Item 1. FINANCIAL STATEMENTS

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Item 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)		Three Months Ended					Nine Months Ended
	September 30					September 30
(in millions, except per share amounts)		2024		2023			2024		2023
Operating revenues		$	1,863.5	$	1,957.4		$	6,315.7	$	6,675.5

Operating expenses
Cost of sales		520.8		587.4			1,917.6		2,430.1
Other operation and maintenance		566.8		516.6			1,631.0		1,546.6
Depreciation and amortization		340.5		320.3			1,010.5		939.7
Property and revenue taxes		51.7		61.1			194.7		192.5
Total operating expenses		1,479.8		1,485.4			4,753.8		5,108.9

Operating income		383.7		472.0			1,561.9		1,566.6

Equity in earnings of transmission affiliates		46.7		44.7			138.3		132.1
Other income, net		44.0		41.8			128.7		130.9
Interest expense		204.2		182.5			596.8		533.4
Other expense		(113.5)		(96.0)			(329.8)		(270.4)

Income before income taxes		270.2		376.0			1,232.1		1,296.2
Income tax expense		31.6		60.4			160.9		183.0
Net income		238.6		315.6			1,071.2		1,113.2

Preferred stock dividends of subsidiary		0.3		0.3			0.9		0.9
Net loss attributed to noncontrolling interests		1.8		0.7			3.4		0.9
Net income attributed to common shareholders		$	240.1	$	316.0		$	1,073.7	$	1,113.2

Earnings per share
Basic		$	0.76	$	1.00		$	3.40	$	3.53
Diluted		$	0.76	$	1.00		$	3.40	$	3.52

Weighted average common shares outstanding
Basic		316.2		315.4			315.9		315.4
Diluted		316.5		315.8			316.2		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					Nine Months Ended
	September 30					September 30
(in millions)		2024		2023			2024		2023
Net income		$	238.6	$	315.6		$	1,071.2	$	1,113.2

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)			(0.2)		(0.2)






Comprehensive income		238.5		315.5			1,071.0		1,113.0

Preferred stock dividends of subsidiary		0.3		0.3			0.9		0.9
Comprehensive loss attributed to noncontrolling interests		1.8		0.7			3.4		0.9
Comprehensive income attributed to common shareholders		$	240.0	$	315.9		$	1,073.5	$	1,113.0

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 BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	September 30, 2024		December 31, 2023
Assets
Current assets
Cash and cash equivalents	$	322.5	$	42.9
Accounts receivable and unbilled revenues, net of reserves of $155.0 and $193.5, respectively	1,175.5		1,503.2
Materials, supplies, and inventories	789.9		775.2
Prepaid taxes	124.5		173.9
Other prepayments	50.7		76.8

Other	156.1		223.7
Current assets	2,619.2		2,795.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,442.8 and $11,073.1, respectively	32,852.9		31,581.5
Regulatory assets (September 30, 2024 and December 31, 2023 include $79.1 and $85.9, respectively, related to WEPCo Environmental Trust)	3,346.5		3,249.8
Equity investment in transmission affiliates	2,080.8		2,005.9
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	918.1		870.9
Other	326.2		383.1
Long-term assets	42,577.3		41,144.0
Total assets	$	45,196.5	$	43,939.7

Liabilities and Equity
Current liabilities
Short-term debt	$	597.0	$	2,020.9
Current portion of long-term debt (September 30, 2024 and December 31, 2023 include $9.1 and $9.0, respectively, related to WEPCo Environmental Trust)	1,823.7		1,264.2
Accounts payable	740.7		896.6
Accrued interest	202.4		154.4
Other	645.6		778.7
Current liabilities	4,009.4		5,114.8

Long-term liabilities
Long-term debt (September 30, 2024 and December 31, 2023 include $80.9 and $85.3, respectively, related to WEPCo Environmental Trust)	16,889.2		15,512.8
Deferred income taxes	5,322.2		4,918.5
Deferred revenue, net	339.9		356.4
Regulatory liabilities	3,889.1		3,697.7
Intangible liabilities	554.6		594.8
Environmental remediation liabilities	430.5		463.7
AROs	547.9		374.2
Other	822.5		835.3
Long-term liabilities	28,795.9		26,753.4

Commitments and contingencies (Note 23)

Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 316,354,446 and 315,434,531 shares outstanding, respectively	3.2		3.2
Additional paid in capital	4,191.4		4,115.9
Retained earnings	7,895.3		7,612.8
Accumulated other comprehensive loss	(7.9)		(7.7)
Common shareholders' equity	12,082.0		11,724.2

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	278.8		316.9
Total liabilities and equity	$	45,196.5	$	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)	Nine Months Ended
	September 30
(in millions)	2024		2023
Operating activities
Net income	$	1,071.2	$	1,113.2
Reconciliation to cash provided by operating activities
Depreciation and amortization	1,010.5		939.7
Deferred income taxes and ITCs, net	368.3		155.9
Contributions and payments related to pension and OPEB plans	(11.0)		(13.0)
Equity income in transmission affiliates, net of distributions	(29.3)		(23.1)
Change in –
Accounts receivable and unbilled revenues, net	324.0		600.7
Materials, supplies, and inventories	(14.7)		67.2
Collateral on deposit	47.7		4.0
Amounts recoverable from customers	(34.2)		26.5
Other current assets	81.8		77.8
Accounts payable	(151.7)		(350.6)
Accrued interest	48.0		82.4
Other current liabilities	(75.2)		(30.1)
Other, net	(5.4)		(112.2)
Net cash provided by operating activities	2,630.0		2,538.4

Investing activities
Capital expenditures	(1,934.7)		(1,729.5)
Acquisition of West Riverside	(97.9)		(95.3)
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)
Acquisition of Red Barn	—		(143.8)
Capital contributions to transmission affiliates	(45.5)		(51.5)
Proceeds from the sale of assets	1.2		30.4
Proceeds from the sale of investments held in rabbi trust	14.8		10.4
Payments for ATC's construction costs that will be reimbursed	(0.7)		(19.5)
Other, net	9.6		(4.9)
Net cash used in investing activities	(2,053.2)		(2,771.7)

Financing activities
Exercise of stock options	13.4		3.0
Issuance of common stock	51.0		—
Purchase of common stock	(3.2)		(10.7)
Dividends paid on common stock	(791.2)		(738.1)
Issuance of long-term debt	2,672.4		2,050.0
Retirement of long-term debt	(837.5)		(996.0)
Change in commercial paper	(1,424.8)		(98.2)
Purchase of additional ownership interest in Samson I from noncontrolling interest	(28.1)		—
Payments for debt extinguishment and issuance costs	(30.7)		(13.0)
Other, net	(2.3)		(4.5)
Net cash provided by (used in) financing activities	(381.0)		192.5

Net change in cash, cash equivalents, and restricted cash	195.8		(40.8)
Cash, cash equivalents, and restricted cash at beginning of period	165.2		182.2
Cash, cash equivalents, and restricted cash at end of period	$	361.0	$	141.4

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 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
Net income attributed to common shareholders	—		—		211.3		—		211.3		—		—		211.3
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(1.6)		(1.6)

Issuance of common stock	—		19.0		—		—		19.0		—		—		19.0
Common stock dividends of $0.8350 per share	—		—		(263.7)		—		(263.7)		—		—		(263.7)
Exercise of stock options	—		1.0		—		—		1.0		—		—		1.0
Purchase of common stock	—		(1.2)		—		—		(1.2)		—		—		(1.2)

Distributions to noncontrolling interests	—		—		—		—		—		—		(0.3)		(0.3)
Stock-based compensation and other	—		3.8		—		—		3.8		—		—		3.8
Balance at June 30, 2024	$	3.2	$	4,168.3	$	7,919.2	$	(7.8)	$	12,082.9	$	30.4	$	281.1	$	12,394.4
Net income attributed to common shareholders	—		—		240.1		—		240.1		—		—		240.1
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(1.8)		(1.8)
Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Issuance of common stock	—		12.8		—		—		12.8		—		—		12.8
Common stock dividends of $0.8350 per share	—		—		(264.0)		—		(264.0)		—		—		(264.0)
Exercise of stock options	—		8.7		—		—		8.7		—		—		8.7

Distributions to noncontrolling interests	—		—		—		—		—		—		(0.5)		(0.5)
Stock-based compensation and other	—		1.6		—		—		1.6		—		—		1.6
Balance at September 30, 2024	$	3.2	$	4,191.4	$	7,895.3	$	(7.9)	$	12,082.0	$	30.4	$	278.8	$	12,391.2


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	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
Net income attributed to common shareholders	—		—		289.7		—		289.7		—		—		289.7
Common stock dividends of $0.7800 per share	—		—		(246.0)		—		(246.0)		—		—		(246.0)
Exercise of stock options	—		1.4		—		—		1.4		—		—		1.4
Purchase of common stock	—		(2.6)		—		—		(2.6)		—		—		(2.6)
Distributions to noncontrolling interests	—		—		—		—		—		—		(1.0)		(1.0)
Stock-based compensation and other	—		2.3		—		—		2.3		—		(0.1)		2.2
Balance at June 30, 2023	$	3.2	$	4,114.7	$	7,570.4	$	(6.9)	$	11,681.4	$	30.4	$	319.6	$	12,031.4
Net income attributed to common shareholders	—		—		316.0		—		316.0		—		—		316.0
Net loss attributed to noncontrolling interests	—		—		—		—		—		—		(0.7)		(0.7)
Other comprehensive loss	—		—		—		(0.1)		(0.1)		—		—		(0.1)
Common stock dividends of $0.7800 per share	—		—		(246.0)		—		(246.0)		—		—		(246.0)
Exercise of stock options	—		0.7		—		—		0.7		—		—		0.7
Purchase of common stock	—		(1.2)		—		—		(1.2)		—		—		(1.2)
Distributions to noncontrolling interests	—		—		—		—		—		—		(2.0)		(2.0)
Stock-based compensation and other	—		2.2		—		—		2.2		—		—		2.2
Balance at September 30, 2023	$	3.2	$	4,116.4	$	7,640.4	$	(7.0)	$	11,753.0	$	30.4	$	316.9	$	12,100.3

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)

September 30, 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 20, 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 and nine months ended September 30, 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 19, Goodwill and Intangibles, for more information.

Acquisition of a Solar Generation Facility in Ohio

In October 2024, WECI signed an agreement to acquire a 90% ownership interest in Hardin III, a 250 MW solar generating facility under construction in Hardin County, Ohio for $407.3 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 first quarter of 2025, at which time the transaction is expected to close. Hardin III is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

Acquisitions of Electric Generation Facilities in Wisconsin

In May 2024, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity for $97.9 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to the acquisition, WPS received


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approval to transfer its ownership interest rights to WE. Including this acquisition, WE owns 200 MWs, or 27.5%, of West Riverside at a total cost of $193.2 million.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $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 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. 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. In May 2024, WECI signed an agreement to acquire an additional 10% ownership interest in Maple Flats, bringing the total acquisition price to approximately $431 million.

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.

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, as a result of storm damage sustained in May 2024, commercial operation is now expected to begin by the end 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.

NOTE 3—DISPOSITION

Wisconsin Segment

Sale of Certain Real Estate by Wisconsin Electric Power Company

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


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NOTE 4—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 September 30, 2024
Electric	$	1,422.2	$	—	$	—	$	1,422.2	$	—	$	—	$	—		$	1,422.2
Natural gas	163.7		168.0		48.4		380.1		10.4		—		(9.6)			380.9
Total regulated revenues	1,585.9		168.0		48.4		1,802.3		10.4		—		(9.6)			1,803.1
Other non-utility revenues	—		—		5.1		5.1		47.7		—		(1.6)			51.2
Total revenues from contracts with customers	1,585.9		168.0		53.5		1,807.4		58.1		—		(11.2)			1,854.3
Other operating revenues	4.1		5.6		(0.5)		9.2		105.0		—		(105.0)		(1)	9.2
Total operating revenues	$	1,590.0	$	173.6	$	53.0	$	1,816.6	$	163.1	$	—	$	(116.2)		$	1,863.5


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Three Months Ended September 30, 2023
Electric	$	1,457.8	$	—	$	—	$	1,457.8	$	—	$	—	$	—		$	1,457.8
Natural gas	159.5		234.8		42.5		436.8		12.9		—		(12.3)			437.4
Total regulated revenues	1,617.3		234.8		42.5		1,894.6		12.9		—		(12.3)			1,895.2
Other non-utility revenues	—		—		4.9		4.9		45.6		—		(1.7)			48.8
Total revenues from contracts with customers	1,617.3		234.8		47.4		1,899.5		58.5		—		(14.0)			1,944.0
Other operating revenues	4.7		8.5		0.2		13.4		101.3		—		(101.3)		(1)	13.4
Total operating revenues	$	1,622.0	$	243.3	$	47.6	$	1,912.9	$	159.8	$	—	$	(115.3)		$	1,957.4


(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended September 30, 2024
Electric	$	3,756.0	$	—	$	—	$	3,756.0	$	—	$	—	$	—		$	3,756.0
Natural gas	964.8		1,027.3		285.4		2,277.5		36.3		—		(34.6)			2,279.2
Total regulated revenues	4,720.8		1,027.3		285.4		6,033.5		36.3		—		(34.6)			6,035.2
Other non-utility revenues	—		—		15.0		15.0		159.1		—		(7.1)			167.0
Total revenues from contracts with customers	4,720.8		1,027.3		300.4		6,048.5		195.4		—		(41.7)			6,202.2
Other operating revenues	16.2		89.1		8.2		113.5		314.2		—		(314.2)		(1)	113.5
Total operating revenues	$	4,737.0	$	1,116.4	$	308.6	$	6,162.0	$	509.6	$	—	$	(355.9)		$	6,315.7


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(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations			WEC Energy Group Consolidated
Nine Months Ended September 30, 2023
Electric	$	3,840.1	$	—	$	—	$	3,840.1	$	—	$	—	$	—		$	3,840.1
Natural gas	1,183.8		1,072.5		364.4		2,620.7		48.3		—		(47.0)			2,622.0
Total regulated revenues	5,023.9		1,072.5		364.4		6,460.8		48.3		—		(47.0)			6,462.1
Other non-utility revenues	—		—		14.8		14.8		142.4		—		(7.1)			150.1
Total revenues from contracts with customers	5,023.9		1,072.5		379.2		6,475.6		190.7		—		(54.1)			6,612.2
Other operating revenues	18.9		44.0		0.3		63.2		304.3		0.1		(304.3)		(1)	63.3
Total operating revenues	$	5,042.8	$	1,116.5	$	379.5	$	6,538.8	$	495.0	$	0.1	$	(358.4)		$	6,675.5

(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.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Residential	$	592.4	$	584.9	$	1,534.2	$	1,530.5
Small commercial and industrial	457.9		462.2		1,233.2		1,257.3
Large commercial and industrial	284.1		289.9		726.6		759.6
Other	7.2		7.2		22.3		22.4
Total retail revenues	1,341.6		1,344.2		3,516.3		3,569.8
Wholesale	27.0		31.9		80.3		96.5
Resale	46.0		75.3		128.9		147.8
Steam	2.2		2.6		16.5		18.2
Other utility revenues	5.4		3.8		14.0		7.8
Total electric utility operating revenues	$	1,422.2	$	1,457.8	$	3,756.0	$	3,840.1

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 September 30, 2024
Residential	$	76.8	$	114.0	$	24.5	$	215.3
Commercial and industrial	30.8		32.0		10.7		73.5
Total retail revenues	107.6		146.0		35.2		288.8
Transportation	19.3		44.7		6.2		70.2
Other utility revenues (1)	36.8		(22.7)		7.0		21.1
Total natural gas utility operating revenues	$	163.7	$	168.0	$	48.4	$	380.1


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(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2023
Residential	$	81.7	$	148.3	$	27.5	$	257.5
Commercial and industrial	34.0		30.8		12.1		76.9
Total retail revenues	115.7		179.1		39.6		334.4
Transportation	18.2		41.9		6.3		66.4
Other utility revenues (1)	25.6		13.8		(3.4)		36.0
Total natural gas utility operating revenues	$	159.5	$	234.8	$	42.5	$	436.8


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2024
Residential	$	599.3	$	651.1	$	166.0	$	1,416.4
Commercial and industrial	275.8		180.5		80.9		537.2
Total retail revenues	875.1		831.6		246.9		1,953.6
Transportation	70.4		187.3		24.0		281.7
Other utility revenues (1)	19.3		8.4		14.5		42.2
Total natural gas utility operating revenues	$	964.8	$	1,027.3	$	285.4	$	2,277.5


(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2023
Residential	$	756.6	$	697.2	$	245.6	$	1,699.4
Commercial and industrial	379.8		191.1		129.8		700.7
Total retail revenues	1,136.4		888.3		375.4		2,400.1
Transportation	67.5		167.3		23.4		258.2
Other utility revenues (1)	(20.1)		16.9		(34.4)		(37.6)
Total natural gas utility operating revenues	$	1,183.8	$	1,072.5	$	364.4	$	2,620.7

(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.

Other Non-Utility Operating Revenues

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Wind generation revenues	$	40.0	$	38.2	$	133.8	$	117.8
We Power revenues (1)	6.1		5.7		18.2		17.5
Appliance service revenues	5.1		4.9		15.0		14.8


Total other non-utility operating revenues	$	51.2	$	48.8	$	167.0	$	150.1

(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.


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Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Late payment charges	$	10.4	$	12.4	$	39.1	$	45.8
Alternative revenues (1)	(1.7)		—		71.1		13.9
Other	0.5		1.0		3.3		3.6
Total other operating revenues	$	9.2	$	13.4	$	113.5	$	63.3

(1)Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

NOTE 5—CREDIT LOSSES

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

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

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

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


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We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 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
September 30, 2024
Accounts receivable and unbilled revenues	$	937.8		$	326.8		$	32.9		$	1,297.5		$	26.7		$	6.3		$	1,330.5
Allowance for credit losses	63.9			86.9			4.2			155.0			—			—			155.0
Accounts receivable and unbilled revenues, net (1)	$	873.9		$	239.9		$	28.7		$	1,142.5		$	26.7		$	6.3		$	1,175.5

Total accounts receivable, net – past due greater than 90 days (1)	$	52.5		$	50.2		$	4.0		$	106.7		$	—		$	—		$	106.7
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	93.6		%	100.0		%	—		%	93.1		%	—		%	—		%	93.1		%


(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 September 30, 2024, $670.1 million, or 57.0%, 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 September 30, 2024 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at July 1, 2024	$	68.7	$	93.2	$	5.0	$	166.9
Provision for credit losses	12.6		11.5		(0.3)		23.8
Provision for credit losses deferred for future recovery or refund	3.8		(11.0)		—		(7.2)
Write-offs charged against the allowance	(30.8)		(12.9)		(2.5)		(46.2)
Recoveries of amounts previously written off	9.6		6.1		2.0		17.7
Balance at September 30, 2024	$	63.9	$	86.9	$	4.2	$	155.0


Nine Months Ended September 30, 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	36.2		38.8		(1.6)		73.4
Provision for credit losses deferred for future recovery or refund	20.9		(17.2)		—		3.7
Write-offs charged against the allowance	(102.3)		(63.2)		(4.9)		(170.4)
Recoveries of amounts previously written off	31.7		18.8		4.3		54.8
Balance at September 30, 2024	$	63.9	$	86.9	$	4.2	$	155.0


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On a consolidated basis, there was a $38.5 million decrease in the allowance for credit losses at September 30, 2024, compared to January 1, 2024, largely driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. 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. Also contributing to the decrease in the allowance for credit losses, we have seen lower required reserve percentages at many of our regulated utilities as a result of an improvement in loss rates. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions in the first half of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.


Three Months Ended September 30, 2023 (in millions)	Wisconsin		Illinois		Other States		WEC Energy Group Consolidated
Balance at July 1, 2023	$	76.4	$	97.0	$	5.3	$	178.7
Provision for credit losses	10.2		4.0		0.6		14.8
Provision for credit losses deferred for future recovery or refund	9.8		7.1		—		16.9
Write-offs charged against the allowance	(31.8)		(14.4)		(1.5)		(47.7)
Recoveries of amounts previously written off	7.4		6.3		0.4		14.1
Balance at September 30, 2023	$	72.0	$	100.0	$	4.8	$	176.8


Nine Months Ended September 30, 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	28.1		17.3		1.5		46.9
Provision for credit losses deferred for future recovery or refund	26.3		13.8		—		40.1
Write-offs charged against the allowance	(89.8)		(58.7)		(4.2)		(152.7)
Recoveries of amounts previously written off	25.4		16.6		1.2		43.2
Balance at September 30, 2023	$	72.0	$	100.0	$	4.8	$	176.8

On a consolidated basis, there was a $22.5 million decrease in the allowance for credit losses at September 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the end of the winter moratorium. In addition, lower energy costs driven by lower natural gas prices contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.


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NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 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)	September 30, 2024		December 31, 2023
Regulatory assets
Plant retirement related items (1)	$	814.3	$	646.2
Pension and OPEB costs	721.1		731.7
Environmental remediation costs	565.8		596.8
Income tax related items	438.9		449.9
AROs	169.3		162.0
Uncollectible expense	123.4		127.7
System support resource	105.5		113.2
Decoupling (2)	100.5		27.3
Securitization	79.1		85.9
Bluewater	54.8		45.3
Derivatives	50.6		130.3
Energy efficiency programs	32.4		33.9
Other, net	149.9		124.5
Total regulatory assets	$	3,405.6	$	3,274.7

Balance sheet presentation
Other current assets	$	59.1	$	24.9
Regulatory assets	3,346.5		3,249.8
Total regulatory assets	$	3,405.6	$	3,274.7

(1) At September 30, 2024, plant retirement related items included $115.0 million of capitalized retirement costs related to the new EPA CCR Rule that was enacted in April 2024. See Note 23, Commitments and Contingencies, for more information.

(2) PGL, NSG, and MERC have decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover the differences between actual and authorized margins for certain customer classes.


(in millions)	September 30, 2024		December 31, 2023
Regulatory liabilities
Income tax related items	$	1,838.0	$	1,901.8
Removal costs	1,429.5		1,329.9
Pension and OPEB benefits	301.2		299.2
Energy costs refundable through rate adjustments	126.0		72.4
Uncollectible expense	39.2		21.2
Paris (1)	31.8		—
Derivatives	29.1		19.2
Electric transmission costs	20.5		30.3
Energy efficiency programs	16.7		17.2
Other, net	89.6		54.0
Total regulatory liabilities	$	3,921.6	$	3,745.2

Balance sheet presentation
Other current liabilities	$	32.5	$	47.5
Regulatory liabilities	3,889.1		3,697.7
Total regulatory liabilities	$	3,921.6	$	3,745.2

(1) In accordance with our Wisconsin rate orders approved by the PSCW in December 2023, WE and WPS are deferring to a future rate proceeding the incremental revenue requirement impact associated with the change to the in-service date of Paris.


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Oak Creek Power Plant Units 5-6

In May 2024, OCPP Units 5 and 6 were retired. Due to the retirement of these units and the determination that recovery was probable, their net book value of $76.8 million at September 30, 2024 was classified as a regulatory asset. In addition, a $43.8 million cost of removal reserve related to the units continued to be classified as a regulatory liability at September 30, 2024. Not included in these amounts was $9.0 million of deferred tax liabilities previously recorded for the retired units. Effective with its rate order issued by the PSCW in December 2022, WE received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. WE also intends to request FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for Koshkonong and have acquired 200 MWs of capacity in West Riverside, and have acquired additional projects. See Note 2, Acquisitions, for more information on the West Riverside acquisitions. OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 7 and 8 was $666.7 million at September 30, 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. The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $252.7 million at September 30, 2024, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson I Solar Energy Center LLC – Storm Damage

During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage. As of September 30, 2024, we recognized an impairment of $5.4 million related to storm damage, which was offset by a $5.4 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from these storms.

NOTE 8—ASSET RETIREMENT OBLIGATIONS

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

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


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The following table shows changes to our AROs:


(in millions)	2024			2023
Balance at January 1	$	374.2		$	479.3
Accretion	13.0			12.8
Additions	165.9		(1)	16.6		(2)

Liabilities settled	(5.2)			(3.2)
Balance at September 30	$	547.9		$	505.5

(1) AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 23, Commitments and Contingencies, for more information.

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

NOTE 9—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 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)						294,990
Restricted shares (2)						108,484
Performance units						205,051

(1)Stock options awarded had a weighted-average exercise price of $84.92 and a weighted-average grant date fair value of $16.19 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $84.97 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 compensation 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 and nine months ended September 30, 2023.

On August 6, 2024, we entered into an EDA, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $1.5 billion through an at-the-market offering program, which includes an equity forward sales component. We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement. The EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) August 31, 2027. Actual sales of common stock under the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding. Any shares offered and sold will be done pursuant to our registration statement on Form S-3 filed with the SEC on


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August 5, 2024 and the related prospectus supplement. As of September 30, 2024, we have not issued any shares of common stock under the EDA, and we have not entered into any forward sale agreements.

We had the following changes to our outstanding common stock during the three and nine months ended September 30, 2024:


	Three Months Ended September 30, 2024	Nine Months Ended September 30, 2024
Common stock shares outstanding at beginning of period	316,079,401	315,434,531
Shares issued:
Stock-based compensation	137,936	300,602
401(k)	38,400	285,000
Stock investment plan	98,709	334,313
Common stock shares outstanding at end of period	316,354,446	316,354,446

On October 17, 2024, our Board of Directors declared a quarterly cash dividend of $0.835 per share, payable on December 1, 2024, to shareholders of record on November 14, 2024.

NOTE 10—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)	September 30, 2024			December 31, 2023
Commercial paper
Amount outstanding	$	592.4		$	2,017.2
Weighted-average interest rate on amounts outstanding	4.94		%	5.49		%
Operating expense loans
Amount outstanding (1)	$	4.6		$	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 nine months ended September 30, 2024 was $1,478.4 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	September 30, 2024
WEC Energy Group	September 2026	$	1,500.0
WEC Energy Group	October 2024 (1)	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		592.4
Available capacity under existing agreements		$	2,705.3

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


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NOTE 11—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. Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper.

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.

Convertible Senior Notes

In the second quarter of 2024, we issued $862.5 million of 2027 Notes and $862.5 million of 2029 Notes. The 2027 Notes and 2029 Notes are senior unsecured obligations and bear interest at an annual rate of 4.375%, payable semiannually beginning on December 1, 2024. Proceeds from the offerings were used to repay short-term debt and for general corporate purposes.

The 2027 Notes will mature on June 1, 2027, and the 2029 Notes will mature on June 1, 2029, unless earlier converted or repurchased in accordance with their terms, or in the case of the 2029 Notes, redeemed by us. No sinking fund is provided for either series of the notes. Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2027 or 2029 Notes. We may not redeem the 2027 Notes prior to their maturity date. We may redeem for cash all or part of the 2029 Notes, at our option, on or after June 1, 2027 and on or before the 41st scheduled trading day immediately preceding their maturity date, if the last reported sale price per share of our common stock has been at least 130% of the conversion price of the 2029 Notes then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period. Any redemptions or fundamental change repurchases of the 2027 Notes or 2029 Notes will be at a price equal to 100% of the principal amount, plus accrued and unpaid interest.

Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2027, in the case of the 2027 Notes, and March 1, 2029, in the case of the 2029 Notes, only under the following circumstances:

During any calendar quarter commencing after the calendar quarter ending on September 30, 2024, (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price of such series of notes on each applicable trading day;
During the five consecutive business day period immediately after any ten consecutive trading day period (measurement period) in which the trading price per $1,000 principal amount of notes of such series for each trading day of the measurement period was less than 98% of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;
Upon the occurrence of specified corporate events, as defined in the related indenture;
In the case of the 2029 Notes only, if we call any of the 2029 Notes for redemption, at any time prior to the close of business on the second scheduled trading day prior to the redemption date, but only with respect to the 2029 Notes called (or deemed called) for redemption.

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

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


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The initial conversion rate for both the 2027 Notes and 2029 Notes is 10.1243 shares of common stock per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $98.77 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

As of September 30, 2024, none of the conditions allowing holders to convert their notes were met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes and 2029 Notes were accounted for in their entirety as a liability on our balance sheet. The following is a summary of our convertible debt instruments as of September 30, 2024:


(in millions)	Principal Amount		Unamortized Debt Issuance Costs		Net Carrying Amount		Fair Value Amount (1)
2027 Notes	$	862.5	$	(8.8)	$	853.7	$	936.3
2029 Notes	862.5		(9.3)		853.2		954.7

(1) The fair values are categorized in Level 2 of the fair value hierarchy. See Note 15, Fair Value Measurements, for more information on the levels of the fair value hierarchy.

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


(in millions)	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
2027 Notes
Contractual interest expense	$	9.4	$	12.9
Amortization of debt issuance costs	0.8		1.1
Total interest expense – 2027 Notes	10.2		14.0

2029 Notes
Contractual interest expense	9.4		12.9
Amortization of debt issuance costs	0.5		0.7
Total interest expense – 2029 Notes	$	9.9	$	13.6

Potentially dilutive common shares issuable upon conversion of the 2027 Notes and 2029 Notes are determined using the if-converted method for calculating diluted earnings per share. As of September 30, 2024, there were no shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes included in our diluted earnings per share calculation as the impact was anti-dilutive.

Wisconsin Electric Power Company

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

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

Wisconsin Gas LLC

In October 2024, WG issued $100.0 million of 4.86% Debentures due November 1, 2029 and $100 million of 5.18% Debentures due November 1, 2034, and used the net proceeds to repay short-term debt.

Michigan Gas Utilities Corporation

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


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Bluewater Gas Storage, LLC

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

NOTE 12—LEASES

In June 2024, UMERC entered into an agreement to acquire and construct Renegade, a utility-scale solar-powered electric generating facility in Delta and Marquette counties, Michigan. Commercial operation of the project is targeted at the end of 2026. Related to its investment in Renegade, UMERC entered into several land leases that commenced in the second quarter of 2024.

In July 2024, WE and WPS partnered with an unaffiliated utility to acquire and construct Koshkonong, a utility-scale solar-powered electric generating facility located in Dane County, Wisconsin. Commercial operation of the project is targeted at the end of 2026. Related to their investment in Koshkonong, WE and WPS, along with their unaffiliated utility partner, entered into several land leases that commenced in the third quarter of 2024.

The land leases entered into related to the Renegade and Koshkonong generating facilities each have an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, these land leases are being amortized over the extended term of the leases. Once Renegade and Koshkonong achieve commercial operation, the lease liabilities will be remeasured to reflect the final total acres being leased. We expect to recover the lease payments through rates. Our total obligation under these land-related finance leases was $120.0 million at September 30, 2024, and was included in long-term debt on our balance sheet. Our finance lease right of use assets were $119.0 million as of September 30, 2024, and were included in property, plant, and equipment on our balance sheet. Our weighted-average discount rate for these land-related finance leases was 6.02%. We used an estimate of the fully collateralized incremental borrowing rate based upon information available for similarly rated companies in determining the present value of lease payments.

Future minimum lease payments and the corresponding present value of our net minimum lease payments under these land-related finance leases as of September 30, 2024, were as follows:


(in millions)
Three Months Ended December 31, 2024	$	—
2025	2.1
2026	2.3
2027	6.2
2028	6.3
2029	6.4
Thereafter	500.6
Total minimum lease payments	523.9
Less: Interest	(403.9)
Present value of minimum lease payments	120.0
Less: Short-term lease liabilities	—
Long-term lease liabilities	$	120.0

NOTE 13—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:


(in millions)	September 30, 2024		December 31, 2023
Materials and supplies	$	369.6	$	320.0
Natural gas in storage	335.0		327.8
Fossil fuel	85.3		127.4
Total	$	789.9	$	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 September 30, 2024, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

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 14—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 September 30, 2024				Three Months Ended September 30, 2023
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	57.0	21.0	%	$	79.0	21.0	%
State income taxes net of federal tax benefit	16.9		6.2	%	23.2		6.2	%
PTCs, net	(33.7)		(12.4)	%	(30.2)		(8.0)	%
Federal excess deferred tax amortization	(5.8)		(2.1)	%	(8.5)		(2.3)	%



Other, net	(2.8)		(1.0)	%	(3.1)		(0.8)	%
Total income tax expense	$	31.6	11.7	%	$	60.4	16.1	%

	Nine Months Ended September 30, 2024				Nine Months Ended September 30, 2023
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	259.2	21.0	%	$	272.2	21.0	%
State income taxes net of federal tax benefit	75.9		6.2	%	80.0		6.2	%
PTCs, net	(143.9)		(11.7)	%	(130.3)		(10.1)	%
Federal excess deferred tax amortization	(26.1)		(2.1)	%	(28.9)		(2.2)	%



Other, net	(4.2)		(0.3)	%	(10.0)		(0.8)	%
Total income tax expense	$	160.9	13.1	%	$	183.0	14.1	%

The effective tax rates for the three and nine months ended September 30, 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 lines 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 and May 2024, under this transferability provision, we entered into agreements to sell substantially all of the PTCs we generated in 2023 and substantially all of the PTCs expected to be generated in 2024 to third parties. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return, which increased our deferred tax liabilities. We are still evaluating how this new guidance can be adopted by our remaining utilities and plan to adopt the guidance for them on a future tax return.


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NOTE 15—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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:


	September 30, 2024
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	6.6	$	11.7	$	—	$	18.3
FTRs and TCRs	—		—		12.0		12.0

Total derivative assets	$	6.6	$	11.7	$	12.0	$	30.3

Investments held in rabbi trust	$	50.8	$	—	$	—	$	50.8

Derivative liabilities
Natural gas contracts	$	23.5	$	20.3	$	—	$	43.8


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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. For the three months ended September 30, 2024, we recorded $2.7 million of net unrealized gains in earnings related to the investments held at the end of the period, compared with $1.7 million of net unrealized losses recorded during the same quarter in 2023. During the nine months ended September 30, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $7.9 million and $4.7 million, respectively.

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Balance at the beginning of the period	$	20.8	$	16.8	$	7.2	$	7.8
Purchases	0.7		0.4		27.5		19.9
Net realized and unrealized gains (losses) included in earnings (1)	0.5		0.1		(0.5)		(0.4)
Settlements	(10.0)		(6.0)		(22.2)		(16.0)
Balance at the end of the period	$	12.0	$	11.3	$	12.0	$	11.3
Net unrealized gains included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)	$	0.2	$	0.1	$	0.1	$	0.1

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

Fair Value of Financial Instruments

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


	September 30, 2024				December 31, 2023
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	22.4	$	30.4	$	21.4
Long-term debt, including current portion (1)	18,445.2		17,986.4		16,631.1		15,564.3

(1)The carrying amount of long-term debt excludes finance lease obligations of $267.7 million and $145.9 million at September 30, 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 16—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.


	September 30, 2024				December 31, 2023
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	17.5	$	41.3	$	10.4	$	78.1
FTRs and TCRs	12.0		—		7.2		—
Coal contracts	—		—		0.3		10.9
Total current	29.5		41.3		17.9		89.0

Long-term
Natural gas contracts	0.8		2.5		0.1		8.0
Coal contracts	—		—		—		9.4
Total long-term	0.8		2.5		0.1		17.4
Total	$	30.3	$	43.8	$	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 September 30, 2024			Three Months Ended September 30, 2023
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	38.6 Dth	$	(24.0)	37.8 Dth	$	(56.3)
FTRs and TCRs	7.9 MWh	4.0		8.1 MWh	21.9
Total		$	(20.0)		$	(34.4)

	Nine Months Ended September 30, 2024			Nine Months Ended September 30, 2023
(in millions)	Volumes	Gains (Losses)		Volumes	Gains (Losses)
Natural gas contracts	154.5 Dth	$	(110.7)	144.2 Dth	$	(200.7)
FTRs and TCRs	23.1 MWh	7.6		22.9 MWh	26.4
Total		$	(103.1)		$	(174.3)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2024 and December 31, 2023, we had posted cash collateral of $52.6 million and $100.3 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2024, we had also received cash collateral of $0.5 million. This amount was recorded on our balance sheet in other current liabilities.


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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:


	September 30, 2024					December 31, 2023
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	30.3	$	43.8		$	18.0	$	106.4
Gross amount not offset on the balance sheet	(7.4)		(24.5)		(1)	(3.1)		(71.0)		(2)
Net amount	$	22.9	$	19.3		$	14.9	$	35.4

(1)Includes cash collateral posted of $17.1 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 and nine months ended September 30, 2024 and 2023 were not significant. At September 30, 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 17—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at September 30, 2024			Expiration

(in millions)			Less Than 1 Year			1 to 3 Years			Over 3 Years
Standby letters of credit (1)	$	136.3		$	19.7		$	—		$	116.6
Surety bonds (2)	34.0			33.9			0.1			—
Other guarantees (3)	11.7			—			—			11.7
Total guarantees	$	182.0		$	53.6		$	0.1		$	128.3

(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 18—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 September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Service cost	$	6.1	$	6.0	$	18.2	$	18.0
Interest cost	29.2		30.5		87.5		91.7
Expected return on plan assets	(45.5)		(46.8)		(136.6)		(140.6)
Loss on plan settlement	0.7		—		0.7		—
Amortization of prior service cost (credit)	(0.1)		—		(0.1)		0.1
Amortization of net actuarial loss	14.9		8.1		44.6		24.8
Net periodic benefit cost (credit)	$	5.3	$	(2.2)	$	14.3	$	(6.0)


	OPEB Benefits
	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Service cost	$	2.7	$	2.4	$	8.1	$	7.3
Interest cost	5.6		5.4		17.0		16.2
Expected return on plan assets	(13.2)		(13.3)		(39.5)		(39.8)

Amortization of prior service credit	(3.3)		(3.7)		(10.1)		(11.1)
Amortization of net actuarial gain	(1.9)		(3.0)		(5.7)		(9.2)
Net periodic benefit credit	$	(10.1)	$	(12.2)	$	(30.2)	$	(36.6)

During the nine months ended September 30, 2024, we made contributions and payments of $10.0 million related to our pension plans and $1.0 million related to our OPEB plans. We expect to make contributions and payments of $3.3 million related to our pension plans and $1.1 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 September 30, 2024, we recorded a $20.3 million regulatory asset for pension costs and a $32.4 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

NOTE 19—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 September 30, 2024. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 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 September 30, 2024.

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


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Intangible Assets

At both September 30, 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.

Intangible Liabilities

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


	September 30, 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	$	(106.1)	$	547.8	$	653.9	$	(66.6)	$	587.3
Proxy revenue swap (2)	7.2		(4.0)		3.2		7.2		(3.5)		3.7
Interconnection agreements (3)	4.7		(1.1)		3.6		4.7		(0.9)		3.8
Total intangible liabilities	$	665.8	$	(111.2)	$	554.6	$	665.8	$	(71.0)	$	594.8

(1) Represents PPAs related to the acquisition of Blooming Grove, 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 February 2029. The remaining useful life of the proxy revenue swap is four years.

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

Amortization related to these intangible liabilities for the three and nine months ended September 30, 2024, was $13.4 million and $40.2 million, respectively. Amortization for the three and nine months ended September 30, 2023, was $13.4 million and $37.2 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 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


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NOTE 20—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 September 30, 2024
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	2,029.7	$	26.1	$	2,055.8
Add: Earnings from equity method investment	46.1		0.6		46.7
Add: Capital contributions	15.2		—		15.2
Less: Distributions	37.0		—		37.0

Add: Other	0.1		—		0.1
Balance at end of period	$	2,054.1	$	26.7	$	2,080.8

	Three Months Ended September 30, 2023
(in millions)	ATC		ATC Holdco		Total
Balance at beginning of period	$	1,931.8	$	24.1	$	1,955.9
Add: Earnings from equity method investment	44.2		0.5		44.7
Add: Capital contributions	18.2		—		18.2
Less: Distributions	35.0		—		35.0


Balance at end of period	$	1,959.2	$	24.6	$	1,983.8

	Nine Months Ended September 30, 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	136.7		1.6		138.3
Add: Capital contributions	45.5		—		45.5
Less: Distributions	109.0		—		109.0
Add: Other	0.1		—		0.1
Balance at end of period	$	2,054.1	$	26.7	$	2,080.8

	Nine Months Ended September 30, 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	130.2		1.9		132.1
Add: Capital contributions	51.5		—		51.5
Less: Distributions	107.1		1.9		109.0


Balance at end of period	$	1,959.2	$	24.6	$	1,983.8

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

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


	Three Months Ended September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Charges to ATC for services and construction	$	4.5	$	4.5	$	15.5	$	12.3
Charges from ATC for network transmission services	103.4		94.3		309.9		283.1


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


(in millions)	September 30, 2024		December 31, 2023
Accounts receivable for services provided to ATC	$	2.1	$	1.6

Accounts payable for services received from ATC	50.0		49.9
Amounts due from ATC for transmission infrastructure upgrades (1)	45.8		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 September 30				Nine Months Ended September 30
(in millions)	2024		2023		2024		2023
Income statement data
Operating revenues	$	221.4	$	206.2	$	651.6	$	610.4
Operating expenses	110.1		102.8		324.1		303.4
Other expense, net	36.4		32.9		107.4		98.3
Net income	$	74.9	$	70.5	$	220.1	$	208.7


(in millions)	September 30, 2024		December 31, 2023
Balance sheet data
Current assets	$	130.0	$	115.2
Noncurrent assets	6,660.4		6,337.0
Total assets	$	6,790.4	$	6,452.2

Current liabilities	$	525.7	$	495.9
Long-term debt	2,933.9		2,736.0
Other noncurrent liabilities	573.5		585.2
Members' equity	2,757.3		2,635.1
Total liabilities and members' equity	$	6,790.4	$	6,452.2

NOTE 21—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 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.
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 and anticipated future WECI acquisitions.


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

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 and nine months ended September 30, 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 September 30, 2024
External revenues	$	1,590.0	$	173.6	$	53.0	$	1,816.6	$	—	$	46.9	$	—	$	—	$	1,863.5
Intersegment revenues	—		—		—		—		—		116.2		—		(116.2)		—
Other operation and maintenance	403.5		126.5		22.6		552.6		—		19.1		(3.3)		(1.6)		566.8
Depreciation and amortization	232.4		63.9		12.0		308.3		—		49.2		5.6		(22.6)		340.5
Equity in earnings of transmission affiliates	—		—		—		—		46.7		—		—		—		46.7
Interest expense	160.3		22.3		4.1		186.7		4.8		23.4		79.0		(89.7)		204.2
Income tax expense (benefit)	63.3		(19.0)		(1.3)		43.0		10.2		(16.0)		(5.6)		—		31.6
Net income (loss)	238.1		(48.6)		(3.7)		185.8		31.7		83.2		(62.1)		—		238.6
Net income (loss) attributed to common shareholders	237.8		(48.6)		(3.7)		185.5		31.7		85.0		(62.1)		—		240.1


	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 September 30, 2023
External revenues	$	1,622.0	$	243.3	$	47.6	$	1,912.9	$	—	$	44.5	$	—	$	—	$	1,957.4
Intersegment revenues	—		—		—		—		—		115.3		—		(115.3)		—
Other operation and maintenance	387.1		86.5		21.7		495.3		—		21.5		1.3		(1.5)		516.6
Depreciation and amortization	215.3		59.3		11.2		285.8		—		48.8		5.3		(19.6)		320.3
Equity in earnings of transmission affiliates	—		—		—		—		44.7		—		—		—		44.7
Interest expense	148.7		22.0		3.7		174.4		5.0		24.8		66.3		(88.0)		182.5
Income tax expense (benefit)	69.3		8.9		(2.0)		76.2		10.0		(6.7)		(19.1)		—		60.4
Net income (loss)	243.4		24.7		(6.0)		262.1		29.7		66.7		(42.9)		—		315.6
Net income (loss) attributed to common shareholders	243.1		24.7		(6.0)		261.8		29.7		67.4		(42.9)		—		316.0


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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
Nine Months Ended September 30, 2024
External revenues	$	4,737.0	$	1,116.4	$	308.6	$	6,162.0	$	—	$	153.7	$	—	$	—	$	6,315.7
Intersegment revenues	—		—		—		—		—		355.9		—		(355.9)		—
Other operation and maintenance	1,182.6		336.1		67.8		1,586.5		—		62.3		(10.7)		(7.1)		1,631.0
Depreciation and amortization	685.3		191.1		34.9		911.3		—		147.9		16.6		(65.3)		1,010.5
Equity in earnings of transmission affiliates	—		—		—		—		138.3		—		—		—		138.3
Interest expense	475.4		70.8		12.1		558.3		14.5		71.6		222.1		(269.7)		596.8
Income tax expense (benefit)	172.6		63.3		12.0		247.9		30.6		(59.6)		(58.0)		—		160.9
Net income (loss)	637.2		164.6		35.5		837.3		93.2		269.2		(128.5)		—		1,071.2
Net income (loss) attributed to common shareholders	636.3		164.6		35.5		836.4		93.2		272.6		(128.5)		—		1,073.7


	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
Nine Months Ended September 30, 2023
External revenues	$	5,042.8	$	1,116.5	$	379.5	$	6,538.8	$	—	$	136.6	$	0.1	$	—	$	6,675.5
Intersegment revenues	—		—		—		—		—		358.4		—		(358.4)		—
Other operation and maintenance	1,119.7		305.5		68.2		1,493.4		—		59.6		0.6		(7.0)		1,546.6
Depreciation and amortization	632.9		176.3		32.2		841.4		—		139.9		15.6		(57.2)		939.7
Equity in earnings of transmission affiliates	—		—		—		—		132.1		—		—		—		132.1
Interest expense	449.4		65.0		12.0		526.4		14.6		69.8		183.9		(261.3)		533.4
Income tax expense (benefit)	188.8		61.8		10.5		261.1		29.4		(44.2)		(63.3)		—		183.0
Net income (loss)	686.8		167.9		30.9		885.6		88.1		240.9		(101.4)		—		1,113.2
Net income (loss) attributed to common shareholders	685.9		167.9		30.9		884.7		88.1		241.8		(101.4)		—		1,113.2

NOTE 22—VARIABLE INTEREST ENTITIES

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

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


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WEPCo Environmental Trust Finance I, LLC

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

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

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

WEPCo Environmental Trust is a VIE primarily because its equity capitalization is insufficient to support its operations. As described above, WE has the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, WE is considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.

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


(in millions)	September 30, 2024		December 31, 2023
Assets
Other current assets (restricted cash)	$	3.3	$	0.8
Regulatory assets	79.1		85.9
Other long-term assets (restricted cash)	0.3		0.6

Liabilities
Current portion of long-term debt	9.1		9.0

Other current liabilities (accrued interest)	0.4		0.1
Long-term debt	80.9		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 September 30, 2024 and December 31, 2023, our equity investment in ATC was $2,054.1 million and $1,980.8 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At September 30, 2024 and December 31, 2023, our equity investment in ATC Holdco was $26.7 million and $25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.


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See Note 20, 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 23—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 September 30, 2024, including those of our subsidiaries, were approximately $9.8 billion.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, 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 Rule

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

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

In February 2024, the Supreme Court heard oral arguments regarding stay applications related to the EPA's Good Neighbor Rule. In June 2024, the Supreme Court granted a stay of the Good Neighbor Rule pending disposition of the applicants' petitions for review at the D.C. Circuit Court of Appeals. We will continue to monitor this case as arguments at the D.C. Circuit Court of Appeals move forward.

Mercury and Air Toxics Standards

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


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National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that also supported the reconsideration; however, in August 2023, the EPA announced that it was instead restarting its ozone standard evaluation. The EPA 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 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status 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 18 months from the May 2025 deadline if the state's 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 has indicated it intends to submit a SIP revision by the May 2025 deadline.

The most recent attainment evaluation date was in August 2024. The moderate attainment deadline was not met, so the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. The EPA must reclassify the nonattainment areas by February 2025. We continue to evaluate the impacts the nonattainment redesignation will have 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. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until 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. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units.

Climate Change

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


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affected under the rule because the rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the Greenhouse Gas Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals.

In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule. The EPA indicated that it intends to draft a new rule for existing natural gas-fired units and opened a non-regulatory docket for this new rulemaking. The EPA has stated it anticipates a proposed rule by the end of 2024.

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

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 nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle power plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit. We expect to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8, the planned retirement of the jointly-owned Columbia Units 1 and 2, and the planned retirement of Weston Unit 3. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements. In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

We also 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 continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility distribution systems. In addition, subject to regulatory approval, we may procure RTCs.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

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

Steam Electric Effluent Limitation Guidelines

The EPA's 2015 final ELG rule, which took effect in January 2016 (2015 ELG rule), was modified in 2020 (2020 ELG rule), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect WE and WPS facilities relate to discharge limits for


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BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP, ERGS, and Weston to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $105 million in capital investment.

The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date. The Supplemental ELG Rule also kept one existing and created one new “permanent cessation of coal” subcategory. Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively. For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025. All WE and WPS coal-fueled units fully meet the 2020 ELG rule requirements. Based on current electrical generation resource planning, we plan to file a Notice of Planned Participation by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for both the ERGS and Weston coal-fueled facilities.

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

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

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)	September 30, 2024		December 31, 2023
Regulatory assets	$	565.8	$	596.8
Reserves for future environmental remediation	430.5		463.7

Coal Combustion Residuals Rule

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


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We expect the final rule, which will become effective in November 2024, to have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. We expect the cost of the additional remediation would be recovered through future rates. See Note 8, Asset Retirement Obligations, for more information on the estimated cost of the additional remediation.

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.

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 24—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Nine Months Ended September 30
(in millions)	2024		2023
Cash paid for interest, net of amount capitalized	$	533.1	$	432.9
Cash paid (received) for income taxes, net (1)	(214.6)		15.8
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	163.4		236.5
Common stock issued for stock-based compensation plans	6.4		—
Increase in receivables related to insurance proceeds	5.3		6.2

(1) Cash received for income taxes in 2024 includes $217.1 million related to 2023 and 2024 PTCs that were sold to third parties.


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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)	September 30, 2024		December 31, 2023
Cash and cash equivalents	$	322.5	$	42.9
Restricted cash included in other current assets	11.2		70.1
Restricted cash included in other long-term assets	27.3		52.2
Cash, cash equivalents, and restricted cash	$	361.0	$	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.

NOTE 25—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.


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A decision is expected in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025 and 2026.

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

2023 Rate Order

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

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

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

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

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

In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders. The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of SMP projects that started in 2023 and emergency repairs needed to ensure the safety and reliability of PGL's delivery system. On May 30, 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement.

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $178.9 million non-cash impairment of our property, plant, and equipment during the fourth quarter of 2023. This amount included $177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $1.7 million of capital costs disallowed at NSG. The remaining disallowance of capital costs at PGL related to expected future spend.

On June 7, 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 16, 2023 and May 30, 2024 orders.

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation. The order required a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively. These amounts were refunded over a period of nine months, which began on September 1, 2023. In 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.


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As of September 30, 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. On August 14, 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on these investments. The charge was recorded on the income statement as a $12.9 million reduction in revenues for the amounts previously collected from customers, a $12.1 million increase to operation and maintenance expense for the impairment of PGL's property, plant, and equipment, and a $0.3 million increase to interest expense related to the amounts due to customers. On October 25, 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August 14, 2024 order.

In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2017 through 2022, is still pending. The aggregate capital costs included in the rider during the open reconciliation years, which include 2017 through 2023, are approximately $2,058 million. As of September 30, 2024, there can be no assurance that all of these costs, along with any previously recognized return on these investments, will be deemed recoverable by the ICC. Further disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Minnesota Energy Resources Corporation

2023 Rate Order

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

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

MERC’s customers were entitled to an $8.9 million refund due to the interim rate increase exceeding the final approved rate increase. These amounts were refunded to customers during the second quarter of 2024.

Michigan Gas Utilities Corporation

2024 Rate Order

In March 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates. On September 26, 2024, the MPSC issued a final order approving a settlement agreement, which authorizes MGU to increase its natural gas base rates by $7.0 million (3.88%). The rate increase reflects a 9.86% ROE and a common equity component average of 50.0%. The rate increase is primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates


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over the past few years. The order also authorizes MGU to defer any expenses incurred to implement the Pipeline and Hazardous Materials Safety Administration's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair."

The new rates will be effective January 1, 2025.

Upper Michigan Energy Resources Corporation

2024 Rate Order

In May 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers. On October 10, 2024, the MPSC issued a final order approving a settlement agreement, which authorizes UMERC to increase electric base rates for non-mine customers by $6.6 million (8.2%). The rate increase reflects a 9.86% ROE and a common equity component average of 50.0%. The rate increase is primarily driven by the construction of the now in-service RICE generation facilities located in the Upper Peninsula of Michigan and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates. A reduction of operation and maintenance costs partially offset these impacts.

The new rates will be effective January 1, 2025.

NOTE 26—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 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.


09/30/2024 Form 10-Q			45			WEC Energy Group, Inc.

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