Item 1. FINANCIAL STATEMENTS

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Item 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)		Three Months Ended
	March 31
(in millions, except per share amounts)			2025		2024
Operating revenues			$	3,149.5	$	2,680.2

Operating expenses
Cost of sales			1,165.7		927.1
Other operation and maintenance			608.0		530.8
Depreciation and amortization			359.9		333.4
Property and revenue taxes			78.4		75.5
Total operating expenses			2,212.0		1,866.8

Operating income			937.5		813.4

Equity in earnings of transmission affiliates			53.6		44.8
Other income, net			18.1		44.1
Interest expense			223.0		192.0
Other expense			(151.3)		(103.1)

Income before income taxes			786.2		710.3
Income tax expense			60.7		87.7
Net income			725.5		622.6

Preferred stock dividends of subsidiary			0.3		0.3
Net income attributed to noncontrolling interests			(1.0)		—
Net income attributed to common shareholders			$	724.2	$	622.3

Earnings per share
Basic			$	2.28	$	1.97
Diluted			$	2.27	$	1.97

Weighted average common shares outstanding
Basic			318.2		315.6
Diluted			319.3		315.9

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)		Three Months Ended
	March 31
(in millions)			2025		2024
Net income			$	725.5	$	622.6

Other comprehensive loss, net of tax
Derivatives accounted for as cash flow hedges

Reclassification of realized derivative gains to net income, net of tax			(0.1)		(0.1)






Comprehensive income			725.4		622.5

Preferred stock dividends of subsidiary			0.3		0.3
Comprehensive income attributed to noncontrolling interests			(1.0)		—
Comprehensive income attributed to common shareholders			$	724.1	$	622.2

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2025		December 31, 2024
Assets
Current assets
Cash and cash equivalents	$	82.2	$	9.8
Accounts receivable and unbilled revenues, net of reserves of $159.4 and $162.8, respectively	1,812.4		1,669.3
Materials, supplies, and inventories	576.0		813.2
Prepaid taxes	171.6		214.9
Other prepayments	76.2		82.6

Other	224.9		121.9
Current assets	2,943.3		2,911.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,838.7 and $11,611.9, respectively	35,447.8		34,645.4
Regulatory assets (March 31, 2025 and December 31, 2024 include $74.3 and $76.5, respectively, related to WEPCo Environmental Trust)	3,283.3		3,339.7
Equity investment in transmission affiliates	2,149.0		2,108.9
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	983.8		968.5
Other	372.1		336.2
Long-term assets	45,288.8		44,451.5
Total assets	$	48,232.1	$	47,363.2

Liabilities and Equity
Current liabilities
Short-term debt	$	1,327.1	$	1,116.6
Current portion of long-term debt (March 31, 2025 and December 31, 2024 include $9.2, related to WEPCo Environmental Trust)	2,729.9		1,729.0
Accounts payable	791.5		1,137.1

Other	1,014.4		859.2
Current liabilities	5,862.9		4,841.9

Long-term liabilities
Long-term debt (March 31, 2025 and December 31, 2024 include $76.5 and $76.4, respectively, related to WEPCo Environmental Trust)	16,161.8		17,178.1
Finance lease obligations	293.9		303.3
Deferred income taxes	5,577.2		5,514.7
Deferred revenue, net	329.3		334.6
Regulatory liabilities	4,043.9		3,958.0
Intangible liabilities	624.5		566.8
Environmental remediation liabilities	442.1		445.8
AROs	601.5		580.0
Other	868.0		838.1
Long-term liabilities	28,942.2		29,719.4

Commitments and contingencies (Note 21)

Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 319,133,501 and 317,680,855 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,456.1		4,315.8
Retained earnings	8,524.4		8,083.8
Accumulated other comprehensive loss	(7.9)		(7.8)
Common shareholders' equity	12,975.8		12,395.0

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	420.8		376.5
Total liabilities and equity	$	48,232.1	$	47,363.2

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2025		2024
Operating activities
Net income	$	725.5	$	622.6
Reconciliation to cash provided by operating activities
Depreciation and amortization	359.9		333.4
Deferred income taxes and ITCs, net	55.6		184.3
Contributions and payments related to pension and OPEB plans	(3.9)		(4.0)
Equity income in transmission affiliates, net of distributions	2.2		(9.1)
Change in –
Accounts receivable and unbilled revenues, net	(180.3)		(61.3)
Materials, supplies, and inventories	237.2		166.6
Other current assets	13.0		36.9
Accounts payable	(195.4)		(229.8)
Temporary LIFO liquidation credit	68.6		—
Accrued interest	83.5		33.4
Other current liabilities	5.6		(78.2)
Other, net	(8.9)		(131.2)
Net cash provided by operating activities	1,162.6		863.6

Investing activities
Capital expenditures	(701.1)		(444.5)
Acquisition of Hardin III, net of cash acquired of $0.2	(406.1)		—
Capital contributions to transmission affiliates	(42.3)		(12.1)
Proceeds from the sale of investments held in rabbi trust	16.9		14.8
Reimbursement for ATC's transmission infrastructure upgrades	39.7		6.2
Other, net	(8.9)		(0.6)
Net cash used in investing activities	(1,101.8)		(436.2)

Financing activities
Exercise of stock options	21.2		3.7
Issuance of common stock, net	117.1		19.2
Purchase of common stock	(1.3)		(2.0)
Dividends paid on common stock	(283.6)		(263.5)
Retirement of long-term debt	(17.9)		(756.9)
Change in commercial paper	209.5		552.8
Purchase of additional ownership interest in Samson I from noncontrolling interest	—		(28.1)
Other, net	(4.6)		(1.7)
Net cash provided by (used in) financing activities	40.4		(476.5)

Net change in cash, cash equivalents, and restricted cash	101.2		(49.1)
Cash, cash equivalents, and restricted cash at beginning of period	42.2		165.2
Cash, cash equivalents, and restricted cash at end of period	$	143.4	$	116.1

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

	WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)	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
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
Net income attributed to common shareholders	—		—		724.2		—		724.2		—		—		724.2
Net income attributed to noncontrolling interests	—		—		—		—		—		—		1.0		1.0
Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Issuance of common stock, net	—		117.1		—		—		117.1		—		—		117.1
Common stock dividends of $0.8925 per share	—		—		(283.6)		—		(283.6)		—		—		(283.6)
Exercise of stock options	—		21.2		—		—		21.2		—		—		21.2
Purchase of common stock	—		(1.3)		—		—		(1.3)		—		—		(1.3)
Acquisition of noncontrolling interests	—		—		—		—		—		—		45.1		45.1

Distributions to noncontrolling interests	—		—		—		—		—		—		(1.8)		(1.8)
Stock-based compensation and other	—		3.3		—		—		3.3		—		—		3.3
Balance at March 31, 2025	$	3.2	$	4,456.1	$	8,524.4	$	(7.9)	$	12,975.8	$	30.4	$	420.8	$	13,427.0



	WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)	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
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	—		—		622.3		—		622.3		—		—		622.3

Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Issuance of common stock	—		19.2		—		—		19.2		—		—		19.2
Common stock dividends of $0.8350 per share	—		—		(263.5)		—		(263.5)		—		—		(263.5)
Exercise of stock options	—		3.7		—		—		3.7		—		—		3.7
Purchase of common stock	—		(2.0)		—		—		(2.0)		—		—		(2.0)
Purchase of additional ownership interest in Samson I from noncontrolling interest	—		4.3		—		—		4.3		—		(32.4)		(28.1)

Distributions to noncontrolling interests	—		—		—		—		—		—		(1.5)		(1.5)
Stock-based compensation and other	—		4.6		—		—		4.6		—		—		4.6
Balance at March 31, 2024	$	3.2	$	4,145.7	$	7,971.6	$	(7.8)	$	12,112.7	$	30.4	$	283.0	$	12,426.1

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


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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2025

NOTE 1—GENERAL INFORMATION

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 condensed 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. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.

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 sheets related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 18, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2024. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2025, are not necessarily indicative of expected results for 2025 due to seasonal variations and other factors.

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

NOTE 2—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 the below acquisitions met the criteria of asset acquisitions. The purchase price of both acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 17, Goodwill and Intangibles, for more information.

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 $406.1 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Hardin III qualifies for PTCs and is included in the non-utility energy infrastructure segment.

Acquisitions of Solar Generation Facility in Texas

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


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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.

NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2024 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. 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
Three Months Ended March 31, 2025
Electric	$	1,320.0	$	—	$	—	$	1,320.0	$	—	$	—	$	—		$	1,320.0
Natural gas	734.1		759.3		223.7		1,717.1		14.1		—		(13.4)			1,717.8
Total regulated revenues	2,054.1		759.3		223.7		3,037.1		14.1		—		(13.4)			3,037.8
Other non-utility revenues	—		—		5.5		5.5		61.5		—		(1.6)			65.4
Total revenues from contracts with customers	2,054.1		759.3		229.2		3,042.6		75.6		—		(15.0)			3,103.2
Other operating revenues	5.8		29.0		(2.1)		32.7		118.7		—		(105.1)		(1)	46.3
Total operating revenues	$	2,059.9	$	788.3	$	227.1	$	3,075.3	$	194.3	$	—	$	(120.1)		$	3,149.5


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended March 31, 2024
Electric	$	1,185.3	$	—	$	—	$	1,185.3	$	—	$	—	$	—		$	1,185.3
Natural gas	586.0		603.8		173.6		1,363.4		14.5		—		(14.2)			1,363.7
Total regulated revenues	1,771.3		603.8		173.6		2,548.7		14.5		—		(14.2)			2,549.0
Other non-utility revenues	—		—		5.0		5.0		52.1		—		(1.6)			55.5
Total revenues from contracts with customers	1,771.3		603.8		178.6		2,553.7		66.6		—		(15.8)			2,604.5
Other operating revenues	7.5		62.2		6.0		75.7		104.3		—		(104.3)		(1)	75.7
Total operating revenues	$	1,778.8	$	666.0	$	184.6	$	2,629.4	$	170.9	$	—	$	(120.1)		$	2,680.2

(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:


	Three Months Ended March 31
(in millions)	2025		2024
Residential	$	545.0	$	483.2
Small commercial and industrial	421.1		391.7
Large commercial and industrial	238.3		217.6
Other	8.0		7.9
Total retail revenues	1,212.4		1,100.4
Wholesale	27.7		25.6
Resale	62.8		45.1
Steam	12.8		10.2
Other utility revenues	4.3		4.0
Total electric utility operating revenues	$	1,320.0	$	1,185.3

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
Three Months Ended March 31, 2025
Residential	$	488.8	$	465.6	$	142.7	$	1,097.1
Commercial and industrial	250.4		131.2		73.1		454.7
Total retail revenues	739.2		596.8		215.8		1,551.8
Transportation	33.2		97.4		13.5		144.1
Other utility revenues (1)	(38.3)		65.1		(5.6)		21.2
Total natural gas utility operating revenues	$	734.1	$	759.3	$	223.7	$	1,717.1


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2024
Residential	$	397.6	$	375.0	$	111.4	$	884.0
Commercial and industrial	191.8		107.0		54.0		352.8
Total retail revenues	589.4		482.0		165.4		1,236.8
Transportation	29.8		90.1		11.6		131.5
Other utility revenues (1)	(33.2)		31.7		(3.4)		(4.9)
Total natural gas utility operating revenues	$	586.0	$	603.8	$	173.6	$	1,363.4

(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, compared with the recovery of natural gas costs that were anticipated in rates.

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


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Other Non-Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2025		2024
Renewable generation revenues	$	53.8	$	44.5
We Power revenues	6.1		6.0
Appliance service revenues	5.5		5.0


Total other non-utility operating revenues	$	65.4	$	55.5

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)	2025		2024
Alternative revenues (1)	$	18.3	$	60.5
Late payment charges	13.8		14.6
Other	14.2		0.6
Total other operating revenues	$	46.3	$	75.7

(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. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2024 Annual Report on Form 10-K.

NOTE 4—CREDIT LOSSES

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.

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.


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We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at March 31, 2025 and December 31, 2024, by reportable segment.


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
March 31, 2025
Accounts receivable and unbilled revenues	$	1,183.3		$	605.9		$	111.7		$	1,900.9		$	64.5		$	6.4		$	1,971.8
Allowance for credit losses	60.9			93.2			5.3			159.4			—			—			159.4
Accounts receivable and unbilled revenues, net (1)	$	1,122.4		$	512.7		$	106.4		$	1,741.5		$	64.5		$	6.4		$	1,812.4

Total accounts receivable, net – past due greater than 90 days (1)	$	43.3		$	34.7		$	0.9		$	78.9		$	—		$	—		$	78.9
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	96.0		%	100.0		%	—		%	96.7		%	—		%	—		%	96.7		%


(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		%

(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 March 31, 2025, $1,134.0 million, or 62.6%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 23, 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 roll-forward of the allowance for credit losses by reportable segment is included below:


Three Months Ended March 31, 2025 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2025	$	73.6	$	83.9	$	5.3	$	162.8
Provision for credit losses	16.1		16.3		0.2		32.6
Provision for credit losses deferred for future recovery or refund	(7.3)		2.2		—		(5.1)
Write-offs charged against the allowance	(33.8)		(25.6)		(0.7)		(60.1)
Recoveries of amounts previously written off	12.3		16.4		0.5		29.2
Balance at March 31, 2025	$	60.9	$	93.2	$	5.3	$	159.4

On a consolidated basis, there was a $3.4 million decrease in the allowance for credit losses at March 31, 2025, compared to January 1, 2025. The allowance for credit losses decreased in Wisconsin during the quarter mainly driven by customer write-offs in addition to a decrease in past due account balances. Reserves increased in Illinois due to an increase in past due balances over the winter moratorium months, when we are not allowed to disconnect service as a result of non-payment. In Illinois, the winter moratorium begins on December 1 and ends on March 31.


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Three Months Ended March 31, 2024 (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	13.8		15.1		(3.0)		25.9
Provision for credit losses deferred for future recovery or refund	15.7		1.3		—		17.0
Write-offs charged against the allowance	(35.6)		(28.0)		(1.3)		(64.9)
Recoveries of amounts previously written off	11.7		6.5		1.0		19.2
Balance at March 31, 2024	$	83.0	$	104.6	$	3.1	$	190.7

On a consolidated basis, there was a $2.8 million decrease in the allowance for credit losses at March 31, 2024, compared to January 1, 2024, driven by lower required reserve percentages at our Illinois and Other States segments as a result of an improvement in loss rates. Reserve percentages at our Wisconsin segment did not change significantly from those calculated in 2023. Largely offsetting the decrease in the allowance for credit losses, we saw an increase in past due accounts receivable balances at our Wisconsin and Illinois segments. An increase in past due balances is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2025 and December 31, 2024. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2024 Annual Report on Form 10-K.


(in millions)	March 31, 2025		December 31, 2024
Regulatory assets
Plant retirement related items	$	820.8	$	810.5
Pension and OPEB costs	660.4		684.9
Environmental remediation costs	540.7		570.1
Income tax related items	446.3		438.5
AROs	170.3		166.7
Uncollectible expense	133.4		151.5
Decoupling	129.1		110.0
System support resource	100.4		102.9
Securitization	74.3		76.5
Energy costs recoverable through rate adjustments	72.2		8.3
Bluewater	55.1		57.7
Finance and operating leases	26.0		22.0
Energy efficiency programs	17.3		26.5
Derivatives	7.7		38.2
Other, net	113.8		114.4
Total regulatory assets	$	3,367.8	$	3,378.7

Balance sheet presentation
Other current assets	$	84.5	$	39.0
Regulatory assets	3,283.3		3,339.7
Total regulatory assets	$	3,367.8	$	3,378.7


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(in millions)	March 31, 2025		December 31, 2024
Regulatory liabilities
Income tax related items	$	1,810.7	$	1,825.4
Removal costs	1,492.2		1,458.2
Pension and OPEB benefits	302.1		308.5
Energy costs refundable through rate adjustments	224.9		160.8
Derivatives	94.8		36.9
Uncollectible expense	45.7		47.2
Revenue requirements of renewable generation facilities	42.5		44.2
Property tax (1)	19.6		19.3
Electric transmission costs	16.2		19.7
Other, net	94.7		83.1
Total regulatory liabilities	$	4,143.4	$	4,003.3

Balance sheet presentation
Other current liabilities	$	99.5	$	45.3
Regulatory liabilities	4,043.9		3,958.0
Total regulatory liabilities	$	4,143.4	$	4,003.3

**(1)**In accordance with MERC's property tax tracker, MERC defers as a regulatory asset or liability the difference between actual property tax expense and the amount included in rates until recovery or refund is authorized in a future rate proceeding.

NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for several other renewable and other projects and have also acquired additional projects. OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 7 and 8 was $648.1 million at March 31, 2025, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WE 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 and the other co-owners 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 $246.6 million at March 31, 2025, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and 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 and Delilah Solar Energy LLC – Storm Damage

During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage. As of March 31, 2025, we recognized an impairment of $2.8 million related to damage from these storms, and recorded a $2.8 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.

In March 2025, both our Samson I and Delilah I solar facilities experienced damage from a storm. We are still assessing the extent of the damage at both of these facilities and we do have insurance coverage in place. As a result, similar to the storms discussed above, although we may experience differences between periods in the timing of cash flows related to necessary repairs and lost revenues, we do not currently expect a significant impact to our long-term cash flows related to this storm.


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NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the three months ended March 31, 2025, the Compensation Committee of our Board of Directors awarded the following stock-based compensation to our directors, officers, and certain other key employees:


Award Type						Number of Awards
Stock options (1)						231,024
Restricted shares (2)						79,170
Performance units						185,945

(1)Stock options awarded had a weighted-average exercise price of $94.55 and a weighted-average grant date fair value of $18.23 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $94.55 per share.

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 LLC (which holds our ownership interest in ATC), 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. Our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2024 Annual Report on Form 10-K for additional information on these and other restrictions.

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

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.

In August 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. As of March 31, 2025, we had issued 2,008,498 shares of common stock under the EDA and received proceeds of $201.4 million, which is net of $2.8 million of commissions and other fees. We have not entered into any forward sale agreements.

We had the following changes to our outstanding common stock during the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31, 2025	Three Months Ended March 31, 2024
Common stock shares outstanding at beginning of period	317,680,855	315,434,531
Shares issued:
At-the-market offering program	977,824	—
Stock-based compensation	342,711	142,178
401(k)	43,300	124,300
Stock investment plan	88,811	121,578
Common stock shares outstanding at end of period	319,133,501	315,822,587


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On April 17, 2025, our Board of Directors declared a quarterly cash dividend of $0.8925 per share, payable on June 1, 2025, to shareholders of record on May 14, 2025.

Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the three months ended March 31, 2025 and 2024:


(in millions)	Three Months Ended March 31, 2025		Three Months Ended March 31, 2024
Numerator:
Net income attributed to common shareholders	$	724.2	$	622.3

Denominator:
Weighted average basic shares outstanding	318.2		315.6
Dilutive effect of stock-based compensation awards	0.5		0.3
Dilutive effect of convertible senior notes	0.6		—
Weighted average diluted shares	319.3		315.9

Basic EPS	$	2.28	$	1.97
Diluted EPS	$	2.27	$	1.97

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

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


(in millions, except percentages)	March 31, 2025			December 31, 2024
Commercial paper
Amount outstanding	$	1,323.9		$	1,114.4
Weighted-average interest rate on amounts outstanding	4.63		%	4.63		%
Operating expense loans
Amount outstanding (1)	$	3.2		$	2.2

(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 the three months ended March 31, 2025 was $1,250.7 million with a weighted-average interest rate during the period of 4.58%.

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:


(in millions)	Maturity	March 31, 2025
WEC Energy Group	September 2026	$	1,500.0
WEC Energy Group	October 2025	200.0
WE	September 2026	500.0
WPS	September 2026	400.0
WG	September 2026	350.0
PGL	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		1,323.9
Available capacity under existing agreements		$	1,973.8


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NOTE 9—LONG-TERM DEBT

WEC Energy Group, Inc.

Convertible Senior Notes

As of March 31, 2025, the conditions allowing holders to convert their notes were not met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes 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 March 31, 2025:


(in millions)	Principal Amount		Unamortized Debt Issuance Costs		Net Carrying Amount		Fair Value Amount (1)
2027 Notes	$	862.5	$	(7.2)	$	855.3	$	1,009.0
2029 Notes	862.5		(8.3)		854.2		1,029.2

(1) The fair values are categorized in Level 2 of the fair value hierarchy. See Note 13, Fair Value Measurements, for more information on the levels of the fair value hierarchy.

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


(in millions)	Three Months Ended March 31, 2025
2027 Notes
Contractual interest expense	$	9.4
Amortization of debt issuance costs	0.8
Total interest expense – 2027 Notes	10.2

2029 Notes
Contractual interest expense	9.4
Amortization of debt issuance costs	0.5
Total interest expense – 2029 Notes	$	9.9

Minnesota Energy Resources Corporation

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

Michigan Gas Utilities Corporation

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

NOTE 10—LEASES

In February 2025, WECI closed on its acquisition of a 90% ownership interest in Hardin III, a solar generating facility. Related to its investment in Hardin III, WECI acquired several land leases that commenced in the first quarter of 2025. See Note 2, Acquisitions, for more information on this project.

The land leases acquired related to Hardin III have terms consisting of 1) an initial term of 25 years with an option for an additional 25-year extension and 2) an initial term of 35 years with an option for a 10-year extension. We expect the optional extensions to be exercised, and, as a result, these land leases are being amortized over the extended terms of the leases. Our total obligation under these land-related operating leases was $32.8 million at March 31, 2025, and was included in other long-term liabilities on our balance sheet. Our operating lease right of use assets were $32.4 million as of March 31, 2025, and were included in other long-term assets on our balance sheet. Our weighted-average discount rate for these land-related operating leases was 6.30%. 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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Future minimum lease payments and the corresponding present value of our net minimum lease payments under these land-related operating leases as of March 31, 2025, were as follows:


(in millions)
Nine Months Ended December 31, 2025	$	1.6
2026	1.6
2027	1.7
2028	1.7
2029	1.7
2030	1.8
Thereafter	120.5
Total minimum lease payments	130.6
Less: Interest	(97.8)
Present value of minimum lease payments	32.8
Less: Short-term lease liabilities	—
Long-term lease liabilities	$	32.8

NOTE 11—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	March 31, 2025		December 31, 2024
Materials and supplies	$	394.5	$	412.5
Fossil fuel	97.0		100.5
Natural gas in storage	84.5		300.2
Total	$	576.0	$	813.2

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. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2025, we had a temporary LIFO liquidation credit of $68.6 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 12—INCOME TAXES

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














	Three Months Ended March 31, 2025				Three Months Ended March 31, 2024
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	164.8	21.0	%	$	149.1	21.0	%
State income taxes net of federal tax benefit	48.5		6.2	%	43.4		6.1	%
PTCs, net	(120.1)		(15.3)	%	(88.0)		(12.4)	%
Federal excess deferred tax amortization	(18.7)		(2.4)	%	(15.4)		(2.2)	%
AFUDC-Equity	(8.5)		(1.1)	%	(6.3)		(0.9)	%



Other, net	(5.3)		(0.7)	%	4.9		0.7	%
Total income tax expense	$	60.7	7.7	%	$	87.7	12.3	%

The effective tax rates for the three months ended March 31, 2025 and 2024, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in renewable generation facilities in our non-utility energy infrastructure and Wisconsin segments and the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. These items were partially offset by state income taxes.


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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 (see federal excess deferred tax amortization line above).

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. Under this transferability provision, we entered into agreements in October 2024 and April 2025 to sell the majority of the PTCs we generate in 2025 and 2026, respectively, to third parties. We elect to account for tax credits transferred under the scope of 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 be capitalized for tax purposes. We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return and plan to adopt the safe harbor method of accounting for our remaining utilities on our 2024 tax return, which increased our deferred tax liabilities.

NOTE 13—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 regional transmission organization.


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


	March 31, 2025
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	81.7	$	3.9	$	—	$	85.6
FTRs and TCRs	—		—		3.0		3.0
Total derivative assets	$	81.7	$	3.9	$	3.0	$	88.6

Investments held in rabbi trust	$	34.2	$	—	$	—	$	34.2

Derivative liabilities
Natural gas contracts	$	—	$	4.9	$	—	$	4.9


	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

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 and Operating Reserves Markets and the Southwest Power Pool 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. For the three months ended March 31, 2025, we recorded $1.8 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $3.7 million of net unrealized gains recorded during the same quarter in 2024.

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


	Three Months Ended March 31
(in millions)	2025		2024
Balance at the beginning of the period	$	7.8	$	7.2
Purchases	1.2		1.0
Net realized and unrealized losses included in earnings (1)	(0.3)		(0.8)
Settlements	(5.7)		(4.8)
Balance at the end of the period	$	3.0	$	2.6
Net unrealized gains included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)	$	—	$	0.1

(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.


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Fair Value of Financial Instruments

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


	March 31, 2025				December 31, 2024
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	21.8	$	30.4	$	21.2
Long-term debt, including current portion	18,891.7		18,271.9		18,907.1		17,840.8

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

NOTE 14—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 an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

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


	March 31, 2025				December 31, 2024
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	78.2	$	4.9	$	29.2	$	13.9
FTRs and TCRs	3.0		—		7.8		—
Total current	81.2		4.9		37.0		13.9

Long-term
Natural gas contracts	7.4		—		4.1		—

Total	$	88.6	$	4.9	$	41.1	$	13.9

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


	Three Months Ended March 31, 2025			Three Months Ended March 31, 2024
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	61.5 Dth	$	(1.9)	67.8 Dth	$	(56.9)
FTRs and TCRs	7.4 MWh	1.5		7.6 MWh	1.6
Total		$	(0.4)		$	(55.3)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2025 and December 31, 2024, we had posted cash collateral of $12.9 million and


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$16.0 million, respectively. These amounts were recorded on our balance sheets in other current assets. At March 31, 2025 and December 31, 2024, we had also received cash collateral of $47.8 million and $4.2 million, respectively. These amounts were recorded on our balance sheets in other current liabilities.

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


	March 31, 2025					December 31, 2024
(in millions)	Derivative Assets			Derivative Liabilities		Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	88.6		$	4.9	$	41.1		$	13.9
Gross amount not offset on the balance sheet	(48.4)		(1)	(0.6)		(11.5)		(2)	(7.3)
Net amount	$	40.2		$	4.3	$	29.6		$	6.6

(1)Includes cash collateral received of $47.8 million.

(2)Includes cash collateral received of $4.2 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 three months ended March 31, 2025 and 2024 were not significant. At March 31, 2025, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 15—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at March 31, 2025			Expiration

(in millions)			Less Than 1 Year			1 to 3 Years			Over 3 Years
Standby letters of credit (1)	$	177.3		$	20.6		$	30.0		$	126.7
Surety bonds (2)	45.5			44.7			0.8			—
Other guarantees (3)	11.0			—			—			11.0
Total guarantees	$	233.8		$	65.3		$	30.8		$	137.7

(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 16—EMPLOYEE BENEFITS

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


		Pension Benefits
	Three Months Ended March 31
(in millions)			2025		2024
Service cost			$	5.7	$	6.7
Interest cost			30.3		29.5
Expected return on plan assets			(44.1)		(45.8)


Amortization of net actuarial loss			13.6		14.4
Net periodic benefit cost			$	5.5	$	4.8


		OPEB Benefits
	Three Months Ended March 31
(in millions)		2025		2024
Service cost		$	2.8	$	2.8
Interest cost		6.5		5.7
Expected return on plan assets		(13.6)		(13.2)

Amortization of prior service credit		(3.2)		(3.4)
Amortization of net actuarial gain		(1.4)		(1.9)
Net periodic benefit credit		$	(8.9)	$	(10.0)

During the three months ended March 31, 2025, we made contributions and payments of $3.5 million related to our pension plans and $0.4 million related to our OPEB plans. We expect to make contributions and payments of $8.6 million related to our pension plans and $2.2 million related to our OPEB plans during the remainder of 2025, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As of March 31, 2025 and December 31, 2024, our balance sheets included regulatory assets of $19.5 million and $24.9 million, respectively, for pension costs and $33.5 million and $38.2 million, respectively, for OPEB costs. In accordance with our December 2024 PSCW rate order, we began amortizing these regulatory assets in 2025. We continue to utilize escrow accounting for our current pension and OPEB costs. The above tables do not reflect any adjustments for the creation or amortization of these regulatory assets.

NOTE 17—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 March 31, 2025. We had no changes to the carrying amount of goodwill during the three months ended March 31, 2025.


(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 March 31, 2025.

Other Indefinite-Lived Intangible Assets

At both March 31, 2025 and December 31, 2024, we had $29.3 million of indefinite-lived intangible assets, largely consisting of spectrum frequencies. The spectrum frequencies enable our utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of


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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 March 31, 2025 and December 31, 2024, we had a finite-lived intangible asset with a gross carrying amount of $18.8 million and $13.0 million, respectively, related to a PPA for Maple Flats Solar Energy Center acquired by WECI in November 2024. The PPA will be amortized over a useful life of 15 years and expires in 2039. At March 31, 2025 and 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 quarter ended March 31, 2025. Amortization expense to be recorded as a decrease to operating revenues is expected to be $1.3 million in each of the next five years.

Intangible Liabilities

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


	March 31, 2025						December 31, 2024
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	751.2	$	(133.0)	$	618.2	$	679.6	$	(119.3)	$	560.3
Proxy revenue swap (2)	7.2		(4.4)		2.8		7.2		(4.2)		3.0
Interconnection agreements (3)	4.7		(1.2)		3.5		4.7		(1.2)		3.5
Total intangible liabilities	$	763.1	$	(138.6)	$	624.5	$	691.5	$	(124.7)	$	566.8

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead Wind Energy LLC, Samson I, Sapphire Sky Wind Energy LLC, Delilah I, and Hardin III 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 Hardin III in 2025.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream Wind Energy LLC'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.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, 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 three months ended March 31, 2025 and 2024, was $13.9 million and $13.4 million, respectively. Amortization for the next five years, including amounts recorded through March 31, 2025, 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	$	57.9	$	59.9	$	59.9	$	59.9	$	59.9
Amortization to be recorded as a decrease to other operation and maintenance	0.2		0.2		0.2		0.2		0.2


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NOTE 18—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. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:






















	Three Months Ended March 31, 2025
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	2,085.1	$	23.8	$	2,108.9
Add: Earnings from equity method investment	50.0		3.6		53.6
Add: Capital contributions	42.3		—		42.3
Less: Distributions	55.8		—		55.8

Balance at end of period	$	2,121.6	$	27.4	$	2,149.0

	Three Months Ended March 31, 2024
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,980.8	$	25.1	$	2,005.9
Add: Earnings from equity method investment	44.4		0.4		44.8
Add: Capital contributions	12.1		—		12.1
Less: Distributions	35.7		—		35.7


Balance at end of period	$	2,001.6	$	25.5	$	2,027.1

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.

The following table summarizes our significant related party transactions with ATC:


	Three Months Ended March 31
(in millions)		2025		2024
Charges to ATC for services and construction		$	4.5	$	4.7
Charges from ATC for network transmission services		116.7		103.3
Refund from ATC related to FERC ROE orders		1.4		—

Our balance sheets included the following receivables and payables for services provided to or received from ATC:


(in millions)	March 31, 2025		December 31, 2024
Accounts receivable for services provided to ATC	$	2.0	$	1.4

Accounts payable for services received from ATC	38.9		34.4
Amounts due from ATC for transmission infrastructure upgrades (1)	11.3		54.5

(1)These 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:


	Three Months Ended March 31
(in millions)		2025		2024
Income statement data
Operating revenues		$	234.9	$	211.9
Operating expenses		116.7		104.8
Other expense, net		39.1		35.2
Net income		$	79.1	$	71.9


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(in millions)	March 31, 2025		December 31, 2024
Balance sheet data
Current assets	$	145.8	$	126.6
Noncurrent assets	6,946.6		6,792.6
Total assets	$	7,092.4	$	6,919.2

Current liabilities	$	639.1	$	482.4
Long-term debt	3,025.9		3,083.4
Other noncurrent liabilities	559.0		545.0
Members' equity	2,868.4		2,808.4
Total liabilities and members' equity	$	7,092.4	$	6,919.2

NOTE 19—SEGMENT INFORMATION

Our President and Chief Executive Officer, 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 3, Operating Revenues, for more information on disaggregation of operating revenues, including intercompany eliminations. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies, in our 2024 Annual Report on Form 10-K.

At March 31, 2025, 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 18, Investment in Transmission Affiliates, for more information on ATC and ATC Holdco.
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 holds majority interests in multiple renewable generating facilities.

See Note 2, Acquisitions, for more information on WECI's recent acquisition of Hardin III.


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The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, and WEC Business Services LLC.

The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2025 and 2024:


	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
Three Months Ended March 31, 2025
External revenues	$	2,059.9	$	788.3	$	227.1	$	3,075.3	$	—	$	74.2	$	—	$	—	$	3,149.5
Intersegment revenues	—		—		—		—		—		120.1		—		(120.1)		—
Fuel and purchased power	390.3		—		—		390.3		—		—		—		—		390.3
Cost of natural gas sold	378.5		288.2		117.6		784.3		—		4.5		—		(13.4)		775.4
Other operation and maintenance	415.1		146.9		28.7		590.7		—		22.1		(3.2)		(1.6)		608.0
Depreciation and amortization	243.6		64.4		12.2		320.2		—		58.2		5.4		(23.9)		359.9
Property and revenue taxes	46.0		20.4		6.5		72.9		—		5.4		0.1		—		78.4
Equity in earnings of transmission affiliates	—		—		—		—		53.6		—		—		—		53.6
Other income, net (1)	17.6		2.1		0.1		19.8		—		0.7		5.0		(7.4)		18.1
Interest expense	161.8		23.2		4.3		189.3		4.8		30.6		86.9		(88.6)		223.0
Income tax expense (benefit)	82.0		69.2		14.8		166.0		11.9		(35.6)		(81.6)		—		60.7
Preferred stock dividends of subsidiary	0.3		—		—		0.3		—		—		—		—		0.3
Net income attributed to noncontrolling interests	—		—		—		—		—		(1.0)		—		—		(1.0)
Net income (loss) attributed to common shareholders	$	359.9	$	178.1	$	43.1	$	581.1	$	36.9	$	108.8	$	(2.6)	$	—	$	724.2

Other Segment Disclosures
Capital expenditures and asset acquisitions	$	616.9	$	53.8	$	17.8	$	688.5	$	—	$	414.6	$	4.1	$	—	$	1,107.2
Equity method investments	16.3		—		—		16.3		2,149.0		—		68.6		—		2,233.9
Total assets (2)	30,836.9		8,344.2		1,638.1		40,819.2		2,159.4		7,886.4		1,243.2		(3,876.1)		48,232.1

(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 March 31, 2025 reflect an elimination of $2,648.6 million for all lease activity between We Power and WE.


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	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
Three Months Ended March 31, 2024
External revenues	$	1,778.8	$	666.0	$	184.6	$	2,629.4	$	—	$	50.8	$	—	$	—	$	2,680.2
Intersegment revenues	—		—		—		—		—		120.1		—		(120.1)		—
Fuel and purchased power	349.2		—		—		349.2		—		—		—		—		349.2
Cost of natural gas sold	301.8		194.7		90.8		587.3		—		4.8		—		(14.2)		577.9
Other operation and maintenance	389.9		107.0		20.6		517.5		—		18.2		(3.4)		(1.5)		530.8
Depreciation and amortization	224.6		63.5		11.4		299.5		—		49.1		5.6		(20.8)		333.4
Property and revenue taxes	47.3		18.1		6.2		71.6		—		3.8		0.1		—		75.5
Equity in earnings of transmission affiliates	—		—		—		—		44.8		—		—		—		44.8
Other income, net (1)	33.4		1.9		—		35.3		—		—		15.5		(6.7)		44.1
Interest expense	157.8		25.0		4.0		186.8		4.8		24.1		66.6		(90.3)		192.0
Income tax expense (benefit)	74.9		72.1		13.0		160.0		9.9		(23.4)		(58.8)		—		87.7
Preferred stock dividends of subsidiary	0.3		—		—		0.3		—		—		—		—		0.3

Net income attributed to common shareholders	$	266.4	$	187.5	$	38.6	$	492.5	$	30.1	$	94.3	$	5.4	$	—	$	622.3

Other Segment Disclosures
Capital expenditures and asset acquisitions	$	330.8	$	75.7	$	18.1	$	424.6	$	—	$	17.3	$	2.6	$	—	$	444.5
Equity method investments	14.5		—		—		14.5		2,027.1		—		65.2		—		2,106.8
Total assets (2)	28,546.7		7,956.4		1,557.4		38,060.5		2,027.2		6,320.8		1,114.2		(3,595.5)		43,927.2

(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 March 31, 2024 reflect an elimination of $2,719.3 million for all lease activity between We Power and WE.

NOTE 20—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)	March 31, 2025		December 31, 2024
Assets
Other current assets (restricted cash)	$	4.3	$	1.5
Regulatory assets	74.3		76.5
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.2		9.2
Accounts payable	0.1		—
Other current liabilities (accrued interest)	0.4		0.1
Long-term debt	76.5		76.4

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 March 31, 2025 and December 31, 2024, our equity investment in ATC was $2,121.6 million and $2,085.1 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 March 31, 2025 and December 31, 2024, our equity investment in ATC Holdco was $27.4 million and $23.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.


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See Note 18, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

NOTE 21—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.

Our minimum future commitments related to these purchase obligations as of March 31, 2025, including those of our subsidiaries, were approximately $9.5 billion.

Environmental Matters

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

Federal Deregulatory Actions

In March 2025, the EPA announced a large-scale deregulatory effort. The EPA announced that, in total, it expects to take 31 deregulatory actions that will likely take multiple years to complete. Of these 31 deregulatory actions, the actions that would apply to us include those impacting the Good Neighbor Rule, MATS, the PM Standard, the Greenhouse Gas Power Plant Rule, the Mandatory Greenhouse Gas Reporting Rule, the ELG, and the CCR Rule. Any EPA actions will require formal rulemaking proceedings and any such actions are likely to be subject to legal challenges. We continue to monitor and evaluate potential risks and benefits to us, depending on the actions ultimately taken.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

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

Our RICE units 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. In September 2024, the D.C. Circuit Court of Appeals granted the EPA's motion for partial voluntary remand so that it could address issues of severability raised in the Supreme Court's June 2024 opinion granting the petitions for stay of the rule. Pursuant to an order of the D.C. Circuit Court of Appeals, the parties filed motions to govern future


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proceedings in December 2024. In January 2025, the D.C. Circuit Court of Appeals issued an order establishing a schedule for supplemental briefing on the issue of severability that extended through early March 2025. In March 2025, the D.C. Circuit Court of Appeals issued an order removing the case from its active docket and holding the case in abeyance, pending quarterly updates from the parties beginning in July 2025. We will continue to monitor this case as arguments at the D.C. Circuit Court of Appeals move forward.

In November 2024, the EPA issued a Good Neighbor Interim Final Rule that administratively stayed the effectiveness of the Good Neighbor Rule in all states to which it originally applies and ensured implementation of good neighbor obligations previously established to address the 2008 ozone NAAQS while the process works through the courts. We believe we are well positioned to comply with the rule's requirements. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

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

National Ambient Air Quality Standards

Ozone

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

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

The EPA's initial nonattainment area designation was effective August 2018, and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status based on the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022.

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

Particulate Matter

All counties within our service territories are in attainment with current 2012 standards for fine PM2.5. Under the former presidential administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard of 35 µg/m3. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until February 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air


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pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Climate Change

Pursuant to the final Greenhouse Gas Power Plant Rule published in May 2024, there are no applicable standards for coal plants until the end of 2031 and after 2031, the applicable standard is dependent upon the unit's retirement date. Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029. For new combined cycle natural gas plants above a 40% capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031. For new simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our 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. We currently believe our existing and planned combined cycle natural gas facilities will be positioned to comply with the proposed rule. As the EPA is not scheduled to finalize this proposal until late 2025, it could be revised or repealed. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, which includes updates to the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The revisions will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the final rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

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 natural gas, and Weston Unit 3. See Note 6, 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.


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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

Effective in June 2020, the requirements of Section 316(b) were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for 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 later 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 May 2024 with the publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect WE and WPS facilities relate to wastewater discharge limits for BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP, 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 NOPP 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 NOPP also may be filed for the OCPP, PWGS, and VAPP facilities because this ELG rule option will allow the company to qualify for more reasonable requirements to address the CRL provisions at our landfills that served these former coal-fired facilities.

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

In November 2024, Edison Electric Institute, on behalf of its members, submitted a petition for reconsideration to the EPA regarding the CRL provisions in the Supplemental ELG Rule in an effort to codify the rule interpretations articulated by the EPA staff during informational conference calls on this issue. We are still awaiting either a rule revision or clear written guidance from the EPA about the Supplemental ELG Rule CRL provisions to determine the applicability and potential compliance costs for inactive/closed landfills.

Numerous parties have challenged the rule through litigation pending in the U.S. Court of Appeals for the Eighth Circuit. The outcome of this case may affect our compliance plans. In February 2025, the U.S. Court of Appeals for the Eighth Circuit granted the EPA's request to hold the ELG rule litigation in abeyance. In April 2025, the EPA filed a motion with the U.S. Court of Appeals for the Eighth Circuit requesting that they continue to hold the case in abeyance until June 30, 2025. The Supplemental ELG Rule remains in


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effect during the pendency of the legal challenge. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which 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:


(in millions)	March 31, 2025		December 31, 2024
Regulatory assets	$	540.7	$	570.1
Reserves for future environmental remediation	442.1		445.8

Coal Combustion Residuals Rule

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

The final rule, which became effective in November 2024 will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. We expect the cost of the additional remediation would be recovered through future rates. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Enforcement and Litigation Matters

We 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

Joint Ownership Power Plants – Columbia Energy Center and Edgewater Generating Station

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 Clean Air Act'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


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jointly owned Columbia and Edgewater plants, the Edgewater Unit 4 generating unit was retired in September 2018. WPL started the process to close out this Consent Decree.

NOTE 22—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Three Months Ended March 31
(in millions)	2025		2024
Cash paid for interest, net of amount capitalized	$	132.4	$	158.6
Cash received for income taxes, net (1)	—		(83.0)
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	146.7		147.2
Common stock issued for stock-based compensation plans	3.2		6.2


Increase in receivable for corporate-owned life insurance proceeds	4.0		—

(1) Cash received for income taxes in the first quarter of 2024 includes $83.4 million related to 2023 PTCs that were sold to a third party.

Restricted Cash

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


(in millions)	March 31, 2025		December 31, 2024
Cash and cash equivalents	$	82.2	$	9.8
Restricted cash included in other current assets	26.9		5.3
Restricted cash included in other long-term assets	34.3		27.1
Cash, cash equivalents, and restricted cash	$	143.4	$	42.2

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 WEC Infrastructure Wind Holding I LLC, WEC Infrastructure Wind Holding II LLC, WECI Energy Holding III, and WEPCo Environmental Trust.
Cash related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account in order to fund future decommissioning.

NOTE 23—REGULATORY ENVIRONMENT

Wisconsin Electric Power Company

Very Large Customer and Bespoke Resources Tariffs

On March 31, 2025, WE filed an application with the PSCW requesting approval to implement a VLC Tariff and a Bespoke Resources Tariff. Under these proposed inter-connected tariffs, VLCs (new customers using 500 MWs or more, such as large data centers) will have access to reliable power to meet their needs and will directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them. The proposed tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

The two new tariffs will work in tandem as VLCs will be required to sign a service agreement and subscribe to a portion of one or more "Bespoke Resources," including renewable generation facilities, battery storage, and natural gas generation units. Under these


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agreements, if a VLC terminates or downsizes its plans, it will still be required to pay for the Bespoke Resources and dedicated distribution facilities that have been built to support its forecasted load, unless the facilities can be repurposed, subject to PSCW approval. Service agreements under the Bespoke Resources Tariff will be effective for the depreciable life of the resource, except for wind or solar resources which will have a term of 20 years. As proposed, the ROE (10.48%) and equity ratio (57%) will be fixed for the entire term of the agreement, and the revenue and costs recovered through the tariffs will be excluded from future rate case proceedings and earnings sharing mechanisms.

We expect a decision from the PSCW in the second quarter of 2026.

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 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 projects to upgrade its natural gas delivery system until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of projects to upgrade PGL's natural gas delivery system that started in 2023 and emergency repairs needed to ensure the safety and reliability of the delivery system. 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.

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 capital investments needed to meet safety and reliability requirements of PGL's natural gas delivery system. Although the ICC ordered PGL to complete safety and reliability work in 2024, it denied the recovery of these costs in our current rates.

In accordance with the November 16, 2023 rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure. On February 20, 2025, the ICC issued an order


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setting expectations for PGL's prospective operations. 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. PGL will replace this cast and ductile iron pipe through its PRP. Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases. In addition, the program will be overseen by a safety monitor hired by the ICC. We are evaluating the impact of this order on our operations and capital plan.

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. In November 2024, the Illinois Appellate Court issued an opinion affirming the ICC order and the related disallowance. PGL and NSG subsequently petitioned the Illinois Supreme Court seeking review and reversal of the May 2023 order; however, their petition was denied on March 26, 2025.

As of March 31, 2025, 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 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 operation and maintenance expense 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. In October 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August order.

PGL's QIP reconciliations from 2017 through 2023 are still pending. The aggregate capital costs included in the rider during these open reconciliation years, along with any previously recognized return on these investments, totaled approximately $2.8 billion as of March 31, 2025. 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.

Upper Michigan Energy Resources Corporation

Amended Renewable Energy Plan

In accordance with Michigan Public Act 235, UMERC filed an AREP with the MPSC on February 27, 2025. UMERC's AREP addresses its compliance with the Act 235 renewable portfolio standards and its proposal to recover the projected compliance costs through an incremental renewable energy surcharge. The projected compliance costs include the purchase of Michigan-sourced renewable energy credits and the revenue requirements for Renegade (see discussion below) and any other incremental renewable generation resources required to meet the Act 235 renewable portfolio standards.


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UMERC's AREP includes its previously approved investment in Renegade, a 100 MW utility-scale solar-powered electric generating facility that will be located in Delta and Marquette counties, Michigan. Construction of Renegade is expected to be completed by the end of 2026, and the cost of this project is estimated to be approximately $226 million. UMERC's AREP requests the recovery of the annual revenue requirement of Renegade through the proposed renewable energy surcharge beginning in January 2027.

The MPSC's approval of the AREP and the proposed renewable energy surcharge is still pending.

NOTE 24—NEW ACCOUNTING PRONOUNCEMENTS

Disaggregation of Income Statement Expenses

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

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.


03/31/2025 Form 10-Q			39			WEC Energy Group, Inc.

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