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)			2024		2023
Operating revenues			$	2,680.2	$	2,888.1

Operating expenses
Cost of sales			927.1		1,309.7
Other operation and maintenance			530.8		534.0
Depreciation and amortization			333.4		305.5
Property and revenue taxes			75.5		69.6
Total operating expenses			1,866.8		2,218.8

Operating income			813.4		669.3

Equity in earnings of transmission affiliates			44.8		43.8
Other income, net			44.1		40.8
Interest expense			192.0		172.2
Other expense			(103.1)		(87.6)

Income before income taxes			710.3		581.7
Income tax expense			87.7		74.1
Net income			622.6		507.6

Preferred stock dividends of subsidiary			0.3		0.3
Net loss attributed to noncontrolling interests			—		0.2
Net income attributed to common shareholders			$	622.3	$	507.5

Earnings per share
Basic			$	1.97	$	1.61
Diluted			$	1.97	$	1.61

Weighted average common shares outstanding
Basic			315.6		315.4
Diluted			315.9		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)			2024		2023
Net income			$	622.6	$	507.6

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			622.5		507.5

Preferred stock dividends of subsidiary			0.3		0.3
Comprehensive loss attributed to noncontrolling interests			—		0.2
Comprehensive income attributed to common shareholders			$	622.2	$	507.4

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, 2024		December 31, 2023
Assets
Current assets
Cash and cash equivalents	$	38.9	$	42.9
Accounts receivable and unbilled revenues, net of reserves of $190.7 and $193.5, respectively	1,557.0		1,503.2
Materials, supplies, and inventories	608.6		775.2
Prepaid taxes	143.0		173.9
Other prepayments	70.9		76.8

Other	186.2		223.7
Current assets	2,604.6		2,795.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,275.0 and $11,073.1, respectively	31,729.8		31,581.5
Regulatory assets (March 31, 2024 and December 31, 2023 include $84.1 and $85.9, respectively, related to WEPCo Environmental Trust)	3,247.0		3,249.8
Equity investment in transmission affiliates	2,027.1		2,005.9
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	883.9		870.9
Other	382.0		383.1
Long-term assets	41,322.6		41,144.0
Total assets	$	43,927.2	$	43,939.7

Liabilities and Equity
Current liabilities
Short-term debt	$	2,574.2	$	2,020.9
Current portion of long-term debt (March 31, 2024 and December 31, 2023 include $9.0, related to WEPCo Environmental Trust)	640.5		1,264.2
Accounts payable	640.9		896.6
Other	854.1		933.1
Current liabilities	4,709.7		5,114.8

Long-term liabilities
Long-term debt (March 31, 2024 and December 31, 2023 include $85.4 and $85.3, respectively, related to WEPCo Environmental Trust)	15,375.8		15,512.8
Deferred income taxes	5,120.0		4,918.5
Deferred revenue, net	351.1		356.4
Regulatory liabilities	3,730.2		3,697.7
Intangible liabilities	581.4		594.8
Environmental remediation liabilities	448.9		463.7
AROs	377.7		374.2
Other	806.3		835.3
Long-term liabilities	26,791.4		26,753.4

Commitments and contingencies (Note 20)

Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,822,587 and 315,434,531 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,145.7		4,115.9
Retained earnings	7,971.6		7,612.8
Accumulated other comprehensive loss	(7.8)		(7.7)
Common shareholders' equity	12,112.7		11,724.2

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	283.0		316.9
Total liabilities and equity	$	43,927.2	$	43,939.7

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)	2024		2023
Operating activities
Net income	$	622.6	$	507.6
Reconciliation to cash provided by operating activities
Depreciation and amortization	333.4		305.5
Deferred income taxes and ITCs, net	184.3		56.5
Contributions and payments related to pension and OPEB plans	(4.0)		(5.5)
Equity income in transmission affiliates, net of distributions	(9.1)		(6.4)
Change in –
Accounts receivable and unbilled revenues, net	(61.3)		60.7
Materials, supplies, and inventories	166.6		293.6
Collateral on deposit	17.2		(91.8)
Other current assets	19.7		89.4
Accounts payable	(229.8)		(424.7)
Other current liabilities	(44.8)		63.7
Other, net	(131.2)		(52.5)
Net cash provided by operating activities	863.6		796.1

Investing activities
Capital expenditures	(444.5)		(499.4)
Acquisition of Whitewater	—		(76.0)
Acquisition of Sapphire Sky, net of cash acquired of $0.3	—		(442.6)
Acquisition of Samson I, net of cash acquired of $5.2	—		(249.4)
Capital contributions to transmission affiliates	(12.1)		(6.1)
Proceeds from the sale of investments held in rabbi trust	14.8		10.4
Other, net	5.6		(4.8)
Net cash used in investing activities	(436.2)		(1,267.9)

Financing activities
Exercise of stock options	3.7		0.9
Issuance of common stock	19.2		—
Purchase of common stock	(2.0)		(6.9)
Dividends paid on common stock	(263.5)		(246.1)
Issuance of long-term debt	—		1,100.0
Retirement of long-term debt	(756.9)		(35.2)
Change in commercial paper	552.8		(385.4)
Purchase of additional ownership interest in Samson I from noncontrolling interest	(28.1)		—
Other, net	(1.7)		(9.7)
Net cash provided by (used in) financing activities	(476.5)		417.6

Net change in cash, cash equivalents, and restricted cash	(49.1)		(54.2)
Cash, cash equivalents, and restricted cash at beginning of period	165.2		182.2
Cash, cash equivalents, and restricted cash at end of period	$	116.1	$	128.0

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, 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



	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, 2022	$	3.2	$	4,115.2	$	7,265.3	$	(6.8)	$	11,376.9	$	30.4	$	209.3	$	11,616.6
Net income attributed to common shareholders	—		—		507.5		—		507.5		—		—		507.5
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.2)		(0.2)
Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Common stock dividends of $0.7800 per share	—		—		(246.1)		—		(246.1)		—		—		(246.1)
Exercise of stock options	—		0.9		—		—		0.9		—		—		0.9
Purchase of common stock	—		(6.9)		—		—		(6.9)		—		—		(6.9)
Acquisition of noncontrolling interests	—		—		—		—		—		—		112.9		112.9
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.3)		(1.3)
Stock-based compensation and other	—		4.4		—		—		4.4		—		—		4.4
Balance at March 31, 2023	$	3.2	$	4,113.6	$	7,526.7	$	(6.9)	$	11,636.6	$	30.4	$	320.7	$	11,987.7

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, 2024

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 17, 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, 2023. 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, 2024, are not necessarily indicative of expected results for 2024 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 all of the below acquisitions met the criteria of asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 16, Goodwill and Intangibles, for more information.

Acquisitions of Solar Generation Facilities in Texas

In March 2024, WECI signed an agreement to acquire a 90% ownership interest in Delilah I, a 300 MW solar generating facility under construction in Lamar County, Texas, for approximately $459.0 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of the second quarter of 2024, at which time the transaction is expected to close. Delilah I is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

In February 2023, WECI completed the acquisition of an 80% ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar County, Texas. Samson I was acquired for $257.3 million, which included payments related to contingent consideration, transaction costs, and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation, May 2022. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment. In January 2024, WECI acquired an additional 10% ownership interest in Samson I for $28.1 million.


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Acquisitions of Electric Generation Facilities in Wisconsin

In June 2023, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to acquisition, WPS received approval to transfer its ownership interest rights to WE. WE's investment was $95.3 million. In addition, WPS filed an application with the PSCW in September 2023 to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity. As it did with the first option, in October 2023, WPS filed for approval to assign its ownership interest pursuant to this second option to WE. The PSCW approved both requests in February 2024. WE's incremental share of this investment is expected to be approximately $100 million, with the transaction expected to close in June 2024.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $143.8 million. Red Barn qualifies for PTCs.

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

Acquisitions of Electric Generation Facilities in Illinois

In February 2023, upon achievement of commercial operation, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility in McLean County, Illinois, for a total investment of $442.6 million, which includes transaction costs and is net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

In October 2022, WECI signed an agreement to acquire an 80% ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $360 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. The transaction is subject to FERC approval and commercial operation is expected to begin during the fourth quarter of 2024, at which time the transaction is expected to close. Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.


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NOTE 3—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2023 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, 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


(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, 2023
Electric	$	1,203.8	$	—	$	—	$	1,203.8	$	—	$	—	$	—		$	1,203.8
Natural gas	784.4		577.7		245.0		1,607.1		21.3		—		(21.1)			1,607.3
Total regulated revenues	1,988.2		577.7		245.0		2,810.9		21.3		—		(21.1)			2,811.1
Other non-utility revenues	—		—		5.2		5.2		43.5		—		(1.6)			47.1
Total revenues from contracts with customers	1,988.2		577.7		250.2		2,816.1		64.8		—		(22.7)			2,858.2
Other operating revenues	8.1		22.0		(0.2)		29.9		101.4		—		(101.4)		(1)	29.9
Total operating revenues	$	1,996.3	$	599.7	$	250.0	$	2,846.0	$	166.2	$	—	$	(124.1)		$	2,888.1

(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)	2024		2023
Residential	$	483.2	$	486.5
Small commercial and industrial	391.7		393.6
Large commercial and industrial	217.6		229.8
Other	7.9		8.0
Total retail revenues	1,100.4		1,117.9
Wholesale	25.6		34.2
Resale	45.1		40.6
Steam	10.2		11.0
Other utility revenues	4.0		0.1
Total electric utility operating revenues	$	1,185.3	$	1,203.8

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, 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


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2023
Residential	$	554.8	$	368.9	$	164.5	$	1,088.2
Commercial and industrial	295.2		117.9		91.5		504.6
Total retail revenues	850.0		486.8		256.0		1,592.8
Transportation	28.9		90.1		10.9		129.9
Other utility revenues (1)	(94.5)		31.7		(21.9)		(84.7)
Total natural gas utility operating revenues	$	784.4	$	608.6	$	245.0	$	1,638.0

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

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)	2024		2023
Wind generation revenues	$	44.5	$	36.0
We Power revenues (1)	6.0		5.9
Appliance service revenues	5.0		5.2


Total other non-utility operating revenues	$	55.5	$	47.1

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

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)	2024		2023
Alternative revenues (1)	$	60.5	$	11.8
Late payment charges	14.6		17.2
Other	0.6		0.9
Total other operating revenues	$	75.7	$	29.9

(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 2023 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


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

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at March 31, 2024 and December 31, 2023, 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, 2024
Accounts receivable and unbilled revenues	$	1,100.6		$	516.7		$	90.9		$	1,708.2		$	33.0		$	6.5		$	1,747.7
Allowance for credit losses	83.0			104.6			3.1			190.7			—			—			190.7
Accounts receivable and unbilled revenues, net (1)	$	1,017.6		$	412.1		$	87.8		$	1,517.5		$	33.0		$	6.5		$	1,557.0

Total accounts receivable, net – past due greater than 90 days (1)	$	68.2		$	45.7		$	1.3		$	115.2		$	—		$	—		$	115.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	95.0		%	100.0		%	—		%	95.9		%	—		%	—		%	95.9		%


(in millions)	Wisconsin			Illinois			Other States			Total Utility Operations			Non-Utility Energy Infrastructure			Corporate and Other			WEC Energy Group Consolidated
December 31, 2023
Accounts receivable and unbilled revenues	$	1,078.0		$	481.5		$	94.9		$	1,654.4		$	33.9		$	8.4		$	1,696.7
Allowance for credit losses	77.4			109.7			6.4			193.5			—			—			193.5
Accounts receivable and unbilled revenues, net (1)	$	1,000.6		$	371.8		$	88.5		$	1,460.9		$	33.9		$	8.4		$	1,503.2

Total accounts receivable, net – past due greater than 90 days (1)	$	51.7		$	45.0		$	2.1		$	98.8		$	—		$	—		$	98.8
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.6		%	100.0		%	—		%	94.5		%	—		%	—		%	94.5		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at March 31, 2024, $1,000.4 million, or 64.3%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

A roll-forward of the allowance for credit losses by reportable segment is included below:


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, and in Illinois the winter moratorium begins on December 1 and ends on March 31.


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Three Months Ended March 31, 2023 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at January 1, 2023	$	82.0	$	111.0	$	6.3	$	199.3
Provision for credit losses	11.2		8.5		1.3		21.0
Provision for credit losses deferred for future recovery or refund	20.4		15.2		—		35.6
Write-offs charged against the allowance	(28.9)		(23.0)		(1.6)		(53.5)
Recoveries of amounts previously written off	6.2		4.8		0.4		11.4
Balance at March 31, 2023	$	90.9	$	116.5	$	6.4	$	213.8

On a consolidated basis, there was a $14.5 million increase in the allowance for credit losses at March 31, 2023, compared to January 1, 2023, driven by an increase in past due accounts receivable balances at our Wisconsin and Illinois reportable segments. As discussed above, an increase in past due balances is a trend we generally see over the winter moratorium months.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2024 and December 31, 2023. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2023 Annual Report on Form 10-K.


(in millions)	March 31, 2024		December 31, 2023
Regulatory assets
Pension and OPEB costs	$	728.9	$	731.7
Plant retirement related items	637.8		646.2
Environmental remediation costs	583.8		596.8
Income tax related items	444.5		449.9
AROs	159.8		162.0
Uncollectible expense	133.7		127.7
System support resource	110.6		113.2
Derivatives	88.7		130.3
Decoupling	87.2		27.3
Securitization	84.1		85.9
Bluewater	51.1		45.3
Energy efficiency programs	29.3		33.9
Other, net	147.4		124.5
Total regulatory assets	$	3,286.9	$	3,274.7

Balance sheet presentation
Other current assets	$	39.9	$	24.9
Regulatory assets	3,247.0		3,249.8
Total regulatory assets	$	3,286.9	$	3,274.7


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(in millions)	March 31, 2024		December 31, 2023
Regulatory liabilities
Income tax related items	$	1,862.6	$	1,901.8
Removal costs	1,365.4		1,329.9
Pension and OPEB benefits	300.0		299.2
Energy costs refundable through rate adjustments	119.3		72.4
Electric transmission costs	31.0		30.3
Energy efficiency programs	20.6		17.2
Uncollectible expense	19.0		21.2
Derivatives	15.2		19.2
Other, net	76.3		54.0
Total regulatory liabilities	$	3,809.4	$	3,745.2

Balance sheet presentation
Other current liabilities	$	79.2	$	47.5
Regulatory liabilities	3,730.2		3,697.7
Total regulatory liabilities	$	3,809.4	$	3,745.2

NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 5-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 5-8 became probable. Subsequently, we have received additional approvals for electric generation facilities, including Koshkonong and 200 MWs of West Riverside. See Note 2, Acquisitions, for more information on the West Riverside acquisition and the two option exercises. OCPP Units 5 and 6 are expected to be retired by the end of May 2024, while OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 5-8 was $760.0 million at March 31, 2024, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. Columbia Units 1 and 2 are expected to be retired by June 2026. The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $255.2 million at March 31, 2024, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson I Solar Energy Center LLC – Storm Damage

During wind storms in March and June 2023, certain sections of our Samson I solar facility incurred damage. As of March 31, 2024, we recognized an impairment of $2.3 million related to storm damage, which was offset by a $2.3 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from these events.


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NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the three months ended March 31, 2024, 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)						283,869
Restricted shares (2)						105,778
Performance units						196,256

(1)Stock options awarded had a weighted-average exercise price of $85.05 and a weighted-average grant date fair value of $16.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $85.05 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 2023 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 compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans. As such, no new shares of common stock were issued during the three months ended March 31, 2023.

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


Common stock shares outstanding at beginning of period						315,434,531
Shares issued:
Stock-based compensation						142,178
401(k)						124,300
Stock investment plan						121,578
Common stock shares outstanding at end of period						315,822,587

On April 18, 2024, our Board of Directors declared a quarterly cash dividend of $0.835 per share, payable on June 1, 2024, to shareholders of record on May 14, 2024.


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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, 2024			December 31, 2023
Commercial paper
Amount outstanding	$	2,570.0		$	2,017.2
Weighted-average interest rate on amounts outstanding	5.50		%	5.49		%
Operating expense loans
Amount outstanding (1)	$	4.2		$	3.7

(1)Coyote Ridge Wind, LLC, 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, 2024 was $2,014.4 million with a weighted-average interest rate during the period of 5.48%.

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, 2024
WEC Energy Group	September 2026	$	1,500.0
WEC Energy Group	October 2024	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		2,570.0
Available capacity under existing agreements		$	727.7

NOTE 9—LONG-TERM DEBT

WEC Energy Group, Inc.

In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes for $115.2 million with proceeds from issuing commercial paper. We recorded a $6.9 million gain related to the early settlement.

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

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	March 31, 2024		December 31, 2023
Materials and supplies	$	330.5	$	320.0
Natural gas in storage	160.0		327.8
Fossil fuel	118.1		127.4
Total	$	608.6	$	775.2


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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, 2024, we had a temporary LIFO liquidation debit of $4.3 million recorded within other current assets 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, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

NOTE 11—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, 2024				Three Months Ended March 31, 2023
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	149.1	21.0	%	$	122.1	21.0	%
State income taxes net of federal tax benefit	43.4		6.1	%	35.8		6.2	%
PTCs, net	(88.0)		(12.4)	%	(66.2)		(11.4)	%
Federal excess deferred tax amortization	(15.4)		(2.2)	%	(13.1)		(2.3)	%



Other, net	(1.4)		(0.2)	%	(4.5)		(0.8)	%
Total income tax expense	$	87.7	12.3	%	$	74.1	12.7	%

The effective tax rates for the three months ended March 31, 2024 and 2023, 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.

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). See Note 26, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information about the impact of the Tax Legislation.

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023, under this transferability provision, we entered into an agreement to sell substantially all of the PTCs we generated in 2023 to a third party. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

NOTE 12—FAIR VALUE MEASUREMENTS

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


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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.

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, 2024
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	1.5	$	2.9	$	—	$	4.4
FTRs and TCRs	—		—		2.6		2.6
Coal contracts	—		0.2		—		0.2
Total derivative assets	$	1.5	$	3.1	$	2.6	$	7.2

Investments held in rabbi trust	$	41.3	$	—	$	—	$	41.3

Derivative liabilities
Natural gas contracts	$	51.4	$	1.2	$	—	$	52.6
Coal contracts	—		18.0		—		18.0
Total derivative liabilities	$	51.4	$	19.2	$	—	$	70.6


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	December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	2.2	$	8.3	$	—	$	10.5
FTRs and TCRs	—		—		7.2		7.2
Coal contracts	—		0.3		—		0.3
Total derivative assets	$	2.2	$	8.6	$	7.2	$	18.0

Investments held in rabbi trust	$	51.7	$	—	$	—	$	51.7

Derivative liabilities
Natural gas contracts	$	70.1	$	16.0	$	—	$	86.1
Coal contracts	—		20.3		—		20.3
Total derivative liabilities	$	70.1	$	36.3	$	—	$	106.4

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy 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. During the three months ended March 31, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $3.7 million and $2.8 million, respectively.

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


	Three Months Ended March 31
(in millions)		2024		2023
Balance at the beginning of the period		$	7.2	$	7.8
Purchases		1.0		0.3
Realized and unrealized net losses included in earnings (1)		(0.8)		(0.3)
Settlements		(4.8)		(4.8)
Balance at the end of the period		$	2.6	$	3.0
Unrealized net gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)		$	0.1	$	(0.1)

(1)Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These realized and unrealized net gains and losses are recorded in operating revenues on our income statements.

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, 2024				December 31, 2023
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	20.3	$	30.4	$	21.4
Long-term debt, including current portion (1)	15,871.6		14,669.6		16,631.1		15,564.3

(1)The carrying amount of long-term debt excludes finance lease obligations of $144.7 million and $145.9 million at March 31, 2024 and December 31, 2023, respectively.

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


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NOTE 13—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, 2024				December 31, 2023
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	4.1	$	49.5	$	10.4	$	78.1
FTRs and TCRs	2.6		—		7.2		—
Coal contracts	0.2		10.9		0.3		10.9
Total current	6.9		60.4		17.9		89.0

Long-term
Natural gas contracts	0.3		3.1		0.1		8.0
Coal contracts	—		7.1		—		9.4
Total long-term	0.3		10.2		0.1		17.4
Total	$	7.2	$	70.6	$	18.0	$	106.4

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, 2024			Three Months Ended March 31, 2023
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	67.8 Dth	$	(56.9)	58.7 Dth	$	(75.3)
FTRs and TCRs	7.6 MWh	1.6		7.3 MWh	0.4
Total		$	(55.3)		$	(74.9)

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, 2024 and December 31, 2023, we had posted cash collateral of $83.1 million and $100.3 million, respectively. These amounts were recorded on our balance sheets in other current assets.


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


	March 31, 2024					December 31, 2023
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	7.2	$	70.6		$	18.0	$	106.4
Gross amount not offset on the balance sheet	(1.8)		(51.7)		(1)	(3.1)		(71.0)		(2)
Net amount	$	5.4	$	18.9		$	14.9	$	35.4

(1)Includes cash collateral posted of $49.9 million.

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

Cash Flow Hedges

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the three months ended March 31, 2024 and 2023 were not significant. At March 31, 2024, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 14—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at March 31, 2024			Expiration

(in millions)			Less Than 1 Year			1 to 3 Years			Over 3 Years
Standby letters of credit (1)	$	117.3		$	20.7		$	—		$	96.6
Surety bonds (2)	33.7			32.6			1.1			—
Other guarantees (3)	10.5			—			—			10.5
Total guarantees	$	161.5		$	53.3		$	1.1		$	107.1

(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 15—EMPLOYEE BENEFITS

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


		Pension Benefits
	Three Months Ended March 31
(in millions)			2024		2023
Service cost			$	6.7	$	6.6
Interest cost			29.5		30.8
Expected return on plan assets			(45.8)		(47.4)

Amortization of prior service cost			—		0.1
Amortization of net actuarial loss			14.4		7.4
Net periodic benefit cost (credit)			$	4.8	$	(2.5)


		OPEB Benefits
	Three Months Ended March 31
(in millions)			2024		2023
Service cost			$	2.8	$	2.5
Interest cost			5.7		5.4
Expected return on plan assets			(13.2)		(13.3)

Amortization of prior service credit			(3.4)		(3.7)
Amortization of net actuarial gain			(1.9)		(3.2)
Net periodic benefit credit			$	(10.0)	$	(12.3)

During the three months ended March 31, 2024, we made contributions and payments of $3.7 million related to our pension plans and $0.3 million related to our OPEB plans. We expect to make contributions and payments of $9.5 million related to our pension plans and $1.9 million related to our OPEB plans during the remainder of 2024, 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 a result, as of March 31, 2024, we recorded a $10.8 million regulatory asset for pension costs and a $20.7 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

NOTE 16—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, 2024. We had no changes to the carrying amount of goodwill during the three months ended March 31, 2024.


(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, 2024.

Intangible Assets

At both March 31, 2024 and December 31, 2023, we had $29.3 million of indefinite-lived intangible assets, largely consisting of spectrum frequencies. The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.


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Intangible Liabilities

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


	March 31, 2024						December 31, 2023
(in millions)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
PPAs (1)	$	653.9	$	(79.8)	$	574.1	$	653.9	$	(66.6)	$	587.3
Proxy revenue swap (2)	7.2		(3.6)		3.6		7.2		(3.5)		3.7
Interconnection agreements (3)	4.7		(1.0)		3.7		4.7		(0.9)		3.8
Total intangible liabilities	$	665.8	$	(84.4)	$	581.4	$	665.8	$	(71.0)	$	594.8

(1) Represents PPAs related to the acquisition of Blooming Grove Wind Energy Center LLC , Tatanka Ridge, Jayhawk, Thunderhead Wind Energy LLC, Samson I, and Sapphire Sky expiring between 2030 and 2037. The weighted-average remaining useful life of the PPAs is 11 years.

(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 five 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 17 years.

Amortization related to these intangible liabilities for the three months ended March 31, 2024 and 2023, was $13.4 million and $10.4 million, respectively. Amortization for the next five years, including amounts recorded through March 31, 2024, is estimated to be:


	For the Years Ending December 31
(in millions)	2024		2025		2026		2027		2028
Amortization to be recorded as an increase to operating revenues	$	53.4	$	53.4	$	53.4	$	53.4	$	53.4
Amortization to be recorded as a decrease to other operation and maintenance	0.2		0.2		0.2		0.2		0.2

NOTE 17—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, 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

	Three Months Ended March 31, 2023
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,884.6	$	24.6	$	1,909.2
Add: Earnings from equity method investment	42.9		0.9		43.8
Add: Capital contributions	6.1		—		6.1
Less: Distributions	37.4		—		37.4


Balance at end of period	$	1,896.2	$	25.5	$	1,921.7

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


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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)		2024		2023
Charges to ATC for services and construction		$	4.7	$	3.8
Charges from ATC for network transmission services		103.3		94.5

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


(in millions)	March 31, 2024		December 31, 2023
Accounts receivable for services provided to ATC	$	1.8	$	1.6

Accounts payable for services received from ATC	49.7		49.9
Amounts due from ATC for transmission infrastructure upgrades (1)	42.1		46.1

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

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


	Three Months Ended March 31
(in millions)		2024		2023
Income statement data
Operating revenues		$	211.9	$	200.4
Operating expenses		104.8		99.1
Other expense, net		35.2		32.5
Net income		$	71.9	$	68.8


(in millions)	March 31, 2024		December 31, 2023
Balance sheet data
Current assets	$	133.2	$	115.2
Noncurrent assets	6,423.4		6,337.0
Total assets	$	6,556.6	$	6,452.2

Current liabilities	$	587.9	$	495.9
Long-term debt	2,736.3		2,736.0
Other noncurrent liabilities	562.2		585.2
Members' equity	2,670.2		2,635.1
Total liabilities and members' equity	$	6,556.6	$	6,452.2

NOTE 18—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At March 31, 2024, we reported six segments, which are described below.

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.


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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 recent WECI acquisitions.

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.

All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three months ended March 31, 2024 and 2023:


	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)		—
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
Equity in earnings of transmission affiliates	—		—		—		—		44.8		—		—		—		44.8
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
Net income	266.7		187.5		38.6		492.8		30.1		94.3		5.4		—		622.6
Net income attributed to common shareholders	266.4		187.5		38.6		492.5		30.1		94.3		5.4		—		622.3


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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, 2023
External revenues	$	1,996.3	$	599.7	$	250.0	$	2,846.0	$	—	$	42.1	$	—	$	—	$	2,888.1
Intersegment revenues	—		—		—		—		—		124.1		—		(124.1)		—
Other operation and maintenance	380.8		113.7		24.7		519.2		—		17.8		(1.4)		(1.6)		534.0
Depreciation and amortization	207.3		58.5		10.4		276.2		—		42.7		5.1		(18.5)		305.5
Equity in earnings of transmission affiliates	—		—		—		—		43.8		—		—		—		43.8
Interest expense	150.6		21.6		4.2		176.4		4.8		19.9		55.6		(84.5)		172.2
Income tax expense (benefit)	65.9		42.0		11.2		119.1		9.7		(17.8)		(36.9)		—		74.1
Net income (loss)	257.5		113.1		33.2		403.8		29.3		88.3		(13.8)		—		507.6
Net income (loss) attributed to common shareholders	257.2		113.1		33.2		403.5		29.3		88.5		(13.8)		—		507.5

NOTE 19—VARIABLE INTEREST ENTITIES

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

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

WEPCo Environmental Trust Finance I, LLC

In November 2020, the PSCW issued a financing order approving the 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 have no 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.


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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, 2024		December 31, 2023
Assets
Other current assets (restricted cash)	$	3.2	$	0.8
Regulatory assets	84.1		85.9
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	9.0		9.0
Accounts payable	0.1		—
Other current liabilities (accrued interest)	0.5		0.1
Long-term debt	85.4		85.3

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At March 31, 2024 and December 31, 2023, our equity investment in ATC was $2,001.6 million and $1,980.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At March 31, 2024 and December 31, 2023, our equity investment in ATC Holdco was $25.5 million and $25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, 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 20—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, 2024, including those of our subsidiaries, were approximately $9.5 billion.


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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, 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.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Plan

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

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. The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu. Adoption of either of these lower limits could have an adverse effect on our operations. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations.

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 the reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration; however, in August 2023, the EPA announced that it is instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. 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 effective date for the initial nonattainment area designation was August 2018, and the attainment status is evaluated every three 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 for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit adequate SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard. This action triggered a May 2025 deadline for states to get their SIP approved or the EPA will issue a federal implementation plan. Additionally, offset sanctions will take effect in 18 months if the SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas. The WDNR intends to submit a SIP revision by the May 2025 deadline.


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The next attainment evaluation date is August 2024. If the moderate attainment deadline is not met, the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. We are currently evaluating the impacts of the potential nonattainment redesignation on our operations.

Particulate Matter

All counties within our service territories are in attainment with current 2012 standards for fine PM2.5. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard of 35 µg/m3. On February 7, 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 May 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. The potential nonattainment status could impact future permitting activities for facilities in applicable locations. The impacts include the potential need for improved or new air pollution control equipment. As we transition to natural gas, this new standard is expected to have less of an impact on our units.

Climate Change

In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. For coal plants, no standards would apply under the proposed version of the rule until 2032, and after 2032 the applicable standard would depend on the unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the proposed rule is highly dependent on the use of hydrogen as an alternative fuel, and on carbon capture technology. For simple cycle natural gas-fired combustion turbines, the proposed version of the rule does not include applicable limits as long as the capacity factor is less than 20%. Our RICE units in Michigan and the new Weston RICE project are not affected under the rule because each RICE unit is less than 25 MWs. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations.

In May 2023, the EPA also proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units. New natural gas stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load. Our RICE units are not affected by this rule since each unit is below 25 MWs. Our ESG Progress Plan is heavily focused on reducing GHG emissions.

In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule. The EPA had indicated it intends to draft a new rule for existing natural gas units in the near future. A non-regulatory docket has been opened by the EPA for this new rulemaking. The EPA anticipates a final rule in the second quarter of 2024.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, in June 2022. In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The proposed revisions could impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems. The EPA has indicated it anticipates a final rule in the second quarter of 2024. We cannot estimate the potential impact of the proposed rule on our operations until the rule is final.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018. We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3. See Note 6, Property, Plant, and Equipment, for more information related to these 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.


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We also continue to reduce methane emissions by improving our natural gas distribution systems, and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility distribution systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

We have received final or interim BTA determinations for all applicable generation facilities. In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance expected in the third quarter of 2024.

Steam Electric Effluent Limitation Guidelines

The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters. The two requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater. Although our coal-fueled facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications were still necessary to meet all of the ELG rule requirements. Through 2023, compliance costs associated with the ELG rule required $105 million in capital investment.

In March 2023, the EPA issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on: 1) BATW; 2) FGD wastewater; 3) CCR leachate; and 4) legacy wastewaters. The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater. Under the proposed rule, this new ZLD requirement must be met by a date determined by the permitting authority (the WDNR for WE) that is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029.

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule. Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032. Although the $89 million biological treatment system at ERGS is complete and was placed in service in December 2023 to meet the WPDES permit deadline, the timing of the project's completion did not comply with the deadline proposed by the EPA to qualify for the early adopter status. In addition, we do not believe that the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations.

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

The EPA also proposed requirements for legacy wastewaters and landfill leachate. We have reviewed the proposed requirements to determine potential costs and actions required for our facilities. We submitted comments to the EPA regarding these proposed requirements.


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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, 2024		December 31, 2023
Regulatory assets	$	583.8	$	596.8
Reserves for future environmental remediation	448.9		463.7

Coal Combustion Residuals Rule

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

We are actively engaged with our trade organizations and provided them information to include in their comments to the EPA. The EPA issued a final rule in April 2024, and we are currently evaluating the impact, if any, on our operations. The rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs; however, we expect the cost of any additional remediation would be recovered through future rates.

Enforcement and Litigation Matters

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

Consent Decrees

Wisconsin Public Service Corporation – Weston and Pulliam Power Plants

In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. We continue to work with the EPA on a closeout process for the Consent Decree.


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Joint Ownership Power Plants – Columbia and Edgewater

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

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Three Months Ended March 31
(in millions)	2024		2023
Cash paid for interest, net of amount capitalized	$	158.6	$	107.5
Cash paid (received) for income taxes, net (1)	(83.0)		1.0
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	147.2		123.0
Common stock issued for stock-based compensation plans	6.2		—
Increase in receivables related to insurance proceeds	—		20.7

(1) Cash received for income taxes in 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, 2024		December 31, 2023
Cash and cash equivalents	$	38.9	$	42.9
Restricted cash included in other current assets	43.6		70.1
Restricted cash included in other long-term assets	33.6		52.2
Cash, cash equivalents, and restricted cash	$	116.1	$	165.2

Our restricted cash 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, and WEPCo Environmental Trust.
Cash related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account annually in order to fund future decommissioning.


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NOTE 22—REGULATORY ENVIRONMENT

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

2025 and 2026 Rate Case

On April 12, 2024, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2025 and January 1, 2026. The requests reflected the following:


	WE					WPS					WG
Proposed 2025 rate increase
Electric	$	240.7	million	/	6.9%	$	110.1	million	/	8.5%	N/A
Gas	$	57.5	million	/	10.0%	$	26.8	million	/	6.8%	$	67.7	million	/	8.2%
Steam	$	2.5	million	/	8.4%	N/A					N/A
Proposed 2026 rate increase (1)
Electric	$	177.9	million	/	4.6%	$	64.3	million	/	4.5%	N/A
Gas	$	31.0	million	/	4.6%	$	16.1	million	/	3.7%	$	30.6	million	/	3.3%
Proposed ROE	10.0%					10.0%					10.0%
Proposed common equity component average on a financial basis	53.5%					53.5%					53.5%

(1) The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025.

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

The requested increases in natural gas rates are driven by the companies' ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.

The utilities also proposed retaining their current earnings sharing mechanism. Under the current earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

A decision is expected in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

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

2023 Rate Order

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. PGL did not request an extension of the QIP rider as PGL returned to the traditional rate making process to recover the costs of necessary infrastructure improvements.

On November 16, 2023, the ICC issued final written orders approving base rate increases for PGL and NSG. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:

A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.
An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.


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

As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. In addition, the ICC ordered PGL to pause spending on its SMP until the ICC has a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level. In accordance with the written order, the ICC initiated the proceeding on January 31, 2024.

On December 15, 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. On January 3, 2024, the ICC granted PGL and NSG a limited-scope rehearing. The rehearing is limited to the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system.

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment 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. We anticipate appealing the ICC’s disallowance of PGL's and NSG's capital costs to the Illinois Appellate Court after the rehearing process is complete.

An ICC decision on our limited-scope rehearing is expected by June 1, 2024.

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 requires a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively. These amounts are being refunded over a period of nine months, which began on September 1, 2023. In June 2023, the ICC denied PGL's and NSG's application requesting a rehearing of the ICC's May 2023 order. In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders. Their appeal is still pending.

As of March 31, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2023, 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 March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2022, are still pending. Annual costs included in the rider have ranged from $192 million to $348 million during these open reconciliation years.

As of March 31, 2024, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.


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Minnesota Energy Resources Corporation

2023 Rate Order

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

In November 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers. Final rates went into effect on March 1, 2024.

MERC’s customers are entitled to a refund to the extent the interim rate increase exceeded the final approved rate increase. As of March 31, 2024, MERC had recorded a regulatory liability of $10.8 million for refunds due to customers. These amounts will be refunded to customers during the second quarter of 2024.

Michigan Gas Utilities Corporation

2024 Rate Case

On March 1, 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates by $17.6 million (9.7%). The request reflects a 10.25% ROE and a common equity component average of 50.9%. The proposed natural gas rate increase is primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates over the past few years. The proposed rate increase also includes the expected impacts of the Pipeline and Hazardous Materials Safety Administration's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."

An MPSC decision is anticipated in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

Upper Michigan Energy Resources Corporation

2024 Rate Case

On May 1, 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers by $11.2 million (13.8%). The request reflects a 10.25% ROE and a common equity component average of 50.0%. The proposed rate increase is primarily driven by the construction of the now in-service RICE generation facilities and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates. A reduction of operation and maintenance costs partially offset these impacts.

An MPSC decision is anticipated in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Improvements to Income Tax Disclosures

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


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

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.


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