorded a pre-tax charge to income of $ 25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on and of these investments.

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.

2024 Form 10-K 171

WEC Energy Group, Inc.

Minnesota Energy Resources Corporation

3 unchanged sentences

The interim rates went into effect on January 1, 2023.

On November 14, 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors.

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 %.

1 unchanged sentence

Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers.

Final rates will be effective March 1, 2024.

MERC’s customers are entitled to a refund to the extent the interim rate increase exceeded the final approved rate increase.

As of December 31, 2023, MERC had recorded a regulatory liability of $ 8.5 million for refunds due to customers.

These amounts will be refunded to customers during the second quarter of 2024.

2023 Form 10-K 155

WEC Energy Group, Inc.

Final rates went into effect on March 1, 2024.

MERC’s customers were entitled to an $ 8.9 million refund due to the interim rate increase exceeding the final approved rate increase, which was retroactive to January 1, 2023.

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

2024 Rate Application

On December 28, 2023, 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 2024 and to request new rates be effective January 1, 2025.

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."

The new rates became effective January 1, 2025.

2023 Rate Order

In March 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates.

In August 2023, the MPSC issued a written order approving a comprehensive settlement that resolved all issues in MGU's rate case.

The key terms of the settlement agreement include:

The key terms of the settlement agreement included:

• a natural gas base rate increase of $ 9.9 million ( 4.7 %);

2 unchanged sentences

• a continuation of the existing MRP rider, effective January 1, 2025 through 2027, including forecasted increased costs for those projects.

MRP costs are being recovered in base rates in 2024.

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.

2021 Rate Order

In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021.

However, MGU decided that it would delay its filing of the rate case as a result of the Coronavirus Disease – 2019 pandemic.

In May 2020, MGU filed an application with the MPSC requesting approval to defer $ 5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case.

In July 2020, the MPSC issued a written order approving MGU's request.

The deferral of these costs helped to mitigate the impacts from delaying the filing of the rate case.

In March 2021, MGU filed its request with the MPSC to increase its natural gas rates.

In September 2021, the MPSC issued a written order approving a settlement agreement MGU reached with certain intervenors.

The order authorized a rate increase of $ 9.3 million ( 6.35 %) and reflected a 9.85 % ROE and a common equity component average of 51.5 %.

The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its previous rate review that resulted in revised base rates effective January 1, 2016.

The order also allowed MGU to implement a rider for its MRP, which supports recovery of planned capital investment related to pipeline replacements to maintain system safety and reliability between 2023 and 2027, without having to file a rate case.

All costs recovered through the rider are subject to a prudence review by the MPSC.

The new rates were effective January 1, 2022.

Upper Michigan Energy Resources Corporation

2024 Rate Application

On December 28, 2023, UMERC provided notification to the MPSC of its intent to file an application requesting an increase to its electric rates.

The application is expected to be filed in March 2024 and to request new rates be effective January 1, 2025.

UMERC is currently in the process of evaluating its rate request.

2023 Form 10-K 156

WEC Energy Group, Inc.

Recovery of Natural Gas Costs

Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations.

All of our utilities have regulatory mechanisms in place for recovering all prudently incurred natural gas costs.

In March 2021, WE and WG received approval from the PSCW to recover approximately $ 54 million and $ 24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs over a period of three months , beginning in April 2021.

In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $ 28 million of natural gas costs in excess of the benchmark set in its GCRM.

WPS also recovered these excess costs over a period of three months , beginning in April 2021.

PGL and NSG incurred approximately $ 131 million and $ 10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates.

These costs were recovered over a period of 12 months, which started on April 1, 2021.

PGL's and NSG's natural gas costs were reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation.

In January 2023, the ICC issued written orders approving each company's 2021 reconciliation.

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.

Recovery of these costs and the issue of prudence was referred to a contested-case proceeding.

Under the settlement agreement, MERC agreed to not seek recovery of $ 3 million of these costs.

MERC substantially recovered the remaining $ 62 million of extraordinary natural gas costs over the previously approved 27 -month recovery period.

Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant.

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.

The new rates became effective January 1, 2025.

NOTE 27— OTHER INCOME, NET

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AFUDC-Equity 59.8 59.1 29.4

Interest income 17.2 3.9 1.2

Gains (losses) from investments held in rabbi trust 11.7 13.7 ( 12.6 )

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NOTE 28— NEW ACCOUNTING PRONOUNCEMENTS

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No.

2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) Disaggregation of Income Statement Expenses.

The amendments require disclosure of certain costs and expenses in the notes to financial statements, which are disaggregated from relevant expense captions on the income statement.

The amendments also require additional qualitative disclosures of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively.

Finally, the amendments require disclosure of the total amount of selling expenses and, in annual reporting periods, an entity's definition of selling expenses.

The amendments are effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted.

We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2027, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Income Tax Disclosures

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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 chief operating decision maker and (2) included in the reported measure of segment profit or loss.

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 amendments are 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 plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Reference Rate Reform

In March 2020, the FASB issued ASU No.

2020-04, Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting and in January 2021, the FASB issued ASU No.

2021-01, Reference Rate Reform (Topic 848):

These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other interbank offered rates to alternative reference rates.

These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022.

In December 2022, the FASB issued ASU No.

2022-06, Reference Rate Reform (Topic 848):

Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848.

An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic.

Our $ 500.0 million 2007 Junior Notes, which were previously subject to a variable rate based on U.S.

dollar LIBOR, became subject to a variable rate based on SOFR beginning July 1, 2023.

No contract modifications were required as the references to LIBOR were replaced by operation of law.

See Note 14, Long-Term Debt, for more information.

We do not anticipate this guidance having a significant impact on our financial statements and related disclosures.

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

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What changed 10-K

Item 8. Financial Statements and Supplementary Data