Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of WEC Energy Group, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of WEC Energy Group, Inc. and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2025, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of rate regulation on financial statements — Refer to Notes 6 and 26 to the financial statements

Critical Audit Matter Description

The Company’s regulated utilities are subject to regulation by various state and federal regulatory bodies (collectively the “Commissions”) which have jurisdiction with respect to the rates of electric and gas distribution companies in each respective state. Management has determined the Company meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the Regulated Operations Topic of the Financial Accounting Standards Board’s Accounting Standard Codification.

2024 Form 10-K			97			WEC Energy Group, Inc.

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Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered through rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by the Company’s regulators. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (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 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. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

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

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

• We inquired of Company management and independently obtained and read: (1) relevant regulatory orders issued by the Commissions for the Company, (2) Company filings with the Commissions, (3) filings made by intervenors and (4) other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. To assess completeness, we evaluated the information obtained and compared it to management’s recorded regulatory asset and liability balances.

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

• 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.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 21, 2025

We have served as the Company's auditor since 2002.

2024 Form 10-K			98			WEC Energy Group, Inc.

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A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of WEC Energy Group, Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of WEC Energy Group, Inc. and subsidiaries (the “Company”) as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2024, of the Company and our report dated February 21, 2025, expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 21, 2025

2024 Form 10-K			99			WEC Energy Group, Inc.

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B. CONSOLIDATED INCOME STATEMENTS

Year Ended December 31
(in millions, except per share amounts)						2024						2023						2022
Operating revenues						$	8,599.9					$	8,893.0					$	9,597.4
Operating expenses
Cost of sales						2,656.0						3,191.2						4,358.9
Other operation and maintenance						2,158.0						2,100.5						1,938.0
Impairment related to ICC disallowances						12.1						178.9						—
Depreciation and amortization						1,354.5						1,264.2						1,122.6
Property and revenue taxes						266.5						250.2						253.7
Total operating expenses						6,447.1						6,985.0						7,673.2
Operating income						2,152.8						1,908.0						1,924.2
Equity in earnings of transmission affiliates						207.5						177.5						194.7
Other income, net						178.2						177.7						128.8
Interest expense						815.3						727.4						515.1
Gain on debt extinguishments						(23.1)						(0.5)						—
Other expense						(406.5)						(371.7)						(191.6)
Income before income taxes						1,746.3						1,536.3						1,732.6
Income tax expense						222.0						204.6						322.9
Net income						1,524.3						1,331.7						1,409.7
Preferred stock dividends of subsidiary						1.2						1.2						1.2
Net (income) loss attributed to noncontrolling interests						4.1						1.2						(0.4)
Net income attributed to common shareholders						$	1,527.2					$	1,331.7					$	1,408.1
Earnings per share
Basic						$	4.83					$	4.22					$	4.46
Diluted						$	4.83					$	4.22					$	4.45
Weighted average common shares outstanding
Basic						316.2						315.4						315.4
Diluted						316.5						315.9						316.1

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

2024 Form 10-K			100			WEC Energy Group, Inc.

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C. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31
(in millions)						2024						2023						2022
Net income						$	1,524.3					$	1,331.7					$	1,409.7
Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Reclassification of realized derivative gains to net income, net of tax						(0.3)						(0.3)						(0.3)
Defined benefit plans
Pension and OPEB adjustments arising during the period, net of tax expense (benefit) of $0.1, $(0.2), and $(1.3), respectively						0.1						(0.6)						(3.5)
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax						0.1						—						0.2
Defined benefit plans, net						0.2						(0.6)						(3.3)
Other comprehensive loss, net of tax						(0.1)						(0.9)						(3.6)
Comprehensive income						1,524.2						1,330.8						1,406.1
Preferred stock dividends of subsidiary						1.2						1.2						1.2
Comprehensive (income) loss attributed to noncontrolling interests						4.1						1.2						(0.4)
Comprehensive income attributed to common shareholders						$	1,527.1					$	1,330.8					$	1,404.5

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

2024 Form 10-K			101			WEC Energy Group, Inc.

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D. CONSOLIDATED BALANCE SHEETS

At December 31
(in millions, except share and per share amounts)						2024						2023
Assets
Current assets
Cash and cash equivalents						$	9.8					$	42.9
Accounts receivable and unbilled revenues, net of reserves of $162.8 and $193.5, respectively						1,669.3						1,503.2
Materials, supplies, and inventories						813.2						775.2
Prepaid taxes						214.9						173.9
Other prepayments						82.6						76.8
Other						121.9						223.7
Current assets						2,911.7						2,795.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,611.9 and $11,073.1, respectively						34,645.4						31,581.5
Regulatory assets (December 31, 2024 and December 31, 2023 include $76.5 and $85.9, respectively, related to WEPCo Environmental Trust)						3,339.7						3,249.8
Equity investment in transmission affiliates						2,108.9						2,005.9
Goodwill						3,052.8						3,052.8
Pension and OPEB assets						968.5						870.9
Other						336.2						383.1
Long-term assets						44,451.5						41,144.0
Total assets						$	47,363.2					$	43,939.7
Liabilities and Equity
Current liabilities
Short-term debt						$	1,116.6					$	2,020.9
Current portion of long-term debt (December 31, 2024 and December 31, 2023 include $9.2 and $9.0, respectively, related to WEPCo Environmental Trust)						1,729.0						1,264.2
Accounts payable						1,137.1						896.6
Other						859.2						933.1
Current liabilities						4,841.9						5,114.8
Long-term liabilities
Long-term debt (December 31, 2024 and December 31, 2023 include $76.4 and $85.3, respectively, related to WEPCo Environmental Trust)						17,178.1						15,366.9
Finance lease obligations						303.3						145.9
Deferred income taxes						5,514.7						4,918.5
Deferred revenue, net						334.6						356.4
Regulatory liabilities						3,958.0						3,697.7
Intangible liabilities						566.8						594.8
Environmental remediation liabilities						445.8						463.7
AROs						580.0						374.2
Other						838.1						835.3
Long-term liabilities						29,719.4						26,753.4
Commitments and contingencies (Note 24)
Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 317,680,855 and 315,434,531 shares outstanding, respectively						3.2						3.2
Additional paid in capital						4,315.8						4,115.9
Retained earnings						8,083.8						7,612.8
Accumulated other comprehensive loss						(7.8)						(7.7)
Common shareholders' equity						12,395.0						11,724.2
Preferred stock of subsidiary						30.4						30.4
Noncontrolling interests						376.5						316.9
Total liabilities and equity						$	47,363.2					$	43,939.7

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

2024 Form 10-K			102			WEC Energy Group, Inc.

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E. CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31
(in millions)						2024						2023						2022
Operating activities
Net income						$	1,524.3					$	1,331.7					$	1,409.7
Reconciliation to cash provided by operating activities
Depreciation and amortization						1,354.5						1,264.2						1,122.6
Deferred income taxes and ITCs, net						529.0						219.4						280.1
Impairment related to ICC disallowances						12.1						178.9						—
Contributions and payments related to pension and OPEB plans						(14.5)						(16.7)						(15.1)
Equity income in transmission affiliates, net of distributions						(57.4)						(33.0)						(74.3)
Net change in transmission regulatory assets and liabilities						(22.8)						19.8						(85.8)
Net loss (gain) on disposition of assets						0.7						(23.8)						(66.2)
Change in –
Accounts receivable and unbilled revenues, net						(161.5)						340.6						(342.1)
Materials, supplies, and inventories						(38.0)						41.9						(171.3)
Collateral on deposit						84.3						22.1						(108.1)
Other current assets						(75.4)						36.3						32.3
Accounts payable						99.7						(254.0)						121.5
Other current liabilities						11.6						47.5						126.9
Other, net						(34.8)						(156.5)						(169.5)
Net cash provided by operating activities						3,211.8						3,018.4						2,060.7
Investing activities
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)						—
Acquisition of Sapphire Sky, net of cash acquired of $0.3						—						(442.6)						—
Acquisition of Samson I, net of cash acquired of $5.2						—						(257.3)						—
Acquisition of Thunderhead, net of cash acquired of $0.5						—						—						(382.0)
Capital contributions to transmission affiliates						(45.5)						(63.7)						(45.5)
Proceeds from the sale of assets						1.7						32.8						69.0
Insurance proceeds received for property damage						6.0						2.5						41.6
Other, net						10.1						(21.9)						(10.6)
Net cash used in investing activities						(3,802.5)						(3,558.2)						(2,642.4)
Financing activities
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)
Dividends paid on common stock						(1,056.2)						(984.2)						(917.9)
Issuance of long-term debt						4,460.9						2,170.0						1,999.3
Retirement of long-term debt						(2,138.0)						(1,005.4)						(92.1)
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)
Other, net						(6.1)						(6.8)						(9.1)
Net cash provided by financing activities						467.7						522.8						676.4
Net change in cash, cash equivalents, and restricted cash						(123.0)						(17.0)						94.7
Cash, cash equivalents, and restricted cash at beginning of year						165.2						182.2						87.5
Cash, cash equivalents, and restricted cash at end of year						$	42.2					$	165.2					$	182.2

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

2024 Form 10-K			103			WEC Energy Group, Inc.

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F. CONSOLIDATED STATEMENTS OF EQUITY

						WEC Energy Group Common Shareholders' 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)
Balance at December 31, 2021						$	3.2					$	4,138.1					$	6,775.1					$	(3.2)					$	10,913.2					$	30.4					$	169.7					$	11,113.3
Net income attributed to common shareholders						—						—						1,408.1						—						1,408.1						—						—						1,408.1
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						—						—						(917.9)						—						(917.9)						—						—						(917.9)
Exercise of stock options						—						33.6						—						—						33.6						—						—						33.6
Purchase of common stock						—						(69.2)						—						—						(69.2)						—						—						(69.2)
Acquisition of noncontrolling interests						—						—						—						—						—						—						42.5						42.5
Capital contributions from noncontrolling interest						—						—						—						—						—						—						1.1						1.1
Distributions to noncontrolling interests						—						—						—						—						—						—						(4.3)						(4.3)
Stock-based compensation and other						—						12.7						—						—						12.7						—						(0.1)						12.6
Balance at December 31, 2022						$	3.2					$	4,115.2					$	7,265.3					$	(6.8)					$	11,376.9					$	30.4					$	209.3					$	11,616.6
Net income attributed to common shareholders						—						—						1,331.7						—						1,331.7						—						—						1,331.7
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(1.2)						(1.2)
Other comprehensive loss						—						—						—						(0.9)						(0.9)						—						—						(0.9)
Common stock dividends of $3.12 per share						—						—						(984.2)						—						(984.2)						—						—						(984.2)
Exercise of stock options						—						6.3						—						—						6.3						—						—						6.3
Purchase of common stock						—						(16.6)						—						—						(16.6)						—						—						(16.6)
Acquisition of noncontrolling interests						—						—						—						—						—						—						114.9						114.9
Distributions to noncontrolling interests						—						—						—						—						—						—						(6.0)						(6.0)
Stock-based compensation and other						—						11.0						—						—						11.0						—						(0.1)						10.9
Balance at December 31, 2023						$	3.2					$	4,115.9					$	7,612.8					$	(7.7)					$	11,724.2					$	30.4					$	316.9					$	12,071.5
Net income attributed to common shareholders						—						—						1,527.2						—						1,527.2						—						—						1,527.2
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(4.1)						(4.1)
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						—						—						(1,056.2)						—						(1,056.2)						—						—						(1,056.2)
Exercise of stock options						—						23.7						—						—						23.7						—						—						23.7
Purchase of common stock						—						(3.2)						—						—						(3.2)						—						—						(3.2)
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)
Stock-based compensation and other						—						11.7						—						—						11.7						—						—						11.7
Balance at December 31, 2024						$	3.2					$	4,315.8					$	8,083.8					$	(7.8)					$	12,395.0					$	30.4					$	376.5					$	12,801.9

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

2024 Form 10-K			104			WEC Energy Group, Inc.

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G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of Operations—WEC Energy Group serves approximately 1.7 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable generating facilities as part of its non-utility energy infrastructure segment.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries, which we control, and VIEs, of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2024 related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:

• Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.

• Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.

• Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.

• Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.

• Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our majority interests in multiple renewable generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on recently acquired WECI renewable generating facilities.

• Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities.

Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information.

(b) Basis of Presentation—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

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(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

(d) Operating Revenues—The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation.

The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

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We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales, and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, 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.

Natural Gas Utility Operating Revenues

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

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, 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.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. We recognize revenues using a time-based output method through a monthly fixed service fee. Typical storage contract rates consist of firm storage reservation charges and firm injection and withdrawal charges. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

Wind and solar generation revenues from WECI's ownership interests in renewable generation facilities continued to grow in 2024. 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

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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.

When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the renewable generation facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and the recognition of REC revenues generally occur concurrently.

Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.

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

As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2024, 2023, and 2022, we recorded $24.3 million, $23.5 million, and $23.4 million, respectively, of revenues related to these deferred carrying costs.

Other Operating Revenues

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Below is a summary of the alternative revenue programs at our utilities:

• The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

• MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.

• WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

(e) Credit Losses—The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 5, Credit Losses.

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

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

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.

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

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

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

(in millions)						2024						2023
Materials and supplies						$	412.5					$	320.0
Natural gas in storage						300.2						327.8
Fossil fuel						100.5						127.4
Total						$	813.2					$	775.2

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 18% and 17% of total inventories at December 31, 2024 and 2023, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2024 and 2023, exceeded the LIFO cost by $77.9 million and $12.2 million, respectively. 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 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. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

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. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. 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. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:

Annual Utility Composite Depreciation Rates						2024						2023						2022
WE						3.03%						3.03%						3.06%
WPS						2.92%						2.93%						2.67%
WG						2.61%						2.61%						2.47%
PGL						3.36%						3.13%						3.13%
NSG						2.49%						2.46%						2.43%
MERC						2.60%						2.60%						2.56%
MGU						2.87%						2.73%						2.75%
UMERC						3.01%						2.97%						3.01%

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2.

We depreciate our WECI assets over the estimated useful life of the property, with wind and solar generating facilities being depreciated over 30 and 35 years, respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.

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

(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC-Debt) used during plant construction, and a return on shareholders' capital (AFUDC-Equity) used for construction purposes. AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below:

						2024
						Average AFUDC Retail Rate						Average AFUDC Wholesale Rate
WE						8.45%						7.11%
WPS						7.46%						5.53%
WG						7.94%						N/A
UMERC						6.28%						N/A
WBS						7.46%						N/A

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

(in millions)						2024						2023						2022
AFUDC-Debt
WE						$	14.6					$	13.0					$	6.9
WPS						3.6						2.9						2.3
WG						1.0						3.4						1.4
UMERC						0.4						—						0.1
WBS						0.1						0.1						0.1
Other						0.2						0.1						0.2
Total AFUDC-Debt						$	19.9					$	19.5					$	11.0
AFUDC-Equity
WE						$	46.0					$	41.0					$	18.8
WPS						9.2						7.6						5.8
WG						2.9						9.8						3.9
UMERC						1.0						—						0.1
WBS						0.3						0.4						0.3
Other						0.4						0.3						0.5
Total AFUDC-Equity						$	59.8					$	59.1					$	29.4

(j) Cloud Computing Hosting Arrangements that are Service Contracts—We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, a centralized repository for data to improve analytics, reporting and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, and customer contact systems. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements.

At December 31, 2024 and 2023, we had $17.0 million and $11.3 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2024 and 2023, was $4.1 million and $2.8 million, respectively. Amortization expense for the years ended December 31, 2024, 2023, and 2022 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees.

(k) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test for all of our reporting units that carried a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. 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 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. See Note 10, Goodwill and Intangibles, for more information.

We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

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

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jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss. In 2024, we recorded a non-cash impairment loss of $12.1 million driven by an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs. In 2023, we recorded a non-cash impairment loss of $178.9 million related to the disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC. See Note 26, Regulatory Environment, for more information.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information.

We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.

(l) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.

(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 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. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. In addition to those shares of common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders, 9.0 million shares were reserved for issuance under the plan.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

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Stock Options

We grant non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in connection with certain termination of employment events following a change in control. Options expire no later than 10 years from the date of the grant.

Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models:

						2024						2023						2022
Stock options granted						294,990						257,780						437,269
Estimated weighted-average fair value per stock option						$	16.19					$	19.58					$	14.71
Assumptions used to value the options:
Risk-free interest rate						3.9% – 5.4%						3.8% – 4.8%						0.2% – 1.6%
Dividend yield						3.8		%				3.2		%				3.2		%
Expected volatility						22.0		%				22.0		%				21.0		%
Expected life (years)						8.4						8.3						8.7

The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience.

Restricted Shares

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 non-employee directors fully vest after one year.

Our restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.

The ultimate number of performance units that will be paid out is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics, as may be determined by the Compensation Committee. Under the terms of awards granted prior to 2023, participants may earn between 0% and 175% of the performance unit award based on our total shareholder return. Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10% based on our performance against additional performance measures, if any, adopted by the Compensation Committee.

The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023. In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023, 2024, and 2025. The ultimate number of units that will be paid out will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and our performance against the weighted average authorized ROE of all of our utility subsidiaries (45%). In addition, the Compensation

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Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award.

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

(o) Earnings Per Share—We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Our potentially dilutive securities include stock options and shares issuable upon the conversion of the 2027 Notes and 2029 Notes.

The dilutive impact from our in-the-money stock options is calculated using the treasury stock method. The calculation of diluted earnings per share for the years ended December 31, 2024, 2023, and 2022 excluded 66,870; 1,716,286; 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. As a policy election, we account for each lease component separately from the nonlease components of a contract.

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our renewable generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

See Note 15, Leases, for more information.

(q) Income Taxes—We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

ITCs are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return.

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

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In 2023 and 2024, under this transferability provision, we entered into agreements to sell substantially all of the PTCs we generated in 2023 and 2024 to third parties. In October 2024, we entered into an agreement to sell the majority of the PTCs expected to be generated in 2025 to a third party. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. 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

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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.

(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).

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

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

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

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

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

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

See Note 17, Fair Value Measurements, for more information.

(s) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.

We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. 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.

(t) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. See Note 19, Guarantees, for more information.

(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 applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 20, Employee Benefits, for more information.

(v) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

(w) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including CCR landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding CCR landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable, and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state regulatory commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and CCR landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(x) Customer Concentrations of Credit Risk—The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2024. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2024.

NOTE 2—ACQUISITIONS

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

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Acquisition of a Solar Generation Facility in Ohio

In February 2025, WECI completed the acquisition of a 90% ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for approximately $405.9 million. 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. In January 2024, WECI acquired an additional 10% ownership interest in Samson I for $28.1 million.

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)
Accounts receivable						$	0.5
Other current assets						0.7
Net property, plant, and equipment						497.2
Other long-term assets						12.3
Accounts payable						(0.5)
Other current liabilities						(0.8)
Other long-term liabilities						(186.4)
Noncontrolling interest						(65.7)
Total purchase price						$	257.3

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. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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

(in millions)
Accounts receivable						$	0.8
Net property, plant, and equipment						642.6
Other long-term assets						1.4
Accounts payable						(1.0)
Other long-term liabilities						(152.0)
Noncontrolling interest						(49.2)
Total purchase price						$	442.6

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.

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

Acquisition of a Wind Generation Facility in Nebraska

In September 2022, WECI completed the acquisition of a 90% ownership interest in Thunderhead, a 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska. The purchase price was $382.0 million, which includes transaction costs and is net of cash acquired. Thunderhead achieved commercial operation in November 2022. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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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)
Accounts receivable						$	0.2
Other prepayments						0.3
Net property, plant, and equipment						692.3
Other long-term assets						5.1
Other current liabilities						(0.2)
Other long-term liabilities						(273.2)
Noncontrolling interest						(42.5)
Total purchase price						$	382.0

NOTE 3—DISPOSITIONS

Wisconsin Segment

Sale of Certain Real Estate by Wisconsin Electric Power Company

In June 2023, we sold approximately 192 acres of real estate at WE's former Pleasant Prairie power plant site that was no longer being utilized in its operations, for $23.0 million, which is net of closing costs. As a result of the sale, a pre-tax gain in the amount of $22.2 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

Illinois Segment

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

In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $55.1 million, which is net of closing costs. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $54.5 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

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NOTE 4—OPERATING REVENUES

For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations has different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Year ended December 31, 2024
Electric						$	4,908.4					$	—					$	—					$	4,908.4					$	—					$	—					$	—					$	4,908.4
Natural gas						1,402.4						1,499.6						419.7						3,321.7						48.4						—						(46.0)						3,324.1
Total regulated revenues						6,310.8						1,499.6						419.7						8,230.1						48.4						—						(46.0)						8,232.5
Other non-utility revenues						—						—						20.4						20.4						223.9						—						(9.1)						235.2
Total revenues from contracts with customers						6,310.8						1,499.6						440.1						8,250.5						272.3						—						(55.1)						8,467.7
Other operating revenues						19.7						102.8						9.7						132.2						419.0						—						(419.0)			(1)			132.2
Total operating revenues						$	6,330.5					$	1,602.4					$	449.8					$	8,382.7					$	691.3					$	—					$	(474.1)					$	8,599.9

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Year ended December 31, 2023
Electric						$	4,994.6					$	—					$	—					$	4,994.6					$	—					$	—					$	—					$	4,994.6
Natural gas						1,606.7						1,480.5						493.7						3,580.9						61.9						—						(60.2)						3,582.6
Total regulated revenues						6,601.3						1,480.5						493.7						8,575.5						61.9						—						(60.2)						8,577.2
Other non-utility revenues						—						—						19.6						19.6						197.5						0.1						(9.1)						208.1
Total revenues from contracts with customers						6,601.3						1,480.5						513.3						8,595.1						259.4						0.1						(69.3)						8,785.3
Other operating revenues						24.6						77.3						5.8						107.7						407.1						—						(407.1)			(1)			107.7
Total operating revenues						$	6,625.9					$	1,557.8					$	519.1					$	8,702.8					$	666.5					$	0.1					$	(476.4)					$	8,893.0

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Year Ended December 31, 2022
Electric						$	4,956.2					$	—					$	—					$	4,956.2					$	—					$	—					$	—					$	4,956.2
Natural gas						1,980.7						1,883.7						601.8						4,466.2						54.3						—						(51.8)						4,468.7
Total regulated revenues						6,936.9						1,883.7						601.8						9,422.4						54.3						—						(51.8)						9,424.9
Other non-utility revenues						—						—						18.7						18.7						133.6						—						(9.1)						143.2
Total revenues from contracts with customers						6,936.9						1,883.7						620.5						9,441.1						187.9						—						(60.9)						9,568.1
Other operating revenues						23.6						7.2						(2.0)						28.8						402.1						0.5						(402.1)			(1)			29.3
Total operating revenues						$	6,960.5					$	1,890.9					$	618.5					$	9,469.9					$	590.0					$	0.5					$	(463.0)					$	9,597.4

(1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. 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

Electric Utility Operating Revenues

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

						Year Ended December 31
(in millions)						2024						2023						2022
Residential						$	1,996.3					$	1,992.3					$	1,879.1
Small commercial and industrial						1,613.0						1,641.1						1,530.4
Large commercial and industrial						942.6						978.4						1,042.2
Other						30.2						30.5						29.9
Total retail revenues						4,582.1						4,642.3						4,481.6
Wholesale						102.6						120.4						153.9
Resale						176.7						195.4						256.7
Steam						22.4						25.2						28.4
Other utility revenues						24.6						11.3						35.6
Total electric utility operating revenues						$	4,908.4					$	4,994.6					$	4,956.2

Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues into customer class:

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Year ended December 31, 2024
Residential						$	893.1					$	945.5					$	250.5					$	2,089.1
Commercial and industrial						416.8						274.5						123.9						815.2
Total retail revenues						1,309.9						1,220.0						374.4						2,904.3
Transportation						96.8						272.2						33.6						402.6
Other utility revenues (1)						(4.3)						7.4						11.7						14.8
Total natural gas utility operating revenues						$	1,402.4					$	1,499.6					$	419.7					$	3,321.7

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Year ended December 31, 2023
Residential						$	1,012.0					$	966.0					$	324.4					$	2,302.4
Commercial and industrial						506.7						267.1						175.3						949.1
Total retail revenues						1,518.7						1,233.1						499.7						3,251.5
Transportation						93.0						231.9						32.5						357.4
Other utility revenues (1)						(5.0)						15.5						(38.5)						(28.0)
Total natural gas utility operating revenues						$	1,606.7					$	1,480.5					$	493.7					$	3,580.9

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Year Ended December 31, 2022
Residential						$	1,234.0					$	1,297.4					$	391.3					$	2,922.7
Commercial and industrial						672.7						408.8						218.7						1,300.2
Total retail revenues						1,906.7						1,706.2						610.0						4,222.9
Transportation						81.8						259.8						34.5						376.1
Other utility revenues (1) (2)						(7.8)						(82.3)						(42.7)						(132.8)
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.

(2) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

See Note 26, Regulatory Environment, for more information.

Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:

						Year Ended December 31
(in millions)						2024						2023						2022
Renewable generation revenues						$	190.5					$	164.9					$	101.0
We Power revenues						24.3						23.5						23.4
Appliance service revenues						20.4						19.6						18.7
Other						—						0.1						0.1
Total other non-utility operating revenues						$	235.2					$	208.1					$	143.2

Other Operating Revenues

Other operating revenues consist primarily of the following:

						Year Ended December 31
(in millions)						2024						2023						2022
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

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

NOTE 5—CREDIT LOSSES

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at December 31, 2024 and 2023, by reportable segment.

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
December 31, 2024
Accounts receivable and unbilled revenues						$	1,149.9					$	535.6					$	100.6					$	1,786.1					$	40.0					$	6.0					$	1,832.1
Allowance for credit losses						73.6						83.9						5.3						162.8						—						—						162.8
Accounts receivable and unbilled revenues, net (1)						$	1,076.3					$	451.7					$	95.3					$	1,623.3					$	40.0					$	6.0					$	1,669.3
Total accounts receivable, net – past due greater than 90 days (1)						$	51.8					$	30.1					$	2.5					$	84.4					$	—					$	—					$	84.4
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						93.8		%				100.0		%				—		%				93.2		%				—		%				—		%				93.2		%

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
December 31, 2023
Accounts receivable and unbilled revenues						$	1,078.0					$	481.5					$	94.9					$	1,654.4					$	33.9					$	8.4					$	1,696.7
Allowance for credit losses						77.4						109.7						6.4						193.5						—						—						193.5
Accounts receivable and unbilled revenues, net (1)						$	1,000.6					$	371.8					$	88.5					$	1,460.9					$	33.9					$	8.4					$	1,503.2
Total accounts receivable, net – past due greater than 90 days (1)						$	51.7					$	45.0					$	2.1					$	98.8					$	—					$	—					$	98.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						93.6		%				100.0		%				—		%				94.5		%				—		%				—		%				94.5		%

(1) Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. 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:

(in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2024						$	77.4					$	109.7					$	6.4					$	193.5
Provision for credit losses						52.1						52.3						0.5						104.9
Provision for credit losses deferred for future recovery or refund						43.8						(8.0)						—						35.8
Write-offs charged against the allowance						(141.8)						(95.0)						(6.6)						(243.4)
Recoveries of amounts previously written off						42.1						24.9						5.0						72.0
Balance at December 31, 2024						$	73.6					$	83.9					$	5.3					$	162.8

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)						Wisconsin						Illinois						Other States																		WEC Energy Group Consolidated
Balance at January 1, 2023						$	82.0					$	111.0					$	6.3																	$	199.3
Provision for credit losses						40.9						26.3						4.8																		72.0
Provision for credit losses deferred for future recovery or refund						52.5						35.8						—																		88.3
Write-offs charged against the allowance						(131.6)						(85.4)						(6.6)																		(223.6)
Recoveries of amounts previously written off						33.6						22.0						1.9																		57.5
Balance at December 31, 2023						$	77.4					$	109.7					$	6.4																	$	193.5

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

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(in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2022						$	84.0					$	105.5					$	8.8					$	198.3
Provision for credit losses						50.5						33.0						2.6						86.1
Provision for credit losses deferred for future recovery or refund						29.7						33.2						—						62.9
Write-offs charged against the allowance						(117.0)						(82.6)						(6.4)						(206.0)
Recoveries of amounts previously written off						34.8						21.9						1.3						58.0
Balance at December 31, 2022						$	82.0					$	111.0					$	6.3					$	199.3

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.

NOTE 6—REGULATORY ASSETS AND LIABILITIES

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

(in millions)						2024						2023						See Note
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
Environmental remediation costs (5)						570.1						596.8						24
Income tax related items						438.5						449.9						1(q), 16
AROs						166.7						162.0						1(l), 9
Uncollectible expense						151.5						127.7						5
Decoupling						110.0						27.3						1(d)
SSR (6)						102.9						113.2
Securitization						76.5						85.9						23
Bluewater (7)						57.7						45.3
Derivatives						38.2						130.3						1(s)
Energy efficiency programs (8)						26.5						33.9
Finance and operating leases						22.0						12.0						15
Other, net						122.7						112.5
Total regulatory assets						$	3,378.7					$	3,274.7
Balance sheet presentation
Other current assets						$	39.0					$	24.9
Regulatory assets						3,339.7						3,249.8
Total regulatory assets						$	3,378.7					$	3,274.7

(1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $26.7 million at both December 31, 2024 and 2023.

(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 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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(4) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(5) As of December 31, 2024, we had made cash expenditures of $124.3 million related to these environmental remediation costs. The remaining $445.8 million represents our estimated future cash expenditures.

(6) This regulatory asset relates to WE's 2014 announcement to retire the PIPP. Despite WE's intent to retire the PIPP, MISO designated the PIPP as a SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for WE's SSR revenues because of the fluctuations in the actual revenues WE received under the PIPP SSR agreements. The rate order WE received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020.

(7) Primarily relates to costs associated with the long-term service agreements our Wisconsin utilities have with Bluewater for natural gas storage services. The PSCW has approved escrow accounting for these costs. As a result, our Wisconsin utilities defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

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

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

(in millions)						2024						2023						See Note
Regulatory liabilities
Income tax related items						$	1,825.4					$	1,901.8					16
Removal costs (1)						1,458.2						1,329.9
Pension and OPEB benefits (2)						308.5						299.2						20, 26
Energy costs refundable through rate adjustments						160.8						72.4						1(d)
Uncollectible expense						47.2						21.2						5
Revenue requirements of renewable generation facilities (3)						44.2						—						26
Derivatives						36.9						19.2						1(s)
Electric transmission costs (4)						19.7						30.3
Other, net						102.4						71.2
Total regulatory liabilities						$	4,003.3					$	3,745.2
Balance sheet presentation
Other current liabilities						$	45.3					$	47.5
Regulatory liabilities						3,958.0						3,697.7
Total regulatory liabilities						$	4,003.3					$	3,745.2

(1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 9, Asset Retirement Obligations, for more information on our legal obligations.

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

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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approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. WE also has FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Pleasant Prairie Power Plant

The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $506.8 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $15.4 million as of December 31, 2024. The net amount of $491.4 million was classified as a regulatory asset on our balance sheet at December 31, 2024 due to the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $138.0 million related to the retired Pleasant Prairie power plant. Pursuant to its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. The amortization is included in depreciation and amortization in the income statement. WE also has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

WE received approval from the PSCW in December 2019 to collect a full return of the net book value of the Pleasant Prairie power plant and a return on all but $100 million of the net book value. During May 2021, WE securitized the remaining $100 million of the Pleasant Prairie power plant's book value, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees, in accordance with a written order issued by the PSCW in November 2020. See Note 23, Variable Interest Entities, for more information on this securitization.

Presque Isle Power Plant

Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $142.6 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $4.4 million as of December 31, 2024. The net amount of $138.2 million was classified as a regulatory asset on our balance sheet at December 31, 2024 as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $38.7 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. In WE's rate order issued by the PSCW in December 2019 and UMERC's rate order issued by the MPSC in October 2024, WE and UMERC received approval to collect a return of and on the net book value of the PIPP and, as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. This amortization is included in depreciation and amortization in the income statement. WE also has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Pulliam Power Plant

In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $29.3 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2024 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units and, as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. The amortization is included in depreciation and amortization in the income statement. WPS also has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value.

Edgewater Generating Station Unit 4

The Edgewater 4 generating unit was retired on September 28, 2018. The net book value of the generating unit was $1.0 million at December 31, 2024, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheet at December 31, 2024 as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the

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

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following at December 31:

(in millions)						2024						2023
Electric – generation						$	6,976.3					$	6,190.4
Electric – distribution						9,298.9						8,688.0
Natural gas – distribution, storage, and transmission						15,673.0						14,851.3
Property, plant, and equipment to be retired, net						906.3						1,043.5
Other						2,410.8						2,350.0
Less: Accumulated depreciation						9,411.0						8,907.9
Net						25,854.3						24,215.3
CWIP						1,653.6						1,118.3
Net utility and non-utility property, plant, and equipment						27,507.9						25,333.6
We Power generation						3,284.3						3,295.9
Renewable generation						4,720.8						3,667.7
Natural gas storage						298.6						291.6
Net non-utility energy infrastructure						8,303.7						7,255.2
Corporate services						172.3						169.8
Other						14.1						14.3
Less: Accumulated depreciation						1,393.9						1,227.5
Net						7,096.2						6,211.8
CWIP						41.3						36.1
Net other property, plant, and equipment						7,137.5						6,247.9
Total property, plant, and equipment						$	34,645.4					$	31,581.5

Severance Liability for Plant Retirements

We have severance liabilities related to past and future plant retirements recorded in other current and other long-term liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows:

(in millions)						2024						2023						2022
Severance liability at January 1						$	17.8					$	16.2					$	4.9
Severance expense						(3.9)			(1)			1.6						11.3
Severance payments						(0.5)						—						—
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 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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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

In November 2023, the ICC issued written rate orders that disallowed $177.2 million of previously incurred capital costs related to the construction and improvement of PGL’s service centers and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. As a result of these disallowances, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment in 2023. 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.

NOTE 8—JOINTLY OWNED UTILITY FACILITIES

Our electric utilities hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We have supplied our own financing for all jointly owned projects. We pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

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

Company						Jointly-Owned Utility Facilities												Ownership						Share of Capacity (MW)						In-Service /Acquisition Date						Operating Owner						Property, Plant, and Equipment						Accumulated Depreciation						CWIP
(in millions, except for percentages and MW)
We Power (1)						ER 1 & ER 2 (2)												83.34		%				1,083.4						2010 & 2011						WE						$	2,482.4					$	(548.3)					$	4.3
WPS						Weston Unit 4 (2)												70.0		%				383.4						2008						WPS						600.9						(230.7)						1.6
WPS						Columbia Units 1 & 2 (2) (5)												27.5		%				307.5						1975 & 1978						WPL						436.5						(186.9)						4.0
WPS						Forward Wind (3)												44.6		%				61.5						2008						WPS						120.1						(60.0)						—
WPS						Two Creeks (4)												66.7		%				100.0						2020						WPS						136.9						(18.6)						—
WPS						Badger Hollow I (4)												66.7		%				100.0						2021						WPS						146.5						(14.5)						0.4
WPS						Red Barn (3)												90.0		%				82.4						2023						WPS						150.6						(8.1)						—
WE						West Riverside (2) (6)												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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(2) Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2025 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(3) Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds.

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

(5) These coal units are expected to be retired by the end of 2029. See Note 7, Property, Plant, and Equipment, for more information.

(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 Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system. The solar portion of this project went into service in December 2024 (see details in the table above) and construction of the battery storage is expected to be completed in 2025. Once 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

Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; the disposal of PCB-contaminated transformers; the closure of CCR landfills at certain generation facilities; and the removal of above ground and underground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators.

WECI has also recorded AROs for the dismantling of our non-utility renewable generation projects.

The following table shows changes to our AROs during the years ended December 31:

(in millions)						2024						2023						2022
Balance as of January 1						$	374.2					$	479.3					$	462.0
Accretion						18.8						17.2						16.1
Additions						192.7			(1)			24.0						12.8
Revisions to estimated cash flows						6.4						(133.5)			(2)			2.2
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 related to the new EPA CCR Rule that was enacted in April 2024. See Note 24, Commitments and Contingencies, for more information.

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

NOTE 10—GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at December 31, 2024. We had no changes to the carrying amount of goodwill during the years ended December 31, 2024 and 2023.

(in millions)						Wisconsin						Illinois						Other States						Non-Utility Energy Infrastructure						Total
Goodwill balance (1)						$	2,104.3					$	758.7					$	183.2					$	6.6					$	3,052.8

(1) We had no accumulated impairment losses related to our goodwill as of December 31, 2024.

During the third quarter of 2024, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2024. No impairments resulted from these tests.

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. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

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

The intangible liabilities below were all obtained through acquisitions by WECI.

						December 31, 2024																		December 31, 2023
(in millions)						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount
PPAs (1)						$	679.6					$	(119.3)					$	560.3					$	653.9					$	(66.6)					$	587.3
Proxy revenue swap (2)						7.2						(4.2)						3.0						7.2						(3.5)						3.7
Interconnection agreements (3)						4.7						(1.2)						3.5						4.7						(0.9)						3.8
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, 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 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 four years.

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(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 16 years.

Amortization related to these intangible liabilities for the years ended December 31, 2024, 2023, and 2022 was $53.7 million, $50.6 million, and $11.3 million, respectively. Amortization for the next five years is estimated to be:

						For the Years Ending December 31
(in millions)						2025						2026						2027						2028						2029
Amortization to be recorded as an increase to operating revenues						$	53.9					$	55.1					$	55.1					$	55.1					$	55.1
Amortization to be recorded as a decrease to other operation and maintenance						0.2						0.2						0.2						0.2						0.2

NOTE 11—COMMON EQUITY

Stock-Based Compensation

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31:

(in millions)						2024						2023						2022
Stock options						$	4.9					$	5.3					$	6.5
Restricted stock						7.6						6.6						7.0
Performance units						26.8						(2.2)			(1)			21.3
Stock-based compensation expense						$	39.3					$	9.7					$	34.8
Related tax benefit						$	10.8					$	2.7					$	9.6

(1) The reduction in expense was due to a decrease in the fair value of the outstanding performance units.

Stock-based compensation costs capitalized during 2024, 2023, and 2022 were not significant.

Stock Options

The following is a summary of our stock option activity during 2024:

Stock Options						Number of Options						Weighted-Average Exercise Price						Weighted-Average Remaining Contractual Life (in years)						Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2024						3,015,751						$	79.57
Granted						294,990						84.92
Exercised						(380,412)						62.20
Forfeited						(10,286)						91.82
Expired						(3,141)						91.34
Outstanding as of December 31, 2024						2,916,902						82.32						5.4						$	35.0
Exercisable as of December 31, 2024						2,182,660						79.16						4.6						$	32.7

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2024. This is calculated as the difference between our closing stock price on December 31, 2024, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2024, 2023, and 2022 was $11.2 million, $5.2 million, and $29.2 million, respectively. The actual tax benefit from option exercises for the same years was approximately $3.1 million, $1.4 million, and $8.0 million, respectively.

As of December 31, 2024, approximately $1.4 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.6 years on a weighted-average basis.

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During the first quarter of 2025, the Compensation Committee awarded 231,024 non-qualified stock options with a weighted-average exercise price of $94.55 and a weighted-average grant date fair value of $18.23 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following restricted stock activity occurred during 2024:

Restricted Shares						Number of Shares						Weighted-Average Grant Date Fair Value
Outstanding and unvested as of January 1, 2024						100,398						$	93.95
Granted						108,484						84.96
Released						(99,941)						91.07
Forfeited						(3,699)						88.56
Outstanding and unvested as of December 31, 2024						105,242						87.61

The intrinsic value of restricted stock released was $8.6 million, $5.8 million, and $7.5 million for the years ended December 31, 2024, 2023, and 2022, respectively. The actual tax benefit from released restricted shares for the same years was $2.4 million, $1.6 million, and $2.1 million, respectively.

As of December 31, 2024, approximately $4.2 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.8 years on a weighted-average basis.

During the first quarter of 2025, the Compensation Committee awarded 79,170 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $94.55 per share.

Performance Units

During 2024, 2023, and 2022, the Compensation Committee awarded 205,051; 157,035; and 171,492 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $2.4 million, $10.2 million, and $20.2 million were settled during 2024, 2023, and 2022, respectively. The actual tax benefit from the distribution of performance units for the same years was $0.6 million, $2.6 million, and $5.1 million, respectively.

At December 31, 2024, we had 466,679 performance units outstanding, including dividend equivalents. A liability of $34.7 million was recorded on our balance sheet at December 31, 2024 related to these outstanding units. As of December 31, 2024, approximately $22.5 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2025, we settled performance units with an intrinsic value of $14.1 million. The actual tax benefit from the distribution of these awards was $3.4 million. In January 2025, the Compensation Committee also awarded 185,945 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, Bluewater, ATC Holding, and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly.

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

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below their authorized level of 53.0%. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level.

WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a 12-month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

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.

The long-term debt obligations of WECI Wind Holding I, WECI Wind Holding II, and WECI Energy Holding III contain various conditions that must be met prior to them making any cash distributions. Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater for the 12-month period prior to the distribution.

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

See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2024, restricted net assets of our consolidated subsidiaries totaled approximately $13 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $583 million.

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

Common Stock

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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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, except share amounts)						2024						2023						2022
Shares purchased						23,292						182,795						687,416
Cost of shares purchased						$	3.2					$	16.6					$	69.2

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

Date Declared						Date Payable						Per Share						Period
January 18, 2024						March 1, 2024						$0.835						First quarter
April 18, 2024						June 1, 2024						$0.835						Second quarter
July 18, 2024						September 1, 2024						$0.835						Third quarter
October 17, 2024						December 1, 2024						$0.835						Fourth quarter

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. The dividend is payable on March 1, 2025, to shareholders of record on February 14, 2025. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

NOTE 12—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2024 and 2023:

(in millions, except share and per share amounts)						Shares Authorized						Shares Outstanding						Redemption Price Per Share						Total
WEC Energy Group
$0.01 par value Preferred Stock						15,000,000						—						—						$	—
WE
$100 par value, Six Per Cent. Preferred Stock						45,000						44,498						—						4.4
$100 par value, Serial Preferred Stock 3.60% Series						2,286,500						260,000						$	101					26.0
$25 par value, Serial Preferred Stock						5,000,000						—						—						—
WPS
$100 par value, Preferred Stock						1,000,000						—						—						—
PGL
$100 par value, Cumulative Preferred Stock						430,000						—						—						—
NSG
$100 par value, Cumulative Preferred Stock						160,000						—						—						—
Total																								$	30.4

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NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:

(in millions, except percentages)						2024						2023
Commercial paper
Amount outstanding at December 31						$	1,114.4					$	2,017.2
Average interest rate on amounts outstanding at December 31						4.63		%				5.49		%
Operating expense loans
Amount outstanding at December 31 (1)						$	2.2					$	3.7

(1) Coyote Ridge, Tatanka Ridge, and Jayhawk have entered into operating expense loans. In accordance with their limited liability company operating agreements, they received loans from the holders of their noncontrolling interests in proportion to their ownership interests.

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%.

WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0%, 65.0%, 65.0%, 65.0%, and 65.0% or less, respectively. As of December 31, 2024, all companies were in compliance with their respective ratio.

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:

(in millions)						Maturity						2024
Revolving credit facility (WEC Energy Group) (1)						September 2026						$	1,500.0
Revolving credit facility (WEC Energy Group)						October 2025 (2)						200.0
Revolving credit facility (WE) (1)						September 2026						500.0
Revolving credit facility (WPS) (1)						September 2026						400.0
Revolving credit facility (WG) (1)						September 2026						350.0
Revolving credit facility (PGL) (1)						September 2026						350.0
Total short-term credit capacity												$	3,300.0
Less:
Letters of credit issued inside credit facilities												$	2.3
Commercial paper outstanding												1,114.4
Available capacity under existing facilities												$	2,183.3

(1) These revolving credit facilities have a renewal provision for two extensions, subject to lender approval. 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. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of WEC Energy Group's credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.

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NOTE 14—LONG-TERM DEBT

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

						2024																		2023
(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
WEC Energy Group Junior Notes (unsecured) (1) (2)						2055						6.72		%				750.0						7.75		%				500.0
WE Debentures (unsecured)						2025-2095						4.55		%				3,935.0						4.22		%				3,285.0
WEPCo Environmental Trust (secured, nonrecourse) (5) (10)						2025-2035						1.58		%				88.0						1.58		%				97.0
WPS Senior Notes (unsecured)						2025-2051						4.17		%				2,275.0						4.11		%				1,975.0
WG Debentures (unsecured)						2025-2046						3.92		%				840.0						3.35		%				790.0
PGL First and Refunding Mortgage Bonds (secured) (3)						2027-2047						3.56		%				1,995.0						3.53		%				2,070.0
NSG First Mortgage Bonds (secured) (4)						2027-2043						3.81		%				177.0						3.81		%				177.0
MERC Senior Notes (unsecured)						2025-2047						3.04		%				210.0						3.04		%				210.0
MGU Senior Notes (unsecured)						2025-2047						3.45		%				175.0						3.18		%				150.0
UMERC Senior Notes (unsecured)						2029						3.26		%				160.0						3.26		%				160.0
Bluewater Gas Storage Senior Notes (unsecured) (5)						2025-2047						4.07		%				131.9						3.76		%				109.8
ATC Holding Senior Notes (unsecured)						2025-2030						4.05		%				475.0						4.05		%				475.0
We Power Subsidiaries Notes (secured, nonrecourse) (5) (6)						2025-2041						5.67		%				814.3						5.65		%				856.4
WECC Notes (unsecured)						2028						6.94		%				50.0						6.94		%				50.0
WECI Wind Holding I Senior Notes (secured, nonrecourse) (5) (7)						2025-2032						2.75		%				246.4						2.75		%				307.7
WECI Wind Holding II Senior Notes (secured, nonrecourse) (5) (8)						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
Jayhawk acquisition																		7.5												7.5
Unamortized debt issuance costs																		(103.2)												(80.2)
Unamortized discount, net and other																		(21.1)												(20.5)
Total long-term debt, including current portion																		18,907.1												16,631.1
Current portion of long-term debt																		(1,729.0)												(1,264.2)
Total long-term debt																		$	17,178.1											$	15,366.9

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

PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued $100 million of collateralized First Mortgage Bonds.

(4) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. 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, 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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(7) WECI Wind Holding I'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 I.

(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.

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

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 and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes for $115.2 million with proceeds from issuing commercial paper. We recorded a $6.4 million gain related to the early settlement. Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper. We recorded a $0.2 million gain related to the early settlement. In December 2024, we redeemed the remaining $358.9 million outstanding principal at par, plus accrued interest, of our 2007 Junior Notes with the proceeds we received from the issuance of our 2024A Junior Notes and 2024B Junior Notes.

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

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

In December 2024, pursuant to a tender offer, we repurchased $250.0 million aggregate principal amount of the $600.0 million outstanding of our 5.60% Senior Notes due September 12, 2026 and repurchased $150.0 million aggregate principal amount of the $450.0 million outstanding of our 1.80% Senior Notes due October 15, 2030, for $380.9 million, plus accrued interest, with proceeds received from issuing commercial paper. As a result of the repurchase, we recorded a $16.5 million gain on debt extinguishment.

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

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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 41st 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)
2027 Notes						$	862.5					$	(8.0)					$	854.5					$	920.6
2029 Notes						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.

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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
2027 Notes
Contractual interest expense						$	22.3
Amortization of debt issuance costs						1.9
Total interest expense – 2027 Notes						24.2
2029 Notes
Contractual interest expense						22.3
Amortization of debt issuance costs						1.2
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 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 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 maturing within one year of December 31, 2024:

(in millions)						Interest Rate						Maturity Date (1)						Principal Amount
MGU Senior Notes (unsecured)						2.69%						May						$	60.0
MERC Senior Notes (unsecured)						2.69%						May						50.0
WE Debentures (unsecured)						3.10%						June						250.0
WEC Energy Group Senior Notes (unsecured)						3.55%						June						120.0
WEC Energy Group Senior Notes (unsecured)						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
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)						5.209%						Semi-annually						16.3
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)						4.673%						Semi-annually						12.2
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)						6.00%						Monthly						7.5
WECI Wind Holding I Senior Notes (secured, nonrecourse)						2.75%						Semi-annually						44.4
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 as of December 31, 2024:

(in millions)						Payments
2025						$	1,729.0
2026						1,519.4
2027						2,137.3
2028						2,303.2
2029						2,643.4
Thereafter						8,691.6
Total						$	19,023.9

Certain long-term debt obligations contain financial and other covenants related to payment of principal and interest when due, maintaining certain total funded debt to capitalization ratios, and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

NOTE 15—LEASES

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities primarily associated with the following operating leases:

• Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, through April 2029.

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

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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 December 2074.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Certain of our leases contain options for early termination or to renew past the initial term, as set forth in the lease agreements. These options are included in our calculation of the lease obligations if it is reasonably certain that they will be exercised.

Obligations Under Finance Leases

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our finance leases is modified to conform to the rate treatment. Amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes. The difference between this lease expense and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842.

Land Leases – Utility Solar Generation

We have various land leases related to our investments in 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. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates.

Power Purchase Commitment

In 1997, WE entered into a 25-year PPA with LSP-Whitewater Limited Partnership. The contract, for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements. The PPA expired on May 31, 2022; however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022. Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility and the acquisition closed effective January 1, 2023. See Note 2, Acquisitions, for more information. Both the PPA and the tolling agreement were accounted for as a finance lease prior to the acquisition.

Land Leases – Non-Utility Energy Infrastructure Solar Generation

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.

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Amounts Recognized in the Financial Statements and Other Information

The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows:

(in millions)						2024						2023						2022
Finance lease expense
Amortization of right of use assets (1)						$	0.2					$	—					$	6.0
Interest on lease liabilities (2)						1.8						0.8						0.9
Operating lease expense (3)						5.2						4.7						6.1
Short-term lease expense (3)						0.6						1.2						0.9
Total lease expense						$	7.8					$	6.7					$	13.9
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases						$	1.8					$	0.8					$	0.9
Operating cash flows from operating leases						7.1						6.8						5.7
Financing cash flows from finance leases						—						—						6.0
Non-cash activities:
Right of use assets obtained in exchange for finance lease liabilities (4)						$	153.2					$	32.8					$	57.6
Right of use assets obtained in exchange for operating lease liabilities						2.6						18.3						—
Weighted-average remaining lease term – finance leases						50.2 years						49.4 years						30.0 years
Weighted-average remaining lease term – operating leases						25.1 years						22.4 years						12.0 years
Weighted-average discount rate – finance lease (5)						5.9		%				5.3		%				3.9		%
Weighted average discount rate – operating leases (5)						5.9		%				5.8		%				3.4		%

(1) Amortization of right of use assets was included as a component of depreciation and amortization expense.

(2) Interest on lease liabilities was included as a component of interest expense.

(3) Operating and short-term lease expense were included as a component of other operation and maintenance expense.

(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 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.

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The following table summarizes our finance and operating lease right of use assets and obligations at December 31:

(in millions)						2024						2023						Balance Sheet Location
Right of use assets
Operating lease right of use assets, net						$	32.1					$	32.0					Other long-term assets
Finance lease right of use assets, net
Land leases – utility solar generation						$	235.8					$	132.7
Land leases –non-utility energy infrastructure solar generation						43.5						—
Other						2.0						1.1
Total finance lease right of use assets, net (1)						$	281.3					$	133.8					Property, plant, and equipment, net
Lease obligations
Current operating lease liabilities						$	4.3					$	4.7					Other current liabilities
Long-term operating lease liabilities						$	37.5					$	38.8					Other long-term liabilities
Current finance lease liabilities
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						$	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						Land Leases - Non-Utility Energy Infrastructure Solar Generation						Other						Total Finance Leases
2025						$	6.0					$	7.3					$	3.3					$	0.3					$	10.9
2026						5.9						8.1						2.3						0.3						10.7
2027						5.8						12.2						2.3						0.3						14.8
2028						5.7						12.4						2.3						0.1						14.8
2029						2.9						12.7						2.4						0.1						15.2
Thereafter						75.9						954.4						159.7						2.6						1,116.7
Total minimum lease payments						102.2						1,007.1						172.3						3.7						1,183.1
Less: Interest						(60.4)						(749.2)						(128.5)						(1.9)						(879.6)
Present value of minimum lease payments						41.8						257.9						43.8						1.8						303.5
Less: Short-term lease liabilities						(4.3)						—						—						(0.2)						(0.2)
Long-term lease liabilities						$	37.5					$	257.9					$	43.8					$	1.6					$	303.3

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.

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NOTE 16—INCOME TAXES

Income Tax Expense

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

(in millions)						2024						2023						2022
Current tax expense (benefit)						$	(307.0)					$	(14.8)					$	50.2
Deferred income taxes, net						538.7						229.9						278.5
ITCs						(9.7)						(10.5)						(5.8)
Total income tax expense						$	222.0					$	204.6					$	322.9

Statutory Rate Reconciliation

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:

						2024												2023												2022
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	367.3					21.0		%				$	322.6					21.0		%				$	363.5					21.0		%
State income taxes net of federal tax benefit						108.0						6.2		%				94.3						6.1		%				109.7						6.3		%
PTCs, net						(200.1)						(11.5)		%				(168.2)						(10.9)		%				(107.6)						(6.2)		%
Federal excess deferred tax amortization (1)						(36.7)						(2.1)		%				(37.6)						(2.4)		%				(36.9)						(2.1)		%
AFUDC-Equity						(12.6)						(0.7)		%				(12.4)						(0.8)		%				(6.2)						(0.4)		%
Other, net						(3.9)						(0.2)		%				5.9						0.3		%				0.4						—		%
Total income tax expense						$	222.0					12.7		%				$	204.6					13.3		%				$	322.9					18.6		%

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

Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 were as follows:

(in millions)						2024						2023
Deferred tax assets
Tax gross up – regulatory items						$	420.1					$	438.6
Future tax benefits						165.4						160.7
Deferred revenues						76.0						84.7
Other						167.9						168.3
Total deferred tax assets						829.4						852.3
Valuation allowance						(1.1)						(5.0)
Net deferred tax assets						$	828.3					$	847.3
Deferred tax liabilities
Property-related						$	4,545.2					$	4,198.0
Investment in affiliates						1,103.9						915.1
Employee benefits and compensation						231.4						227.2
Deferred costs – plant retirements						194.3						199.6
Other						268.2						225.9
Total deferred tax liabilities						6,343.0						5,765.8
Deferred tax liability, net						$	5,514.7					$	4,918.5

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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.

The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2024 and 2023 are summarized in the tables below:

2024 (in millions)						Gross Value						Deferred Tax Effect						Valuation Allowance						Earliest Year of Expiration
Future tax benefits as of December 31, 2024
Federal tax credit						$	—					$	157.9					$	—					2042
State net operating loss						107.5						7.2						(1.1)						2032
Other state benefits						—						0.3						—						2028
Balance as of December 31, 2024						$	107.5					$	165.4					$	(1.1)

2023 (in millions)						Gross Value						Deferred Tax Effect						Valuation Allowance						Earliest Year of Expiration
Future tax benefits as of December 31, 2023
Federal tax credit						$	—					$	153.0					$	—					2042
State net operating loss						62.6						3.8						(1.1)						2032
Other state benefits						—						3.9						(3.9)						2024
Balance as of December 31, 2023						$	62.6					$	160.7					$	(5.0)

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(in millions)						2024						2023						2022
Balance as of January 1						$	4.6					$	6.3					$	6.8
Additions for tax positions of prior years						—						0.2						0.3
Additions based on tax positions related to the current year						—						—						0.4
Reductions for tax positions of prior years						(0.2)						(1.9)						(1.2)
Balance as of December 31						$	4.4					$	4.6					$	6.3

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. As of December 31, 2024 and 2023, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $3.4 million and $3.6 million, respectively.

Interest accrued related to unrecognized tax benefits is as follows:

(in millions)						2024						2023						2022
Balance as of January 1						$	0.6					$	0.5					$	0.1
Interest expense related to unrecognized tax benefits						0.3						0.1						0.4
Balance as of December 31						$	0.9					$	0.6					$	0.5

For the years ended December 31, 2024, 2023, and 2022, we recognized no penalties related to unrecognized tax benefits in our consolidated income statements. At December 31, 2024 and 2023, we had no amounts accrued for penalties related to unrecognized tax benefits.

Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $1.8 million associated with statutes of limitations on certain tax years. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months.

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

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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:

Jurisdiction						Years
Federal						2021–2024
Illinois						2021–2024
Michigan						2020–2024
Minnesota						2020–2024
Wisconsin						2020–2024

NOTE 17—FAIR VALUE MEASUREMENTS

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

						December 31, 2024
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	19.6					$	13.7					$	—					$	33.3
FTRs and TCRs						—						—						7.8						7.8
Total derivative assets						$	19.6					$	13.7					$	7.8					$	41.1
Investments held in rabbi trust						$	52.1					$	—					$	—					$	52.1
Derivative liabilities
Natural gas contracts						$	7.1					$	6.8					$	—					$	13.9

						December 31, 2023
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	2.2					$	8.3					$	—					$	10.5
FTRs and TCRs						—						—						7.2						7.2
Coal contracts						—						0.3						—						0.3
Total derivative assets						$	2.2					$	8.6					$	7.2					$	18.0
Investments held in rabbi trust						$	51.7					$	—					$	—					$	51.7
Derivative liabilities
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 Southwest Power Pool, Inc. Integrated Marketplace, respectively.

We hold investments in the Integrys rabbi trust. These investments are used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. During the years ended December 31, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $9.0 million and $10.0 million, respectively. For the year ended December 31, 2022, we recorded $12.7 million of net unrealized losses in earnings related to the investments held at the end of the period.

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

(in millions)						2024						2023						2022
Balance at the beginning of the period						$	7.2					$	7.8					$	2.4
Purchases						28.7						21.0						23.7
Net realized and unrealized gains (losses) included in earnings (1)						(0.7)						(0.5)						0.5
Settlements						(27.4)						(21.1)						(18.8)
Balance at the end of the period						$	7.8					$	7.2					$	7.8
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 net realized and unrealized gains and losses are recorded in operating revenues on our income statements.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31:

						2024												2023
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock of subsidiary						$	30.4					$	21.2					$	30.4					$	21.4
Long-term debt, including current portion						18,907.1						17,840.8						16,631.1						15,564.3

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

NOTE 18—DERIVATIVE INSTRUMENTS

Derivative assets and liabilities are included in the other current and other long-term line items on our balance sheets. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments.

						December 31, 2024												December 31, 2023
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	29.2					$	13.9					$	10.4					$	78.1
FTRs and TCRs						7.8						—						7.2						—
Coal contracts						—						—						0.3						10.9
Total current						37.0						13.9						17.9						89.0
Long-term
Natural gas contracts						4.1						—						0.1						8.0
Coal contracts						—						—						—						9.4
Total long-term						4.1						—						0.1						17.4
Total						$	41.1					$	13.9					$	18.0					$	106.4

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Realized gains and losses on derivatives used in our regulatory utility operations are recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations are recorded in operating revenues on the income statements. Our estimated notional sales volumes and realized gains and losses were as follows for the years ended:

						December 31, 2024												December 31, 2023												December 31, 2022
(in millions)						Volumes						Gains (Losses)						Volumes						Gains (Losses)						Volumes						Gains
Natural gas contracts						206.3 Dth						$	(127.8)					198.0 Dth						$	(259.1)					183.3 Dth						$	299.5
FTRs and TCRs						29.7 MWh						8.2						30.2 MWh						25.9						27.2 MWh						11.8
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
Gross amount recognized on the balance sheet						$	41.1					$	13.9					$	18.0					$	106.4
Gross amount not offset on the balance sheet						(11.5)			(1)			(7.3)						(3.1)						(71.0)			(2)
Net amount						$	29.6					$	6.6					$	14.9					$	35.4

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

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

Cash Flow Hedges

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.

NOTE 19—GUARANTEES

The following table shows our outstanding guarantees:

						Total Amounts Committed at December 31, 2024						Expiration
(in millions)									Less Than 1 Year						1 to 3 Years						Over 3 Years
Standby letters of credit (1)						$	176.1					$	19.8					$	30.0					$	126.3
Surety bonds (2)						34.0						33.9						0.1						—
Other guarantees (3)						11.3						—						—						11.3
Total guarantees						$	221.4					$	53.7					$	30.1					$	137.6

(1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.

(2) Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

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

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NOTE 20—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded non-qualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Other than those employees who receive a contribution to their 401(k) savings plan as described below, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit. Employees who started before 1996 receive a benefit based upon years of service and final average salary. 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.

For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.

We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. 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.

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

						Pension Benefits												OPEB Benefits
(in millions)						2024						2023						2024						2023
Change in benefit obligation
Obligation at January 1						$	2,352.4					$	2,315.9					$	448.1					$	402.3
Service cost						24.2						24.0						10.9						9.8
Interest cost						116.6						122.3						22.7						21.6
Participant contributions						—						—						11.2						11.8
Actuarial (gain) loss						(99.6)						81.9						6.9						45.9
Benefit payments						(184.4)						(191.7)						(41.7)						(46.0)
Federal subsidy on benefits paid						N/A						N/A						1.4						1.5
Transfer						—						—						1.4						1.2
Obligation at December 31						$	2,209.2					$	2,352.4					$	460.9					$	448.1
Change in fair value of plan assets
Fair value at January 1						$	2,665.8					$	2,628.0					$	829.6					$	835.3
Actual return on plan assets						129.8						214.9						49.5						76.4
Employer contributions net of plan transfer (1)						13.1						14.6						1.4						(47.9)
Participant contributions						—						—						11.2						11.8
Benefit payments						(184.4)						(191.7)						(41.7)						(46.0)
Fair value at December 31						$	2,624.3					$	2,665.8					$	850.0					$	829.6
Funded status at December 31						$	415.1					$	313.4					$	389.1					$	381.5

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

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

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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.

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:

						Pension Benefits												OPEB Benefits
(in millions)						2024						2023						2024						2023
Pension and OPEB assets						$	562.4					$	475.2					$	406.1					$	395.7
Other long-term liabilities						147.3						161.8						17.0						14.2
Total net assets						$	415.1					$	313.4					$	389.1					$	381.5

The accumulated benefit obligation for all defined benefit pension plans was $2,156.8 million and $2,279.6 million as of December 31, 2024 and 2023, respectively.

The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:

(in millions)						2024						2023
Accumulated benefit obligation						$	286.0					$	300.7
Fair value of plan assets						143.2						147.3

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31:

(in millions)						2024						2023
Projected benefit obligation						$	290.5					$	306.7
Fair value of plan assets						143.2						147.3

The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:

(in millions)						2024						2023
Accumulated benefit obligation						$	194.0					$	21.0
Fair value of plan assets						177.0						6.9

The following table shows the amounts that had not yet been recognized in our net periodic benefit cost (credit) as of December 31:

						Pension Benefits												OPEB Benefits
(in millions)						2024						2023						2024						2023
Pre-tax accumulated other comprehensive income (loss) (1)
Net actuarial loss (gain)						$	12.3					$	12.7					$	(1.1)					$	(1.2)
Prior service credits						—						—						—						—
Total						$	12.3					$	12.7					$	(1.1)					$	(1.2)
Net regulatory assets (liabilities) (2)
Net actuarial loss (gain)						$	578.7					$	688.9					$	(148.8)					$	(166.3)
Prior service credits						(2.1)						(2.2)						(15.8)						(29.3)
Total						$	576.6					$	686.7					$	(164.6)					$	(195.6)

(1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.

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

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

						Pension Benefits																		OPEB Benefits
(in millions)						2024						2023						2022						2024						2023						2022
Service cost						$	24.2					$	24.0					$	50.8					$	10.9					$	9.8					$	14.3
Interest cost						116.6						122.3						91.8						22.7						21.6						15.4
Expected return on plan assets						(182.1)						(187.4)						(208.0)						(52.7)						(53.0)						(68.9)
Plan settlement						4.0						1.3						6.2						—						—						—
Amortization of prior service cost (credit)						(0.1)						—						1.6						(13.5)						(14.8)						(15.9)
Amortization of net actuarial loss (gain)						59.5						33.0						75.3						(7.6)						(12.3)						(24.7)
Net periodic benefit cost (credit)						$	22.1					$	(6.8)					$	17.7					$	(40.2)					$	(48.7)					$	(79.8)

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of December 31, 2024 and 2023, our balance sheet included a $24.9 million and a $6.0 million regulatory asset for pension costs, respectively, and a $38.2 million and a $14.8 million regulatory asset for OPEB costs, respectively.

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

						Pension Benefits												OPEB Benefits
						2024						2023						2024						2023
Discount rate						5.69%						5.19%						5.71%						5.16%
Rate of compensation increase						4.00%						4.00%						N/A						N/A
Interest credit rate						4.85%						4.84%						N/A						N/A
Assumed medical cost trend rate (Pre 65)						N/A						N/A						7.00%						6.25%
Ultimate trend rate (Pre 65)						N/A						N/A						5.00%						5.00%
Year ultimate trend rate is reached (Pre 65)						N/A						N/A						2033						2031
Assumed medical cost trend rate (Post 65)						N/A						N/A						6.10%						6.39%
Ultimate trend rate (Post 65)						N/A						N/A						5.00%						5.00%
Year ultimate trend rate is reached (Post 65)						N/A						N/A						2030						2030

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

						Pension Benefits
						2024						2023						2022
Discount rate						5.18%						5.49%						3.18%
Expected return on plan assets						6.61%						6.62%						6.88%
Rate of compensation increase						4.00%						4.00%						4.00%
Interest credit rate						4.84%						4.62%						3.78%

						OPEB Benefits
						2024						2023						2022
Discount rate						5.16%						5.50%						2.92%
Expected return on plan assets						6.50%						6.50%						7.00%
Assumed medical cost trend rate (Pre 65)						6.25%						6.50%						5.70%
Ultimate trend rate (Pre 65)						5.00%						5.00%						5.00%
Year ultimate trend rate is reached (Pre 65)						2031						2031						2028
Assumed medical cost trend rate (Post 65)						6.39%						6.00%						5.67%
Ultimate trend rate (Post 65)						5.00%						5.00%						5.00%
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

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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.

Plan Assets

Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. 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 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. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(r), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

The following tables provide the fair values of our investments by asset class:

						December 31, 2024
						Pension Plan Assets																								OPEB Assets
(in millions)						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Asset Class
Equity securities:
United States equity						$	168.4					$	—					$	—					$	168.4					$	93.8					$	—					$	—					$	93.8
International equity						158.2						—						—						158.2						86.4						—						—						86.4
Fixed income securities: (1)
United States bonds						—						880.1						—						880.1						99.0						205.6						—						304.6
International bonds						—						81.6						—						81.6						—						11.2						—						11.2
						$	326.6					$	961.7					$	—					$	1,288.3					$	279.2					$	216.8					$	—					$	496.0
Investments measured at net asset value:
Equity securities																								414.9																								190.4
Fixed income securities																								126.0																								51.8
Other																								795.1																								111.8
Total																								$	2,624.3																							$	850.0

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

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						December 31, 2023
						Pension Plan Assets																								OPEB Assets
(in millions)						Level 1						Level 2						Level 3						Total						Level 1						Level 2						Level 3						Total
Asset Class
Equity securities:
United States equity						$	179.3					$	—					$	—					$	179.3					$	91.8					$	—					$	—					$	91.8
International equity						174.0						—						—						174.0						84.6						—						—						84.6
Fixed income securities: (1)
United States bonds						—						906.6						—						906.6						91.5						203.2						—						294.7
International bonds						—						88.0						—						88.0						—						11.9						—						11.9
						$	353.3					$	994.6					$	—					$	1,347.9					$	267.9					$	215.1					$	—					$	483.0
Investments measured at net asset value:
Equity securities																								407.4																								182.1
Fixed income securities																								124.2																								47.7
Other																								786.3																								116.8
Total																								$	2,665.8																							$	829.6

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

Cash Flows

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.

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

(in millions)						Pension Benefits						OPEB Benefits
2025						$	212.5					$	35.3
2026						214.4						36.7
2027						205.0						37.9
2028						197.2						38.5
2029						188.7						38.8
2030-2034						839.4						189.4

Savings Plans

We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. 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.

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NOTE 21—INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of 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. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. ATC's corporate manager has a ten-member board of directors, and ATC Holdco's corporate manager has a four-member board of directors. We have one representative on each board. Each member of the board has only one vote. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:

						2024
(in millions)						ATC						ATC Holdco						Total
Balance at January 1						$	1,980.8					$	25.1					$	2,005.9
Add: Earnings from equity method investment						205.4						2.1						207.5
Add: Capital contributions						45.5						—						45.5
Less: Distributions						146.7						3.4						150.1
Add: Other						0.1						—						0.1
Balance at December 31						$	2,085.1					$	23.8					$	2,108.9

						2023
(in millions)						ATC						ATC Holdco						Total
Balance at January 1						$	1,884.6					$	24.6					$	1,909.2
Add: Earnings from equity method investment						175.1						2.4						177.5
Add: Capital contributions						63.7						—						63.7
Less: Distributions						142.6						1.9						144.5
Balance at December 31						$	1,980.8					$	25.1					$	2,005.9

						2022
(in millions)						ATC						ATC Holdco						Total
Balance at January 1						$	1,766.9					$	22.5					$	1,789.4
Add: Earnings from equity method investment						192.6						2.1						194.7
Add: Capital contributions						45.5						—						45.5
Less: Distributions						120.4						—						120.4
Balance at December 31						$	1,884.6					$	24.6					$	1,909.2

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. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.

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

(in millions)						2024						2023						2022
Charges to ATC for services and construction						$	21.6					$	17.4					$	18.9
Charges from ATC for network transmission services						413.3						377.5						363.7
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:

(in millions)						2024						2023
Accounts receivable for services provided to ATC						$	1.4					$	1.6
Accounts payable for services received from ATC						34.4						49.9
Amounts due from ATC for transmission infrastructure upgrades (1)						54.5						46.1

(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:

						Year Ended December 31
(in millions)						2024						2023						2022
Income statement data
Operating revenues						$	911.3					$	818.9					$	751.2
Operating expenses						442.4						407.6						381.5
Other expense, net						137.7						131.7						123.0
Net income						$	331.2					$	279.6					$	246.7

(in millions)						December 31, 2024						December 31, 2023
Balance sheet data
Current assets						$	126.6					$	115.2
Noncurrent assets						6,792.6						6,337.0
Total assets						$	6,919.2					$	6,452.2
Current liabilities						$	482.4					$	495.9
Long-term debt						3,083.4						2,736.0
Other noncurrent liabilities						545.0						585.2
Members' equity						2,808.4						2,635.1
Total liabilities and members' equity						$	6,919.2					$	6,452.2

NOTE 22—SEGMENT INFORMATION

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

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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.

• 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:

◦We Power, which owns and leases generating facilities to WE,

◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and

◦WECI, which owns majority interests in multiple renewable generating facilities.

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

• 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.

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

						Utility Operations
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
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
Impairment related to ICC disallowances						—						12.1						—						12.1						—						—						—						—						12.1
Depreciation and amortization						919.9						255.4						47.0						1,222.3						—						198.4						22.3						(88.5)						1,354.5
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
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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						Utility Operations
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
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
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.

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

NOTE 23—VARIABLE INTEREST ENTITIES

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

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

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WEPCo Environmental Trust Finance I, LLC

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

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

WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, WE is authorized to implement periodic adjustments of the environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. WE remits all collections of the environmental control charge to WEPCo Environmental Trust's indenture trustee.

WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, WE has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. 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 sheets:

(in millions)						December 31, 2024						December 31, 2023
Assets
Other current assets (restricted cash)						$	1.5					$	0.8
Regulatory assets						76.5						85.9
Other long-term assets (restricted cash)						0.6						0.6
Liabilities
Current portion of long-term debt						9.2						9.0
Other current liabilities (accrued interest)						0.1						0.1
Long-term debt						76.4						85.3

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. 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. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At December 31, 2024 and 2023, our equity investment in ATC Holdco was $23.8 million and $25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

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

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NOTE 24—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

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.

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

																		Payments Due By Period
(in millions)						Date Contracts Extend Through						Total Amounts Committed						2025						2026						2027						2028						2029						Later Years
Electric utility:
Nuclear						2033						$	5,680.3					$	634.5					$	681.6					$	730.4					$	782.6					$	838.5					$	2,012.7
Coal supply and transportation						2029						343.4						303.0						33.5						3.3						1.7						1.9						—
Purchased power						2063						394.3						59.7						61.4						56.1						52.2						25.5						139.4
Other						2043						80.2						10.0						10.1						8.7						7.1						6.3						38.0
Natural gas utility:
Supply and transportation						2048						2,448.0						388.5						357.9						345.2						302.6						217.5						836.3
Non-utility energy infrastructure:
Purchased power						2051						623.0						38.2						38.6						39.3						40.6						39.4						426.9
Natural gas storage and transportation						2048						4.8						4.0						—						0.1						—						0.1						0.6
Total												$	9,574.0					$	1,437.9					$	1,183.1					$	1,183.1					$	1,186.8					$	1,129.2					$	3,453.9

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, ozone, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:

• the development of additional sources of renewable electric energy supply, battery storage, and natural gas and LNG storage facilities;

• the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;

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

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

• the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;

• 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; and

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

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

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

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

In February 2024, the Supreme Court heard oral arguments regarding stay applications related to the EPA's Good Neighbor Rule. In June 2024, the Supreme Court granted a stay of the Good Neighbor Rule pending disposition of the applicants' petitions for review at the D.C. Circuit Court of Appeals. The D.C. 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

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

National Ambient Air Quality Standards

Ozone

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

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

The EPA's initial nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status based on the

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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.

The most recent attainment evaluation date was in August 2024. The moderate attainment deadline was not met, so in December 2024 the EPA published a final determination reclassifying the nonattainment areas in Wisconsin to a "serious" classification effective January 16, 2025. This nonattainment status could have a material adverse effect on future permitting activities for our facilities in applicable locations, including additional costs associated with more strenuous emission control requirements or the need to purchase additional emission reduction credits.

Particulate Matter

All counties within our service 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/m3, while retaining the 24-hour standard of 35 µg/m3. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until February 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units.

Climate Change

In May 2023, the EPA proposed GHG performance standards for fossil-fired steam generating and natural gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. The final rule, known as the Greenhouse Gas Power Plant Rule, was published in May 2024. Pursuant to the final rule, there are no applicable standards for coal plants until the end of 2031 and after 2031, the applicable standard is dependent upon the unit's retirement date. Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029. For new combined cycle natural gas plants above a 40% capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031. For new simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our RICE units in Michigan and the new Weston RICE units are not affected under the rule because the rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the Greenhouse Gas Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals.

In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule. At that time, the EPA indicated it would work on new rulemaking phases, focusing on CO2 emissions, as well as NOx and hazardous air pollutants (formaldehyde) emissions. In November 2024, the EPA released the first proposed rule of the three rule "packages" to address NOx emissions from existing combustion turbines. The proposed rule for turbines that operate at a greater than 20% capacity factor, will require more stringent NOx limits and control requirements for new, modified, or reconstructed turbines. For turbines that operate at a capacity of 20% or lower, less restrictive standards and the use of combustion controls would apply. 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 CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The revisions will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the final rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities.

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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natural gas, and Weston Unit 3. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050. We also believe we will be in a position to eliminate coal as an energy source by the end of 2032.

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

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

We have received final or interim BTA determinations for all generation facilities where Section 316(b) is applicable. The most recent BTA determination was for Weston Units 3 and 4. In accordance with the requirements in the CWA, the WDNR reissued the Weston WPDES permit in June 2024 (effective July 1, 2024) that includes a determination that existing technology (wet cooling towers) installed at the units represents BTA for minimizing adverse environmental impacts. With respect to OCPP Units 7 and 8, we believe the WDNR will reach the same BTA determination decision when the WPDES permit for those units is reissued, which is expected in 2025.

Steam Electric Effluent Limitation Guidelines

The EPA's 2015 final ELG rule, which took effect in January 2016 (2015 ELG rule), was modified in 2020 (2020 ELG rule), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect WE and WPS facilities relate to discharge limits for BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP, ERGS, and Weston to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $105 million in capital investment.

The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date. The Supplemental ELG Rule also kept one existing and created one new “permanent cessation of coal” subcategory. Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively. For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025. All WE and WPS coal-fueled units fully meet the 2020 ELG rule requirements. Based on current electrical generation resource planning, we plan to file a Notice of Planned Participation by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for both the ERGS and Weston coal-fired facilities. A Notice of Privacy Practice also may be filed for the OCPP, PWGS, and VAPP facilities because this ELG rule option will allow the company to qualify for more reasonable requirements to address the CRL provisions at our landfills that served these former coal-fired facilities.

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The final Supplemental ELG Rule allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2028 or 2034, required by either the 2015 or the 2020 ELG Rule, respectively, if needed for reliability concerns (i.e., energy emergencies, reliability must run agreements, etc.) as determined by the DOE, a public utility commission, or independent system operator.

We are still evaluating the Supplemental ELG Rule CRL provisions to determine the applicability and potential compliance costs for inactive/closed landfills. Numerous parties have challenged the rule through litigation pending in the U.S. Court of Appeals for the 8th Circuit. This rule remains in effect during the pendency of the legal challenge.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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

We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31:

(in millions)						2024						2023
Regulatory assets						$	570.1					$	596.8
Reserves for future environmental remediation						445.8						463.7

Coal Combustion Residuals Rule

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

The final rule, which became effective in November 2024 will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. We expect the cost of the additional remediation would be recovered through future rates. See Note 9, Asset Retirement Obligations, for more information on the estimated cost of the additional remediation.

Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. WE and WPS have achieved their required renewable energy percentages of 8.27% and 9.74%, respectively, by constructing various wind parks, solar parks, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing basis. 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

In December 2016, Michigan enacted Act 342, which required 12.5% of the state's electric energy to come from renewables for 2019 and 2020, and energy optimization (efficiency) targets up to 1% annually. The renewable requirement increased to 15.0% for 2021 and beyond. UMERC was in compliance with its requirements under this statute as of December 31, 2024. 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. The acts require electric providers to file a renewable energy plan every two years and to set renewable energy portfolio targets from now until 2040. 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% 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. They require a utility to file a plan every two years until 2025, then every three years thereafter.

Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. Following our significant engagement with the EPA, the agency conditionally terminated the Consent Decree in December 2024.

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with WPL, MG&E, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater Unit 4 generating unit was retired in September 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. WPL started the process to close out this Consent Decree.

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NOTE 25—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions

						Year Ended December 31
(in millions)						2024						2023						2022
Cash paid for interest, net of amount capitalized						$	785.7					$	653.4					$	485.2
Cash paid (received) for income taxes, net (1)						(264.2)						(58.9)						52.4
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						285.7						171.3						197.4
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

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows:

(in millions)						2024						2023						2022
Cash and cash equivalents						$	9.8					$	42.9					$	28.9
Restricted cash included in other current assets						5.3						70.1						25.6
Restricted cash included in other long-term assets						27.1						52.2						127.7
Cash, cash equivalents, and restricted cash						$	42.2					$	165.2					$	182.2

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 related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account annually in order to fund future decommissioning.

• Cash used by WE and WPS during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets at December 31, 2022. See Note 2, Acquisitions, for more information on the purchase of this facility.

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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:

						WE												WPS												WG
2025 rate increase
Electric (1)						$	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)
Electric (1)						$	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 were 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 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 and WG's LNG projects were placed into service in November 2023 and February 2024, respectively.

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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:

						WE												WPS												WG
2024 incremental rate increases (decreases)
Electric (1)						$	82.2	million	/			2.5%						$	(32.7)	million	/			(2.6)%						N/A
Gas						$	23.9	million	/			4.5%						N/A												$	21.6	million	/			2.8%

(1) Amounts reflect the impact to our Wisconsin retail electric operations and include any incremental increases (WE) or decreases (WPS) resulting from updated fuel costs.

The utilities' ROE and common equity component averages were not addressed in the limited rate case re-openers.

2023 and 2024 Rates

In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable. These requests were updated in July 2022 to reflect new developments that impacted the original proposals. The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments had already been approved by the PSCW. 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 December 2022, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2023. The final orders reflected the following:

						WE												WPS												WG
2023 base rate increase
Electric						$	283.5	million	/			9.1%						$	120.5	million	/			9.8%						N/A
Gas						$	46.1	million	/			9.6%						$	26.4	million	/			7.1%						$	46.5	million	/			6.4%
Steam						$	7.6	million	/			35.3%						N/A												N/A
ROE						9.8%												9.8%												9.8%
Common equity component average on a financial basis						53.0%												53.0%												53.0%

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

• 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 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 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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2022 Rates

In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that allowed them to maintain their electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year. In connection with the request, the three utilities also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. In September 2021, the PSCW issued written orders approving the application.

The final orders reflected the following:

• WE, WPS, and WG amortized, in 2022, certain previously deferred balances to offset approximately half of their forecasted revenue deficiencies.

• WG deferred interest and depreciation expense associated with capital investments since its last rate case that otherwise would have been added to rate base in a 2022 test-year rate case.

• WE, WPS, and WG were able to defer any increases in tax expense due to changes in tax law that occurred in 2021 and/or 2022.

• WE, WPS, and WG maintained their earnings sharing mechanisms, with modification.

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

2023 Rate Order

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 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. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:

• A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.

• An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.

The ICC approved an authorized ROE of 9.38% for both PGL and NSG, and set the common equity component average at 50.79% and 52.58% for PGL and NSG, respectively.

As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project.

In addition, the ICC ordered PGL to pause spending on its SMP until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding in January 2024. On February 20, 2025, the ICC issued an order setting expectations for PGL's prospective operations under its SMP. The ICC directed us to focus on replacing all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute. We are evaluating the impact of this order on our operations and capital plan.

In 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.

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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

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which was in effect until December 1, 2023. As discussed above, PGL has returned to the traditional rate-making process for recovery of these costs, and they are now included in PGL's base rates.

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

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Minnesota Energy Resources Corporation

2023 Rate Order

In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023.

In November 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. 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 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 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 included:

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

• an ROE of 9.8%;

• a common equity component average of 51.0%; and,

• a continuation of the existing MRP rider, effective January 1, 2025 through 2027, including forecasted increased costs for those projects. MRP costs were recovered in base rates in 2024.

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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. Inflationary pressure on operating costs also contributed to the rate increase. The new rates were effective January 1, 2024.

Upper Michigan Energy Resources Corporation

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

Total other income, net was as follows for the years ended December 31:

(in millions)						2024						2023						2022
Non-service components of net periodic benefit costs						$	83.7					$	97.7					$	104.4
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)
Earnings (losses) from equity method investments (1)						4.7						(1.1)						9.3
Other, net						1.1						4.4						(2.9)
Other income, net						$	178.2					$	177.7					$	128.8

(1) Amounts do not include equity earnings of transmission affiliates as those earnings are shown as a separate line item on the income statements.

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

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

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adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the CODM and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The update was effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We adopted these amendments beginning with our fiscal year ending on December 31, 2024. See Note 22, Segment Information, which reflects the implementation of this update in our disclosures about our reportable segments.

2024 Form 10-K			174			WEC Energy Group, Inc.

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