WEC Energy (WEC) 10-Q 31 Jul 24 2024 Q2 Quarterly report Financial data

COVER PAGE

COVER PAGE	6 Months Ended
	Jun. 30, 2024 shares
Cover [Abstract]
Document type	10-Q
Document Quarterly Report	true
Document period end date	Jun. 30, 2024
Document Transition Report	false
Entity File Number	001-09057
Entity registrant name	WEC ENERGY GROUP, INC.
Entity Tax Identification Number	39-1391525
Entity Incorporation, State or Country Code	WI
Entity Address, Address Line One	231 West Michigan Street
Entity Address, Address Line Two	P.O. Box 1331
Entity Address, City or Town	Milwaukee
Entity Address, State or Province	WI
Entity Address, Postal Zip Code	53201
City Area Code	414
Local Phone Number	221-2345
Title of 12(b) Security	Common Stock, $.01 Par Value
Trading Symbol	WEC
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity filer category	Large Accelerated Filer
Smaller reporting company	false
Emerging growth company	false
Entity Shell Company	false
Entity common stock, shares outstanding	316,079,401
Entity central index key	0000783325
Current fiscal year end date	--12-31
Document fiscal year focus	2024
Document fiscal period focus	Q2
Amendment flag	false

CONDENSED CONSOLIDATED INCOME S

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Income Statement [Abstract]
Operating revenues	$ 1,772	$ 1,830	$ 4,452.2	$ 4,718.1
Operating expenses
Cost of sales	469.7	533	1,396.8	1,842.7
Other operation and maintenance	533.4	496	1,064.2	1,030
Depreciation and amortization	336.6	313.9	670	619.4
Property and revenue taxes	67.5	61.8	143	131.4
Total operating expenses	1,407.2	1,404.7	3,274	3,623.5
Operating income	364.8	425.3	1,178.2	1,094.6
Equity in earnings of transmission affiliates	46.8	43.6	91.6	87.4
Other income, net	40.6	48.3	84.7	89.1
Interest expense	200.6	178.7	392.6	350.9
Other expense	(113.2)	(86.8)	(216.3)	(174.4)
Income before income taxes	251.6	338.5	961.9	920.2
Income tax expense	41.6	48.5	129.3	122.6
Net income	210	290	832.6	797.6
Preferred stock dividends of subsidiary	0.3	0.3	0.6	0.6
Net loss attributed to noncontrolling interests	1.6	0	1.6	0.2
Net income attributed to common shareholders	$ 211.3	$ 289.7	$ 833.6	$ 797.2
Earnings per share
Basic (in dollars per share)	$ 0.67	$ 0.92	$ 2.64	$ 2.53
Diluted (in dollars per share)	$ 0.67	$ 0.92	$ 2.64	$ 2.52
Weighted average common shares outstanding
Basic (in shares)	315.9	315.4	315.8	315.4
Diluted (in shares)	316.2	315.9	316.1	315.9

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Statement of Other Comprehensive Income [Abstract]
Net income	$ 210	$ 290	$ 832.6	$ 797.6
Derivatives accounted for as cash flow hedges
Reclassification of realized derivative gains to net income, net of tax	0	0	(0.1)	(0.1)
Comprehensive income	210	290	832.5	797.5
Preferred stock dividends of subsidiary	0.3	0.3	0.6	0.6
Comprehensive loss attributed to noncontrolling interests	1.6	0	1.6	0.2
Comprehensive income attributed to common shareholders	$ 211.3	$ 289.7	$ 833.5	$ 797.1

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 224	$ 42.9
Accounts receivable and unbilled revenues, net of reserves of $166.9 and $193.5, respectively	1,242.7	1,503.2
Materials, supplies, and inventories	695.8	775.2
Prepaid taxes	182.6	173.9
Other prepayments	52.6	76.8
Other	186.4	223.7
Current assets	2,584.1	2,795.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $11,263.4 and $11,073.1, respectively	32,263.8	31,581.5
Regulatory assets (June 30, 2024 and December 31, 2023 include $82.3 and $85.9, respectively, related to WEPCo Environmental Trust)	3,393.1	3,249.8
Equity investment in transmission affiliates	2,055.8	2,005.9
Goodwill	3,052.8	3,052.8
Pension and OPEB assets	901.2	870.9
Other	331.4	383.1
Long-term assets	41,998.1	41,144
Total assets	44,582.2	43,939.7
Current liabilities
Short-term debt	761.3	2,020.9
Current portion of long-term debt (June 30, 2024 and December 31, 2023 include $9.1 and $9.0, respectively, related to WEPCo Environmental Trust)	1,157.4	1,264.2
Accounts payable	799.9	896.6
Customer credit balances	178.8	236.2
Other	594.2	696.9
Current liabilities	3,491.6	5,114.8
Long-term liabilities
Long-term debt (June 30, 2024 and December 31, 2023 include $80.9 and $85.3, respectively, related to WEPCo Environmental Trust)	16,907.8	15,512.8
Deferred income taxes	5,265.4	4,918.5
Deferred revenue, net	345.5	356.4
Regulatory liabilities	3,834.7	3,697.7
Intangible liabilities	568	594.8
Environmental remediation liabilities	437	463.7
AROs	543.6	374.2
Other	794.2	835.3
Long-term liabilities	28,696.2	26,753.4
Commitments and contingencies (Note 23)
Common shareholders' equity
Common stock – $0.01 par value; 650,000,000 shares authorized; 316,079,401 and $315,434,531 shares outstanding, respectively	3.2	3.2
Additional paid in capital	4,168.3	4,115.9
Retained earnings	7,919.2	7,612.8
Accumulated other comprehensive loss	(7.8)	(7.7)
Common shareholders' equity	12,082.9	11,724.2
Preferred stock of subsidiary	30.4	30.4
Noncontrolling interests	281.1	316.9
Total liabilities and equity	$ 44,582.2	$ 43,939.7
Common stock, shares outstanding	316,079,401	315,434,531

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 166.9	$ 193.5
Property, plant, and equipment, accumulated depreciation and amortization	$ 11,263.4	$ 11,073.1
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	650,000,000	650,000,000
Common stock, shares outstanding	316,079,401	315,434,531
Regulatory assets (June 30, 2024 and December 31, 2023 include $82.3 and $85.9, respectively, related to WEPCo Environmental Trust)	$ 3,393.1	$ 3,249.8
Current portion of long-term debt (June 30, 2024 and December 31, 2023 include $9.1 and $9.0, respectively, related to WEPCo Environmental Trust)	1,157.4	1,264.2
WEPCo Environmental Trust
Regulatory assets (June 30, 2024 and December 31, 2023 include $82.3 and $85.9, respectively, related to WEPCo Environmental Trust)	82.3	85.9
Current portion of long-term debt (June 30, 2024 and December 31, 2023 include $9.1 and $9.0, respectively, related to WEPCo Environmental Trust)	9.1	9
Long-term debt (June 30, 2024 and December 31, 2023 include $80.9 and $85.3, respectively, related to WEPCo Environmental Trust)	$ 80.9	$ 85.3

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Operating activities
Net income	$ 832.6	$ 797.6
Reconciliation to cash provided by operating activities
Depreciation and amortization	670	619.4
Deferred income taxes and ITCs, net	321.5	113.4
Contributions and payments related to pension and OPEB plans	(7.5)	(9.2)
Equity income in transmission affiliates, net of distributions	(19.6)	(13.4)
Change in –
Accounts receivable and unbilled revenues, net	254.2	529.5
Materials, supplies, and inventories	79.4	213.3
Collateral on deposit	47.4	(28.9)
Amounts recoverable from customers	(17)	33.7
Other current assets	19.1	16.2
Accounts payable	(90.3)	(388.4)
Customer credit balances	(57.4)	(10.9)
Other current liabilities	(53.1)	(28.9)
Other, net	(78.3)	(89.1)
Net cash provided by operating activities	1,901	1,754.3
Investing activities
Capital expenditures	(1,138.4)	(1,073.7)
Acquisition of West Riverside	(98.2)	(95.3)
Acquisition of Whitewater	0	(76)
Acquisition of Sapphire Sky, net of cash acquired of $0.3	0	(442.6)
Acquisition of Samson I, net of cash acquired of $5.2	0	(249.4)
Acquisition of Red Barn	0	(143.8)
Capital contributions to transmission affiliates	(30.3)	(33.3)
Proceeds from the sale of assets	0.9	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	(0.6)	(19.1)
Other, net	1	(9)
Net cash used in investing activities	(1,250.8)	(2,101.4)
Financing activities
Exercise of stock options	4.7	2.3
Issuance of common stock	38.2	0
Purchase of common stock	(3.2)	(9.5)
Dividends paid on common stock	(527.2)	(492.1)
Issuance of long-term debt	2,074.2	1,450
Retirement of long-term debt	(785.4)	(76.8)
Change in commercial paper	(1,260.4)	(556.6)
Purchase of additional ownership interest in Samson I from noncontrolling interest	(28.1)	0
Payments for debt extinguishment and issuance costs	(23.6)	(9.6)
Other, net	(1.7)	(2.7)
Net cash provided by (used in) financing activities	(512.5)	305
Net change in cash, cash equivalents, and restricted cash	137.7	(42.1)
Cash, cash equivalents, and restricted cash at beginning of period	165.2	182.2
Cash, cash equivalents, and restricted cash at end of period	$ 302.9	$ 140.1

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) $ in Millions	6 Months Ended
	Jun. 30, 2023 USD ($)
Sapphire Sky
Acquisitions
Cash acquired	$ 0.3
Samson I
Acquisitions
Cash acquired	$ 5.2

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total common shareholders' equity	Common stock	Additional paid in capital	Retained earnings	Accumulated other comprehensive loss	Preferred stock of subsidiary	Noncontrolling interests
Balance at Dec. 31, 2022	$ 11,616.6	$ 11,376.9	$ 3.2	$ 4,115.2	$ 7,265.3	$ (6.8)	$ 30.4	$ 209.3
Statements of equity
Net income attributed to common shareholders	507.5	507.5	0	0	507.5	0	0	0
Net loss attributed to noncontrolling interests	(0.2)	0	0	0	0	0	0	(0.2)
Other comprehensive loss	(0.1)	(0.1)	0	0	0	(0.1)	0	0
Common stock dividends	(246.1)	(246.1)	0	0	(246.1)	0	0	0
Exercise of stock options	0.9	0.9	0	0.9	0	0	0	0
Purchase of common stock	(6.9)	(6.9)	0	(6.9)	0	0	0	0
Acquisition of noncontrolling interests	112.9	0	0	0	0	0	0	112.9
Distributions to noncontrolling interests	(1.3)	0	0	0	0	0	0	(1.3)
Stock-based compensation and other	4.4	4.4	0	4.4	0	0	0	0
Balance at Mar. 31, 2023	$ 11,987.7	11,636.6	3.2	4,113.6	7,526.7	(6.9)	30.4	320.7
Statements of equity
Common stock dividend declared (in dollars per share)	$ 0.7800
Balance at Dec. 31, 2022	$ 11,616.6	11,376.9	3.2	4,115.2	7,265.3	(6.8)	30.4	209.3
Statements of equity
Net income attributed to common shareholders	797.2
Net loss attributed to noncontrolling interests	(0.2)
Issuance of common stock	0
Balance at Jun. 30, 2023	12,031.4	11,681.4	3.2	4,114.7	7,570.4	(6.9)	30.4	319.6
Balance at Mar. 31, 2023	11,987.7	11,636.6	3.2	4,113.6	7,526.7	(6.9)	30.4	320.7
Statements of equity
Net income attributed to common shareholders	289.7	289.7	0	0	289.7	0	0	0
Net loss attributed to noncontrolling interests	0
Common stock dividends	(246)	(246)	0	0	(246)	0	0	0
Exercise of stock options	1.4	1.4	0	1.4	0	0	0	0
Purchase of common stock	(2.6)	(2.6)	0	(2.6)	0	0	0	0
Distributions to noncontrolling interests	(1)	0	0	0	0	0	0	(1)
Stock-based compensation and other	2.2	2.3	0	2.3	0	0	0	(0.1)
Balance at Jun. 30, 2023	$ 12,031.4	11,681.4	3.2	4,114.7	7,570.4	(6.9)	30.4	319.6
Statements of equity
Common stock dividend declared (in dollars per share)	$ 0.7800
Balance at Dec. 31, 2023	$ 12,071.5	11,724.2	3.2	4,115.9	7,612.8	(7.7)	30.4	316.9
Statements of equity
Net income attributed to common shareholders	622.3	622.3	0	0	622.3	0	0	0
Other comprehensive loss	(0.1)	(0.1)	0	0	0	(0.1)	0	0
Issuance of common stock	19.2	19.2	0	19.2	0	0	0	0
Common stock dividends	(263.5)	(263.5)	0	0	(263.5)	0	0	0
Exercise of stock options	3.7	3.7	0	3.7	0	0	0	0
Purchase of common stock	(2)	(2)	0	(2)	0	0	0	0
Purchase of additional ownership interest in Samson I from noncontrolling interest	(28.1)	4.3	0	4.3	0	0	0	(32.4)
Distributions to noncontrolling interests	(1.5)	0	0	0	0	0	0	(1.5)
Stock-based compensation and other	4.6	4.6	0	4.6	0	0	0	0
Balance at Mar. 31, 2024	$ 12,426.1	12,112.7	3.2	4,145.7	7,971.6	(7.8)	30.4	283
Statements of equity
Common stock dividend declared (in dollars per share)	$ 0.8350
Balance at Dec. 31, 2023	$ 12,071.5	11,724.2	3.2	4,115.9	7,612.8	(7.7)	30.4	316.9
Statements of equity
Net income attributed to common shareholders	833.6
Net loss attributed to noncontrolling interests	(1.6)
Issuance of common stock	38.2
Balance at Jun. 30, 2024	12,394.4	12,082.9	3.2	4,168.3	7,919.2	(7.8)	30.4	281.1
Balance at Mar. 31, 2024	12,426.1	12,112.7	3.2	4,145.7	7,971.6	(7.8)	30.4	283
Statements of equity
Net income attributed to common shareholders	211.3	211.3	0	0	211.3	0	0	0
Net loss attributed to noncontrolling interests	(1.6)	0	0	0	0	0	0	(1.6)
Issuance of common stock	19	19	0	19	0	0	0	0
Common stock dividends	(263.7)	(263.7)	0	0	(263.7)	0	0	0
Exercise of stock options	1	1	0	1	0	0	0	0
Purchase of common stock	(1.2)	(1.2)	0	(1.2)	0	0	0	0
Distributions to noncontrolling interests	(0.3)	0	0	0	0	0	0	(0.3)
Stock-based compensation and other	3.8	3.8	0	3.8	0	0	0	0
Balance at Jun. 30, 2024	$ 12,394.4	$ 12,082.9	$ 3.2	$ 4,168.3	$ 7,919.2	$ (7.8)	$ 30.4	$ 281.1
Statements of equity
Common stock dividend declared (in dollars per share)	$ 0.8350

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2024	Mar. 31, 2024	Jun. 30, 2023	Mar. 31, 2023
Statement of Stockholders' Equity [Abstract]
Common stock dividend declared (in dollars per share)	$ 0.8350	$ 0.8350	$ 0.7800	$ 0.7800

GENERAL INFORMATION

GENERAL INFORMATION	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	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 six months ended June 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.

ACQUISITIONS

ACQUISITIONS	6 Months Ended
	Jun. 30, 2024
Asset Acquisition [Abstract]
ACQUISITIONS	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. Acquisitions of Electric Generation Facilities in Wisconsin In May 2024, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity for $98.2 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to the acquisition, WPS received 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 $193.5 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.

DISPOSITIONS

DISPOSITIONS	6 Months Ended
	Jun. 30, 2024
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	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.

OPERATING REVENUES

OPERATING REVENUES	6 Months Ended
	Jun. 30, 2024
Revenue from Contract with Customer [Abstract]
OPERATING REVENUES	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 June 30, 2024 Electric $ 1,148.5 $ — $ — $ 1,148.5 $ — $ — $ — $ 1,148.5 Natural gas 215.1 255.5 63.4 534.0 11.4 — (10.8) 534.6 Total regulated revenues 1,363.6 255.5 63.4 1,682.5 11.4 — (10.8) 1,683.1 Other non-utility revenues — — 4.9 4.9 59.3 — (3.9) 60.3 Total revenues from contracts with customers 1,363.6 255.5 68.3 1,687.4 70.7 — (14.7) 1,743.4 Other operating revenues 4.6 21.3 2.7 28.6 104.9 — (104.9) (1) 28.6 Total operating revenues $ 1,368.2 $ 276.8 $ 71.0 $ 1,716.0 $ 175.6 $ — $ (119.6) $ 1,772.0 (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 June 30, 2023 Electric $ 1,178.5 $ — $ — $ 1,178.5 $ — $ — $ — $ 1,178.5 Natural gas 239.9 260.0 76.9 576.8 14.1 — (13.6) 577.3 Total regulated revenues 1,418.4 260.0 76.9 1,755.3 14.1 — (13.6) 1,755.8 Other non-utility revenues — — 4.7 4.7 53.3 — (3.8) 54.2 Total revenues from contracts with customers 1,418.4 260.0 81.6 1,760.0 67.4 — (17.4) 1,810.0 Other operating revenues 6.1 13.5 0.3 19.9 101.6 0.1 (101.6) (1) 20.0 Total operating revenues $ 1,424.5 $ 273.5 $ 81.9 $ 1,779.9 $ 169.0 $ 0.1 $ (119.0) $ 1,830.0 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2024 Electric $ 2,333.8 $ — $ — $ 2,333.8 $ — $ — $ — $ 2,333.8 Natural gas 801.1 859.3 237.0 1,897.4 25.9 — (25.0) 1,898.3 Total regulated revenues 3,134.9 859.3 237.0 4,231.2 25.9 — (25.0) 4,232.1 Other non-utility revenues — — 9.9 9.9 111.4 — (5.5) 115.8 Total revenues from contracts with customers 3,134.9 859.3 246.9 4,241.1 137.3 — (30.5) 4,347.9 Other operating revenues 12.1 83.5 8.7 104.3 209.2 — (209.2) (1) 104.3 Total operating revenues $ 3,147.0 $ 942.8 $ 255.6 $ 4,345.4 $ 346.5 $ — $ (239.7) $ 4,452.2 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2023 Electric $ 2,382.3 $ — $ — $ 2,382.3 $ — $ — $ — $ 2,382.3 Natural gas 1,024.3 837.7 321.9 2,183.9 35.4 — (34.7) 2,184.6 Total regulated revenues 3,406.6 837.7 321.9 4,566.2 35.4 — (34.7) 4,566.9 Other non-utility revenues — — 9.9 9.9 96.8 — (5.4) 101.3 Total revenues from contracts with customers 3,406.6 837.7 331.8 4,576.1 132.2 — (40.1) 4,668.2 Other operating revenues 14.2 35.5 0.1 49.8 203.0 0.1 (203.0) (1) 49.9 Total operating revenues $ 3,420.8 $ 873.2 $ 331.9 $ 4,625.9 $ 335.2 $ 0.1 $ (243.1) $ 4,718.1 (1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates. Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Residential $ 458.6 $ 459.1 $ 941.8 $ 945.6 Small commercial and industrial 383.6 401.5 775.3 795.1 Large commercial and industrial 224.9 239.9 442.5 469.7 Other 7.2 7.2 15.1 15.2 Total retail revenues 1,074.3 1,107.7 2,174.7 2,225.6 Wholesale 27.7 30.4 53.3 64.6 Resale 37.8 31.9 82.9 72.5 Steam 4.1 4.6 14.3 15.6 Other utility revenues 4.6 3.9 8.6 4.0 Total electric utility operating revenues $ 1,148.5 $ 1,178.5 $ 2,333.8 $ 2,382.3 Natural Gas Utility Operating Revenues The following tables disaggregate natural gas utility operating revenues into customer class: (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended June 30, 2024 Residential $ 124.9 $ 162.1 $ 30.1 $ 317.1 Commercial and industrial 53.2 41.5 16.2 110.9 Total retail revenues 178.1 203.6 46.3 428.0 Transportation 21.3 52.5 6.2 80.0 Other utility revenues (1) 15.7 (0.6) 10.9 26.0 Total natural gas utility operating revenues $ 215.1 $ 255.5 $ 63.4 $ 534.0 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended June 30, 2023 Residential $ 120.1 $ 180.0 $ 53.6 $ 353.7 Commercial and industrial 50.6 42.4 26.2 119.2 Total retail revenues 170.7 222.4 79.8 472.9 Transportation 20.4 48.8 6.2 75.4 Other utility revenues (1) 48.8 (11.2) (9.1) 28.5 Total natural gas utility operating revenues $ 239.9 $ 260.0 $ 76.9 $ 576.8 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2024 Residential $ 522.5 $ 537.1 $ 141.5 $ 1,201.1 Commercial and industrial 245.0 148.5 70.2 463.7 Total retail revenues 767.5 685.6 211.7 1,664.8 Transportation 51.1 142.6 17.8 211.5 Other utility revenues (1) (17.5) 31.1 7.5 21.1 Total natural gas utility operating revenues $ 801.1 $ 859.3 $ 237.0 $ 1,897.4 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2023 Residential $ 674.9 $ 548.9 $ 218.1 $ 1,441.9 Commercial and industrial 345.8 160.3 117.7 623.8 Total retail revenues 1,020.7 709.2 335.8 2,065.7 Transportation 49.3 125.4 17.1 191.8 Other utility revenues (1) (45.7) 3.1 (31.0) (73.6) Total natural gas utility operating revenues $ 1,024.3 $ 837.7 $ 321.9 $ 2,183.9 (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 June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Wind generation revenues $ 49.3 $ 43.6 $ 93.8 $ 79.6 We Power revenues (1) 6.1 5.9 12.1 11.8 Appliance service revenues 4.9 4.7 9.9 9.9 Total other non-utility operating revenues $ 60.3 $ 54.2 $ 115.8 $ 101.3 (1) As part of the construction of the We Power electric utility generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Late payment charges 14.1 16.2 28.7 33.4 Alternative revenues (1) $ 12.3 $ 2.1 $ 72.8 $ 13.9 Other 2.2 1.7 2.8 2.6 Total other operating revenues $ 28.6 $ 20.0 $ 104.3 $ 49.9 (1) Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

CREDIT LOSSES

CREDIT LOSSES	6 Months Ended
	Jun. 30, 2024
Credit Loss [Abstract]
CREDIT LOSSES	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. We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at June 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 June 30, 2024 Accounts receivable and unbilled revenues $ 966.0 $ 364.0 $ 36.8 $ 1,366.8 $ 37.1 $ 5.7 $ 1,409.6 Allowance for credit losses 68.7 93.2 5.0 166.9 — — 166.9 Accounts receivable and unbilled revenues, net (1) $ 897.3 $ 270.8 $ 31.8 $ 1,199.9 $ 37.1 $ 5.7 $ 1,242.7 Total accounts receivable, net – past due greater than 90 days (1) $ 66.9 $ 56.2 $ 2.4 $ 125.5 $ — $ — $ 125.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 94.4 % 100.0 % — % 95.1 % — % — % 95.1 % (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 June 30, 2024, $729.6 million, or 58.7%, 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 June 30, 2024 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at April 1, 2024 $ 83.0 $ 104.6 $ 3.1 $ 190.7 Provision for credit losses 9.8 12.2 1.7 23.7 Provision for credit losses deferred for future recovery or refund 1.4 (7.5) — (6.1) Write-offs charged against the allowance (35.9) (22.3) (1.1) (59.3) Recoveries of amounts previously written off 10.4 6.2 1.3 17.9 Balance at June 30, 2024 $ 68.7 $ 93.2 $ 5.0 $ 166.9 Six Months Ended June 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 23.6 27.3 (1.3) 49.6 Provision for credit losses deferred for future recovery or refund 17.1 (6.2) — 10.9 Write-offs charged against the allowance (71.5) (50.3) (2.4) (124.2) Recoveries of amounts previously written off 22.1 12.7 2.3 37.1 Balance at June 30, 2024 $ 68.7 $ 93.2 $ 5.0 $ 166.9 On a consolidated basis, there was a $26.6 million decrease in the allowance for credit losses at June 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 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 June 30, 2023 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at April 1, 2023 $ 90.9 $ 116.5 $ 6.4 $ 213.8 Provision for credit losses 6.7 4.8 (0.4) 11.1 Provision for credit losses deferred for future recovery or refund (3.9) (8.5) — (12.4) Write-offs charged against the allowance (29.1) (21.3) (1.1) (51.5) Recoveries of amounts previously written off 11.8 5.5 0.4 17.7 Balance at June 30, 2023 $ 76.4 $ 97.0 $ 5.3 $ 178.7 Six Months Ended June 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 17.9 13.3 0.9 32.1 Provision for credit losses deferred for future recovery or refund 16.5 6.7 — 23.2 Write-offs charged against the allowance (58.0) (44.3) (2.7) (105.0) Recoveries of amounts previously written off 18.0 10.3 0.8 29.1 Balance at June 30, 2023 $ 76.4 $ 97.0 $ 5.3 $ 178.7 On a consolidated basis, there was a $20.6 million decrease in the allowance for credit losses at June 30, 2023, compared to January 1, 2023, 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. Also contributing to the decrease in the allowance for credit losses, we believe that the lower energy costs that customers were seeing, which were 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.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	6 Months Ended
	Jun. 30, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities were reflected on our balance sheets at June 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) June 30, 2024 December 31, 2023 Regulatory assets Plant retirement related items (1) $ 824.6 $ 646.2 Pension and OPEB costs 725.1 731.7 Environmental remediation costs 575.2 596.8 Income tax related items 442.8 449.9 AROs 167.1 162.0 Uncollectible expense 123.9 127.7 System support resource 107.9 113.2 Decoupling (2) 102.1 27.3 Securitization 82.3 85.9 Derivatives 62.7 130.3 Bluewater 53.5 45.3 Energy efficiency programs 30.1 33.9 Other, net 137.7 124.5 Total regulatory assets $ 3,435.0 $ 3,274.7 Balance sheet presentation Other current assets $ 41.9 $ 24.9 Regulatory assets 3,393.1 3,249.8 Total regulatory assets $ 3,435.0 $ 3,274.7 (1) Included in plant retirement related items at June 30, 2024, are $116.0 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) June 30, 2024 December 31, 2023 Regulatory liabilities Income tax related items $ 1,852.0 $ 1,901.8 Removal costs 1,401.5 1,329.9 Pension and OPEB benefits 300.3 299.2 Energy costs refundable through rate adjustments 143.1 72.4 Derivatives 39.8 19.2 Electric transmission costs 29.5 30.3 Uncollectible expense 24.8 21.2 Energy efficiency programs 19.4 17.2 Other, net 84.2 54.0 Total regulatory liabilities $ 3,894.6 $ 3,745.2 Balance sheet presentation Other current liabilities $ 59.9 $ 47.5 Regulatory liabilities 3,834.7 3,697.7 Total regulatory liabilities $ 3,894.6 $ 3,745.2 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 $78.3 million at June 30, 2024 was classified as a regulatory asset. In addition, a $43.9 million cost of removal reserve related to the units continued to be classified as a regulatory liability at June 30, 2024. Not included in these

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	6 Months Ended
	Jun. 30, 2024
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	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. 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 $675.8 million at June 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. Columbia Units 1 and 2 are expected to be retired by June 2026. The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $252.1 million at June 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 wind storms in March 2023, June 2023, and May 2024, certain sections of our Samson I solar facility incurred damage. As of June 30, 2024, we recognized an impairment of $2.3 million related to storm damage, which was offset by a $2.3 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from these events.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	6 Months Ended
	Jun. 30, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	ASSET RETIREMENT OBLIGATIONS Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; the disposal of PCB-contaminated transformers; the closure of CCR landfills at certain generation facilities; and the removal of above ground and underground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. WECI has also recorded AROs for the dismantling of our non-utility renewable generation projects. The following table shows changes to our AROs: (in millions) 2024 2023 Balance at January 1 $ 374.2 $ 479.3 Accretion 7.4 8.5 Additions 165.7 (1) 16.6 (2) Liabilities settled (3.7) (1.5) Balance at June 30 $ 543.6 $ 502.9 (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.

COMMON EQUITY

COMMON EQUITY	6 Months Ended
	Jun. 30, 2024
Equity [Abstract]
COMMON EQUITY	COMMON EQUITY Stock-Based Compensation During the six months ended June 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 compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans. As such, no new shares of common stock were issued during the three and six months ended June 30, 2023. We had the following changes to our outstanding common stock during the three and six months ended June 30, 2024: Three Months Ended June 30, 2024 Six Months Ended June 30, 2024 Common stock shares outstanding at beginning of period 315,822,587 315,434,531 Shares issued: Stock-based compensation 20,488 162,666 401(k) 122,300 246,600 Stock investment plan 114,026 235,604 Common stock shares outstanding at end of period 316,079,401 316,079,401 On July 18, 2024, our Board of Directors declared a quarterly cash dividend of $0.835 per share, payable on September 1, 2024, to shareholders of record on August 14, 2024.

SHORT-TERM DEBT AND LINES OF CR

SHORT-TERM DEBT AND LINES OF CREDIT	6 Months Ended
	Jun. 30, 2024
Short-Term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	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) June 30, 2024 December 31, 2023 Commercial paper Amount outstanding $ 756.8 $ 2,017.2 Weighted-average interest rate on amounts outstanding 5.46 % 5.49 % Operating expense loans Amount outstanding (1) $ 4.5 $ 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 six months ended June 30, 2024 was $1,836.4 million with a weighted-average interest rate during the period of 5.50%. 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 June 30, 2024 WEC Energy Group September 2026 $ 1,500.0 WEC Energy Group October 2024 200.0 WE September 2026 500.0 WPS September 2026 400.0 WG September 2026 350.0 PGL September 2026 350.0 Total short-term credit capacity $ 3,300.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 756.8 Available capacity under existing agreements $ 2,540.9

LONG-TERM DEBT

LONG-TERM DEBT	6 Months Ended
	Jun. 30, 2024
Long-Term Debt, Unclassified [Abstract]
LONG-TERM DEBT	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. 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 June 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 June 30, 2024: (in millions) Principal Amount Unamortized Debt Issuance Costs Net Carrying Amount Fair Value Amount (1) 2027 Notes $ 862.5 $ (9.0) $ 853.5 $ 856.4 2029 Notes 862.5 (9.2) 853.3 856.5 (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 June 30, 2024 Six Months Ended June 30, 2024 2027 Notes Contractual interest expense $ 3.5 $ 3.5 Amortization of debt issuance costs 0.3 0.3 Total interest expense - 2027 Notes 3.8 3.8 2029 Notes Contractual interest expense 3.5 3.5 Amortization of debt issuance costs 0.2 0.2 Total interest expense - 2029 Notes $ 3.7 $ 3.7 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 June 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 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.

LEASES

LEASES	6 Months Ended
	Jun. 30, 2024
Leases [Abstract]
LEASES	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. Each lease has 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, the land leases are being amortized over the extended term of the leases. Once Renegade achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased. We expect to recover the lease payments through rates. Our total obligation under the land-related finance lease for Renegade was $18.7 million at June 30, 2024, and was included in long-term debt on our balance sheet. Our finance lease right of use asset related to Renegade was also $18.7 million as of June 30, 2024, and was included in property, plant, and equipment on our balance sheet. Our weighted-average discount rate for the Renegade finance lease was 5.86%. 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 the finance lease for Renegade as of June 30, 2024, were as follows: (in millions) Six Months Ended December 31, 2024 $ 0.7 2025 0.3 2026 0.9 2027 0.9 2028 0.9 2029 0.9 Thereafter 70.5 Total minimum lease payments 75.1 Less: Interest (56.4) Present value of minimum lease payments 18.7 Less: Short-term lease liabilities — Long-term lease liabilities $ 18.7 On July 30, 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. Once fully constructed, WE and WPS will collectively own 270 MWs of solar generation. 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. We are currently evaluating the impact these leases will have on our financial statements and related disclosures.

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	6 Months Ended
	Jun. 30, 2024
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventories consisted of: (in millions) June 30, 2024 December 31, 2023 Materials and supplies $ 350.3 $ 320.0 Natural gas in storage 239.0 327.8 Fossil fuel 106.5 127.4 Total $ 695.8 $ 775.2 PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. 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 June 30, 2024, we had a temporary LIFO liquidation debit of $0.3 million recorded within other current assets on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end. Substantially all other materials and supplies, natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

INCOME TAXES

INCOME TAXES	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	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 June 30, 2024 Three Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 53.1 21.0 % $ 71.1 21.0 % State income taxes net of federal tax benefit 15.6 6.2 % 21.0 6.2 % PTCs, net (22.2) (8.8) % (33.9) (10.0) % Federal excess deferred tax amortization (4.9) (1.9) % (7.3) (2.2) % Other, net — — % (2.4) (0.7) % Total income tax expense $ 41.6 16.5 % $ 48.5 14.3 % Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 202.2 21.0 % $ 193.2 21.0 % State income taxes net of federal tax benefit 59.0 6.1 % 56.8 6.2 % PTCs, net (110.2) (11.4) % (100.1) (10.9) % Federal excess deferred tax amortization (20.3) (2.1) % (20.4) (2.2) % Other, net (1.4) (0.2) % (6.9) (0.8) % Total income tax expense $ 129.3 13.4 % $ 122.6 13.3 % The effective tax rates for the three and six months ended June 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 are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	6 Months Ended
	Jun. 30, 2024
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	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: June 30, 2024 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 4.0 $ 9.3 $ — $ 13.3 FTRs and TCRs — — 20.8 20.8 Coal contracts — 0.2 — 0.2 Total derivative assets $ 4.0 $ 9.5 $ 20.8 $ 34.3 Investments held in rabbi trust $ 47.9 $ — $ — $ 47.9 Derivative liabilities Natural gas contracts $ 27.6 $ 13.0 $ — $ 40.6 Coal contracts — 15.7 — 15.7 Total derivative liabilities $ 27.6 $ 28.7 $ — $ 56.3 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 June 30, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $1.5 million and $3.6 million, respectively. For the six months ended June 30, 2024 and 2023, the net unrealized gains included in earnings related to the investments held at the end of the period were $5.2 million and $6.4 million, respectively. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Balance at the beginning of the period $ 2.6 $ 3.0 $ 7.2 $ 7.8 Purchases 25.8 19.2 26.8 19.5 Net realized and unrealized losses included in earnings (1) (0.2) (0.2) (1.0) (0.5) Settlements (7.4) (5.2) (12.2) (10.0) Balance at the end of the period $ 20.8 $ 16.8 $ 20.8 $ 16.8 Net unrealized losses included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1) $ (0.2) $ (0.1) $ (0.2) $ (0.1) (1) Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized 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: June 30, 2024 December 31, 2023 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 21.2 $ 30.4 $ 21.4 Long-term debt, including current portion (1) 17,900.6 16,632.6 16,631.1 15,564.3 (1) The carrying amount of long-term debt excludes finance lease obligations of $164.6 million and $145.9 million at June 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.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	6 Months Ended
	Jun. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	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. June 30, 2024 December 31, 2023 (in millions) Derivative Derivative Derivative Derivative Current Natural gas contracts $ 13.1 $ 38.4 $ 10.4 $ 78.1 FTRs and TCRs 20.8 — 7.2 — Coal contracts 0.1 10.8 0.3 10.9 Total current 34.0 49.2 17.9 89.0 Long-term Natural gas contracts 0.2 2.2 0.1 8.0 Coal contracts 0.1 4.9 — 9.4 Total long-term 0.3 7.1 0.1 17.4 Total $ 34.3 $ 56.3 $ 18.0 $ 106.4 Realized gains and losses on derivatives used in our regulated utility operations are recorded in cost of sales operating revenues Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 48.1 Dth $ (29.8) 47.7 Dth $ (69.1) FTRs and TCRs 7.6 MWh 2.0 7.5 MWh 4.1 Total $ (27.8) $ (65.0) Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 115.9 Dth $ (86.7) 106.4 Dth $ (144.4) FTRs and TCRs 15.2 MWh 3.6 14.8 MWh 4.5 Total $ (83.1) $ (139.9) On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2024 and December 31, 2023, we had posted cash collateral of $52.9 million and $100.3 million, respectively. These amounts were recorded on our balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: June 30, 2024 December 31, 2023 (in millions) Derivative Derivative Derivative Derivative Gross amount recognized on the balance sheet $ 34.3 $ 56.3 $ 18.0 $ 106.4 Gross amount not offset on the balance sheet (4.5) (28.1) (1) (3.1) (71.0) (2) Net amount $ 29.8 $ 28.2 $ 14.9 $ 35.4 (1) Includes cash collateral posted of $23.6 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 six months ended June 30, 2024 and 2023 were not significant. At June 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.

GUARANTEES

GUARANTEES	6 Months Ended
	Jun. 30, 2024
Guarantees [Abstract]
GUARANTEES	GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed at June 30, 2024 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 136.5 $ 19.7 $ — $ 116.8 Surety bonds (2) 34.0 32.1 1.9 — Other guarantees (3) 11.0 — — 11.0 Total guarantees $ 181.5 $ 51.8 $ 1.9 $ 127.8 (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.

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	6 Months Ended
	Jun. 30, 2024
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	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 June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 5.4 $ 5.4 $ 12.1 $ 12.0 Interest cost 28.8 30.4 58.3 61.2 Expected return on plan assets (45.3) (46.4) (91.1) (93.8) Amortization of prior service cost — — — 0.1 Amortization of net actuarial loss 15.3 9.3 29.7 16.7 Net periodic benefit cost (credit) $ 4.2 $ (1.3) $ 9.0 $ (3.8) OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 2.6 $ 2.4 $ 5.4 $ 4.9 Interest cost 5.7 5.4 11.4 10.8 Expected return on plan assets (13.1) (13.2) (26.3) (26.5) Amortization of prior service credit (3.4) (3.7) (6.8) (7.4) Amortization of net actuarial gain (1.9) (3.0) (3.8) (6.2) Net periodic benefit credit $ (10.1) $ (12.1) $ (20.1) $ (24.4) During the six months ended June 30, 2024, we made contributions and payments of $6.8 million related to our pension plans and $0.7 million related to our OPEB plans. We expect to make contributions and payments of $6.5 million related to our pension plans and $1.3 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 June 30, 2024, we recorded a $15.5 million regulatory asset for pension costs and a $26.5 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

GOODWILL AND INTANGIBLES

GOODWILL AND INTANGIBLES	6 Months Ended
	Jun. 30, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL AND INTANGIBLES	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 June 30, 2024. We had no changes to the carrying amount of goodwill during the six months ended June 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 June 30, 2024. Intangible Assets At both June 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. June 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 $ (93.0) $ 560.9 $ 653.9 $ (66.6) $ 587.3 Proxy revenue swap (2) 7.2 (3.8) 3.4 7.2 (3.5) 3.7 Interconnection agreements (3) 4.7 (1.0) 3.7 4.7 (0.9) 3.8 Total intangible liabilities $ 665.8 $ (97.8) $ 568.0 $ 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 five years. (3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 16 years. Amortization related to these intangible liabilities for the three and six months ended June 30, 2024, was $13.4 million and $26.8 million, respectively. Amortization for the three and six months ended June 30, 2023, was $13.4 million and $23.8 million, respectively. Amortization for the next five years, including amounts recorded through June 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

INVESTMENT IN TRANSMISSION AFFI

INVESTMENT IN TRANSMISSION AFFILIATES	6 Months Ended
	Jun. 30, 2024
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENT IN TRANSMISSION AFFILIATES	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 June 30, 2024 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 2,001.6 $ 25.5 $ 2,027.1 Add: Earnings from equity method investment 46.2 0.6 46.8 Add: Capital contributions 18.2 — 18.2 Less: Distributions 36.3 — 36.3 Balance at end of period $ 2,029.7 $ 26.1 $ 2,055.8 Three Months Ended June 30, 2023 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,896.2 $ 25.5 $ 1,921.7 Add: Earnings from equity method investment 43.1 0.5 43.6 Add: Capital contributions 27.2 — 27.2 Less: Distributions 34.7 1.9 36.6 Balance at end of period $ 1,931.8 $ 24.1 $ 1,955.9 Six Months Ended June 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 90.6 1.0 91.6 Add: Capital contributions 30.3 — 30.3 Less: Distributions 72.0 — 72.0 Balance at end of period $ 2,029.7 $ 26.1 $ 2,055.8 Six Months Ended June 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 86.0 1.4 87.4 Add: Capital contributions 33.3 — 33.3 Less: Distributions 72.1 1.9 74.0 Balance at end of period $ 1,931.8 $ 24.1 $ 1,955.9 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 June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Charges to ATC for services and construction $ 6.3 $ 4.0 $ 11.0 $ 7.8 Charges from ATC for network transmission services 103.2 94.3 206.5 188.8 Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) June 30, 2024 December 31, 2023 Accounts receivable for services provided to ATC $ 1.6 $ 1.6 Accounts payable for services received from ATC 50.0 49.9 Amounts due from ATC for transmission infrastructure upgrades (1) 42.3 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 June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Income statement data Operating revenues $ 218.3 $ 203.8 $ 430.2 $ 404.2 Operating expenses 109.2 101.5 214.0 200.6 Other expense, net 35.8 32.9 71.0 65.4 Net income $ 73.3 $ 69.4 $ 145.2 $ 138.2 (in millions) June 30, 2024 December 31, 2023 Balance sheet data Current assets $ 146.5 $ 115.2 Noncurrent assets 6,539.3 6,337.0 Total assets $ 6,685.8 $ 6,452.2 Current liabilities $ 586.0 $ 495.9 Long-term debt 2,810.5 2,736.0 Other noncurrent liabilities 573.3 585.2 Members' equity 2,716.0 2,635.1 Total liabilities and members' equity $ 6,685.8 $ 6,452.2

SEGMENT INFORMATION

SEGMENT INFORMATION	6 Months Ended
	Jun. 30, 2024
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At June 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 WECI acquisitions. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark, 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 six months ended June 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 June 30, 2024 External revenues $ 1,368.2 $ 276.8 $ 71.0 $ 1,716.0 $ — $ 56.0 $ — $ — $ 1,772.0 Intersegment revenues — — — — — 119.6 — (119.6) — Other operation and maintenance 389.2 102.6 24.6 516.4 — 25.0 (4.0) (4.0) 533.4 Depreciation and amortization 228.3 63.7 11.5 303.5 — 49.6 5.4 (21.9) 336.6 Equity in earnings of transmission affiliates — — — — 46.8 — — — 46.8 Interest expense 157.3 23.5 4.0 184.8 4.9 24.1 76.5 (89.7) 200.6 Income tax expense (benefit) 34.4 10.2 0.3 44.9 10.5 (20.2) 6.4 — 41.6 Net income (loss) 132.4 25.7 0.6 158.7 31.4 91.7 (71.8) — 210.0 Net income (loss) attributed to common shareholders 132.1 25.7 0.6 158.4 31.4 93.3 (71.8) — 211.3 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 June 30, 2023 External revenues $ 1,424.5 $ 273.5 $ 81.9 $ 1,779.9 $ — $ 50.0 $ 0.1 $ — $ 1,830.0 Intersegment revenues — — — — — 119.0 — (119.0) — Other operation and maintenance 351.8 105.3 21.8 478.9 — 20.3 0.7 (3.9) 496.0 Depreciation and amortization 210.3 58.5 10.6 279.4 — 48.4 5.2 (19.1) 313.9 Equity in earnings of transmission affiliates — — — — 43.6 — — — 43.6 Interest expense 150.1 21.4 4.1 175.6 4.8 25.1 62.0 (88.8) 178.7 Income tax expense (benefit) 53.6 10.9 1.3 65.8 9.7 (19.7) (7.3) — 48.5 Net income (loss) 185.9 30.1 3.7 219.7 29.1 85.9 (44.7) — 290.0 Net income (loss) attributed to common shareholders 185.6 30.1 3.7 219.4 29.1 85.9 (44.7) — 289.7 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 Six Months Ended June 30, 2024 External revenues $ 3,147.0 $ 942.8 $ 255.6 $ 4,345.4 $ — $ 106.8 $ — $ — $ 4,452.2 Intersegment revenues — — — — — 239.7 — (239.7) — Other operation and maintenance 779.1 209.6 45.2 1,033.9 — 43.2 (7.4) (5.5) 1,064.2 Depreciation and amortization 452.9 127.2 22.9 603.0 — 98.7 11.0 (42.7) 670.0 Equity in earnings of transmission affiliates — — — — 91.6 — — — 91.6 Interest expense 315.1 48.5 8.0 371.6 9.7 48.2 143.1 (180.0) 392.6 Income tax expense (benefit) 109.3 82.3 13.3 204.9 20.4 (43.6) (52.4) — 129.3 Net income (loss) 399.1 213.2 39.2 651.5 61.5 186.0 (66.4) — 832.6 Net income (loss) attributed to common shareholders 398.5 213.2 39.2 650.9 61.5 187.6 (66.4) — 833.6 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 Six Months Ended June 30, 2023 External revenues $ 3,420.8 $ 873.2 $ 331.9 $ 4,625.9 $ — $ 92.1 $ 0.1 $ — $ 4,718.1 Intersegment revenues — — — — — 243.1 — (243.1) — Other operation and maintenance 732.6 219.0 46.5 998.1 — 38.1 (0.7) (5.5) 1,030.0 Depreciation and amortization 417.6 117.0 21.0 555.6 — 91.1 10.3 (37.6) 619.4 Equity in earnings of transmission affiliates — — — — 87.4 — — — 87.4 Interest expense 300.7 43.0 8.3 352.0 9.6 45.0 117.6 (173.3) 350.9 Income tax expense (benefit) 119.5 52.9 12.5 184.9 19.4 (37.5) (44.2) — 122.6 Net income (loss) 443.4 143.2 36.9 623.5 58.4 174.2 (58.5) — 797.6 Net income (loss) attributed to common shareholders 442.8 143.2 36.9 622.9 58.4 174.4 (58.5) — 797.2

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES The primary beneficiary of a VIE must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in VIEs. We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. WEPCo Environmental Trust Finance I, LLC In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to WE's retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized WE to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is a wholly owned subsidiary of WE. In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders 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) June 30, 2024 December 31, 2023 Assets Other current assets (restricted cash) $ 0.3 $ 0.8 Regulatory assets 82.3 85.9 Other long-term assets (restricted cash) 0.3 0.6 Liabilities Current portion of long-term debt 9.1 9.0 Accounts payable 0.1 — Other current liabilities (accrued interest) 0.1 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 June 30, 2024 and December 31, 2023, our equity investment in ATC was $2,029.7 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 June 30, 2024 and December 31, 2023, our equity investment in ATC Holdco was $26.1 million and $25.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco. 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.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	6 Months Ended
	Jun. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	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 June 30, 2024, including those of our subsidiaries, were approximately $10.1 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. National Ambient Air Quality Standards Ozone After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting the reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration; however, in August 2023, the EPA announced that it is instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. This new review is anticipated to take 3 to 5 years to complete. In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023. The effective date for the initial nonattainment area designation was August 2018, and the attainment status is evaluated every 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 SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas. The WDNR intends to submit a SIP revision by the May 2025 deadline. The next attainment evaluation date is August 2024. If the moderate attainment deadline is not met, the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. We are currently evaluating what, if any, impacts the potential 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/m 3 , while retaining the 24-hour standard of 35 µg/m 3 . In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m 3 . The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until 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 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 CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The revisions will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the final rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities. Our 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 in late 2025, the planned retirement of the jointly-owned Columbia Units 1 and 2 by June 2026, and the planned retirement of Weston Unit 3 in 2031. 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 both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our natural gas utility distribution systems. Water Quality Clean Water Act Cooling Water Intake Structure Rule Section 316(b) of the CWA became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities. Effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for WE and WPS facilities. We have received final or interim BTA determinations for all 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 final ELG rule, which took effect in January 2016 ("2015 ELG rule"), was modified in 2020 ("2020 ELG rule"), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect WE and WPS facilities relate to discharge limits for BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP, ERGS, and Weston to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $105 million in capital investment. The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date. The Supplemental ELG Rule also kept one existing and created one new “permanent cessation of coal” subcategory. Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively. For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025. All WE and WPS coal-fueled units fully meet the 2020 ELG rule requirements. Based on current electrical generation resource planning, we plan to file a Notice of Planned Participation by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for both the ERGS and Weston coal-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) June 30, 2024 December 31, 2023 Regulatory assets $ 575.2 $ 596.8 Reserves for future environmental remediation 437.0 463.7 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. 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.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	6 Months Ended
	Jun. 30, 2024
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Non-Cash Transactions Six Months Ended June 30 (in millions) 2024 2023 Cash paid for interest, net of amount capitalized $ 377.7 $ 312.8 Cash paid (received) for income taxes, net (1) (172.8) 15.8 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 167.1 156.7 Common stock issued for stock-based compensation plans 6.4 — Increase in receivables related to insurance proceeds 2.2 5.6 (1) Cash received for income taxes in 2024 includes $173.0 million related to 2023 and 2024 PTCs that were sold to third parties. Restricted Cash The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) June 30, 2024 December 31, 2023 Cash and cash equivalents $ 224.0 $ 42.9 Restricted cash included in other current assets 51.3 70.1 Restricted cash included in other long-term assets 27.6 52.2 Cash, cash equivalents, and restricted cash $ 302.9 $ 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.

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	6 Months Ended
	Jun. 30, 2024
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC 2025 and 2026 Rate Case On April 12, 2024, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2025 and January 1, 2026. The requests reflected the following: WE WPS WG Proposed 2025 rate increase Electric $ 240.7 million / 6.9% $ 110.1 million / 8.5% N/A Gas $ 57.5 million / 10.0% $ 26.8 million / 6.8% $ 67.7 million / 8.2% Steam $ 2.5 million / 8.4% N/A N/A Proposed 2026 rate increase (1) Electric $ 177.9 million / 4.6% $ 64.3 million / 4.5% N/A Gas $ 31.0 million / 4.6% $ 16.1 million / 3.7% $ 30.6 million / 3.3% Proposed ROE 10.0% 10.0% 10.0% Proposed common equity component average on a financial basis 53.5% 53.5% 53.5% (1) The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025. The primary drivers of the requested increases in electric rates are continued capital investments to transition our generation fleets from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW. The requested increases in natural gas rates are driven by the companies' ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates. The utilities also proposed retaining their current earnings sharing mechanism. Under the current earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers. A decision is expected in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025 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. As of June 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. In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2022, is still pending. Annual costs included in the rider have ranged from $192 million to $348 million during these open reconciliation years. As of June 30, 2024, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC. Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations. 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 Case On March 1, 2024, MGU filed a request with the MPSC to increase its retail natural gas base rates by $17.6 million (9.7%). The request reflects a 10.25% ROE and a common equity component average of 50.9%. The proposed natural gas rate increase is primarily driven by inflationary pressure on capital projects and operating and maintenance costs and the significant increase in interest rates over the past few years. The proposed rate increase also includes the expected impacts of the Pipeline and Hazardous Materials Safety Administration's proposed rulemaking titled "Gas Pipeline Leak Detection and Repair." An MPSC decision is anticipated in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025. Upper Michigan Energy Resources Corporation 2024 Rate Case On May 1, 2024, UMERC filed a request with the MPSC to increase its electric base rates for non-mine customers by $11.2 million (13.8%). The request reflects a 10.25% ROE and a common equity component average of 50.0%. The proposed rate increase is primarily driven by the construction of the now in-service RICE generation facilities and a reduction in sales volumes resulting from the implementation of limited retail choice since UMERC’s predecessor utilities last reset rates. A reduction of operation and maintenance costs partially offset these impacts. An MPSC decision is anticipated in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	6 Months Ended
	Jun. 30, 2024
Accounting Changes and Error Corrections [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	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.

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Jun. 30, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

GENERAL INFORMATION (Policies)

GENERAL INFORMATION (Policies)	6 Months Ended
	Jun. 30, 2024
Accounting Policies [Abstract]
Consolidation	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.
Equity method investments	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.
Basis of accounting	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 six months ended June 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.
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.
Income taxes	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 are currently evaluating the impact this guidance may have on our financial statements and related disclosures.
Fair value measurement	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.
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.
Other non-utility revenues
Disaggregation of Operating Revenues
Revenue Recognition	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.

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	6 Months Ended
	Jun. 30, 2024
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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 June 30, 2024 Electric $ 1,148.5 $ — $ — $ 1,148.5 $ — $ — $ — $ 1,148.5 Natural gas 215.1 255.5 63.4 534.0 11.4 — (10.8) 534.6 Total regulated revenues 1,363.6 255.5 63.4 1,682.5 11.4 — (10.8) 1,683.1 Other non-utility revenues — — 4.9 4.9 59.3 — (3.9) 60.3 Total revenues from contracts with customers 1,363.6 255.5 68.3 1,687.4 70.7 — (14.7) 1,743.4 Other operating revenues 4.6 21.3 2.7 28.6 104.9 — (104.9) (1) 28.6 Total operating revenues $ 1,368.2 $ 276.8 $ 71.0 $ 1,716.0 $ 175.6 $ — $ (119.6) $ 1,772.0 (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 June 30, 2023 Electric $ 1,178.5 $ — $ — $ 1,178.5 $ — $ — $ — $ 1,178.5 Natural gas 239.9 260.0 76.9 576.8 14.1 — (13.6) 577.3 Total regulated revenues 1,418.4 260.0 76.9 1,755.3 14.1 — (13.6) 1,755.8 Other non-utility revenues — — 4.7 4.7 53.3 — (3.8) 54.2 Total revenues from contracts with customers 1,418.4 260.0 81.6 1,760.0 67.4 — (17.4) 1,810.0 Other operating revenues 6.1 13.5 0.3 19.9 101.6 0.1 (101.6) (1) 20.0 Total operating revenues $ 1,424.5 $ 273.5 $ 81.9 $ 1,779.9 $ 169.0 $ 0.1 $ (119.0) $ 1,830.0 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2024 Electric $ 2,333.8 $ — $ — $ 2,333.8 $ — $ — $ — $ 2,333.8 Natural gas 801.1 859.3 237.0 1,897.4 25.9 — (25.0) 1,898.3 Total regulated revenues 3,134.9 859.3 237.0 4,231.2 25.9 — (25.0) 4,232.1 Other non-utility revenues — — 9.9 9.9 111.4 — (5.5) 115.8 Total revenues from contracts with customers 3,134.9 859.3 246.9 4,241.1 137.3 — (30.5) 4,347.9 Other operating revenues 12.1 83.5 8.7 104.3 209.2 — (209.2) (1) 104.3 Total operating revenues $ 3,147.0 $ 942.8 $ 255.6 $ 4,345.4 $ 346.5 $ — $ (239.7) $ 4,452.2 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2023 Electric $ 2,382.3 $ — $ — $ 2,382.3 $ — $ — $ — $ 2,382.3 Natural gas 1,024.3 837.7 321.9 2,183.9 35.4 — (34.7) 2,184.6 Total regulated revenues 3,406.6 837.7 321.9 4,566.2 35.4 — (34.7) 4,566.9 Other non-utility revenues — — 9.9 9.9 96.8 — (5.4) 101.3 Total revenues from contracts with customers 3,406.6 837.7 331.8 4,576.1 132.2 — (40.1) 4,668.2 Other operating revenues 14.2 35.5 0.1 49.8 203.0 0.1 (203.0) (1) 49.9 Total operating revenues $ 3,420.8 $ 873.2 $ 331.9 $ 4,625.9 $ 335.2 $ 0.1 $ (243.1) $ 4,718.1 (1) Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.
Revenues from contracts with customers | Electric
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following table disaggregates electric utility operating revenues into customer class: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Residential $ 458.6 $ 459.1 $ 941.8 $ 945.6 Small commercial and industrial 383.6 401.5 775.3 795.1 Large commercial and industrial 224.9 239.9 442.5 469.7 Other 7.2 7.2 15.1 15.2 Total retail revenues 1,074.3 1,107.7 2,174.7 2,225.6 Wholesale 27.7 30.4 53.3 64.6 Resale 37.8 31.9 82.9 72.5 Steam 4.1 4.6 14.3 15.6 Other utility revenues 4.6 3.9 8.6 4.0 Total electric utility operating revenues $ 1,148.5 $ 1,178.5 $ 2,333.8 $ 2,382.3
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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 June 30, 2024 Residential $ 124.9 $ 162.1 $ 30.1 $ 317.1 Commercial and industrial 53.2 41.5 16.2 110.9 Total retail revenues 178.1 203.6 46.3 428.0 Transportation 21.3 52.5 6.2 80.0 Other utility revenues (1) 15.7 (0.6) 10.9 26.0 Total natural gas utility operating revenues $ 215.1 $ 255.5 $ 63.4 $ 534.0 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended June 30, 2023 Residential $ 120.1 $ 180.0 $ 53.6 $ 353.7 Commercial and industrial 50.6 42.4 26.2 119.2 Total retail revenues 170.7 222.4 79.8 472.9 Transportation 20.4 48.8 6.2 75.4 Other utility revenues (1) 48.8 (11.2) (9.1) 28.5 Total natural gas utility operating revenues $ 239.9 $ 260.0 $ 76.9 $ 576.8 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2024 Residential $ 522.5 $ 537.1 $ 141.5 $ 1,201.1 Commercial and industrial 245.0 148.5 70.2 463.7 Total retail revenues 767.5 685.6 211.7 1,664.8 Transportation 51.1 142.6 17.8 211.5 Other utility revenues (1) (17.5) 31.1 7.5 21.1 Total natural gas utility operating revenues $ 801.1 $ 859.3 $ 237.0 $ 1,897.4 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2023 Residential $ 674.9 $ 548.9 $ 218.1 $ 1,441.9 Commercial and industrial 345.8 160.3 117.7 623.8 Total retail revenues 1,020.7 709.2 335.8 2,065.7 Transportation 49.3 125.4 17.1 191.8 Other utility revenues (1) (45.7) 3.1 (31.0) (73.6) Total natural gas utility operating revenues $ 1,024.3 $ 837.7 $ 321.9 $ 2,183.9 (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.
Revenues from contracts with customers | Other non-utility revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Other non-utility operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Wind generation revenues $ 49.3 $ 43.6 $ 93.8 $ 79.6 We Power revenues (1) 6.1 5.9 12.1 11.8 Appliance service revenues 4.9 4.7 9.9 9.9 Total other non-utility operating revenues $ 60.3 $ 54.2 $ 115.8 $ 101.3 (1) As part of the construction of the We Power electric utility generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, which is presented as deferred revenue, net on our balance sheets. We continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE.
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Other operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Late payment charges 14.1 16.2 28.7 33.4 Alternative revenues (1) $ 12.3 $ 2.1 $ 72.8 $ 13.9 Other 2.2 1.7 2.8 2.6 Total other operating revenues $ 28.6 $ 20.0 $ 104.3 $ 49.9 (1) Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

CREDIT LOSSES (Tables)

CREDIT LOSSES (Tables)	6 Months Ended
	Jun. 30, 2024
Credit Loss [Abstract]
Schedule of gross receivables and related allowances for credit losses	We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at June 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 June 30, 2024 Accounts receivable and unbilled revenues $ 966.0 $ 364.0 $ 36.8 $ 1,366.8 $ 37.1 $ 5.7 $ 1,409.6 Allowance for credit losses 68.7 93.2 5.0 166.9 — — 166.9 Accounts receivable and unbilled revenues, net (1) $ 897.3 $ 270.8 $ 31.8 $ 1,199.9 $ 37.1 $ 5.7 $ 1,242.7 Total accounts receivable, net – past due greater than 90 days (1) $ 66.9 $ 56.2 $ 2.4 $ 125.5 $ — $ — $ 125.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 94.4 % 100.0 % — % 95.1 % — % — % 95.1 % (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 June 30, 2024, $729.6 million, or 58.7%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.
Rollforward of the allowances for credit losses by reportable segment	A roll-forward of the allowance for credit losses by reportable segment is included below: Three Months Ended June 30, 2024 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at April 1, 2024 $ 83.0 $ 104.6 $ 3.1 $ 190.7 Provision for credit losses 9.8 12.2 1.7 23.7 Provision for credit losses deferred for future recovery or refund 1.4 (7.5) — (6.1) Write-offs charged against the allowance (35.9) (22.3) (1.1) (59.3) Recoveries of amounts previously written off 10.4 6.2 1.3 17.9 Balance at June 30, 2024 $ 68.7 $ 93.2 $ 5.0 $ 166.9 Six Months Ended June 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 23.6 27.3 (1.3) 49.6 Provision for credit losses deferred for future recovery or refund 17.1 (6.2) — 10.9 Write-offs charged against the allowance (71.5) (50.3) (2.4) (124.2) Recoveries of amounts previously written off 22.1 12.7 2.3 37.1 Balance at June 30, 2024 $ 68.7 $ 93.2 $ 5.0 $ 166.9 On a consolidated basis, there was a $26.6 million decrease in the allowance for credit losses at June 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 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 June 30, 2023 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at April 1, 2023 $ 90.9 $ 116.5 $ 6.4 $ 213.8 Provision for credit losses 6.7 4.8 (0.4) 11.1 Provision for credit losses deferred for future recovery or refund (3.9) (8.5) — (12.4) Write-offs charged against the allowance (29.1) (21.3) (1.1) (51.5) Recoveries of amounts previously written off 11.8 5.5 0.4 17.7 Balance at June 30, 2023 $ 76.4 $ 97.0 $ 5.3 $ 178.7 Six Months Ended June 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 17.9 13.3 0.9 32.1 Provision for credit losses deferred for future recovery or refund 16.5 6.7 — 23.2 Write-offs charged against the allowance (58.0) (44.3) (2.7) (105.0) Recoveries of amounts previously written off 18.0 10.3 0.8 29.1 Balance at June 30, 2023 $ 76.4 $ 97.0 $ 5.3 $ 178.7 On a consolidated basis, there was a $20.6 million decrease in the allowance for credit losses at June 30, 2023, compared to January 1, 2023, 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. Also contributing to the decrease in the allowance for credit losses, we believe that the lower energy costs that customers were seeing, which were 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.

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	(in millions) June 30, 2024 December 31, 2023 Regulatory assets Plant retirement related items (1) $ 824.6 $ 646.2 Pension and OPEB costs 725.1 731.7 Environmental remediation costs 575.2 596.8 Income tax related items 442.8 449.9 AROs 167.1 162.0 Uncollectible expense 123.9 127.7 System support resource 107.9 113.2 Decoupling (2) 102.1 27.3 Securitization 82.3 85.9 Derivatives 62.7 130.3 Bluewater 53.5 45.3 Energy efficiency programs 30.1 33.9 Other, net 137.7 124.5 Total regulatory assets $ 3,435.0 $ 3,274.7 Balance sheet presentation Other current assets $ 41.9 $ 24.9 Regulatory assets 3,393.1 3,249.8 Total regulatory assets $ 3,435.0 $ 3,274.7 (1) Included in plant retirement related items at June 30, 2024, are $116.0 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.
Schedule of regulatory liabilities	(in millions) June 30, 2024 December 31, 2023 Regulatory liabilities Income tax related items $ 1,852.0 $ 1,901.8 Removal costs 1,401.5 1,329.9 Pension and OPEB benefits 300.3 299.2 Energy costs refundable through rate adjustments 143.1 72.4 Derivatives 39.8 19.2 Electric transmission costs 29.5 30.3 Uncollectible expense 24.8 21.2 Energy efficiency programs 19.4 17.2 Other, net 84.2 54.0 Total regulatory liabilities $ 3,894.6 $ 3,745.2 Balance sheet presentation Other current liabilities $ 59.9 $ 47.5 Regulatory liabilities 3,834.7 3,697.7 Total regulatory liabilities $ 3,894.6 $ 3,745.2

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	6 Months Ended
	Jun. 30, 2024
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to asset retirement obligations	The following table shows changes to our AROs: (in millions) 2024 2023 Balance at January 1 $ 374.2 $ 479.3 Accretion 7.4 8.5 Additions 165.7 (1) 16.6 (2) Liabilities settled (3.7) (1.5) Balance at June 30 $ 543.6 $ 502.9 (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.

COMMON EQUITY (Tables)

COMMON EQUITY (Tables)	6 Months Ended
	Jun. 30, 2024
Equity [Abstract]
Schedule of stock-based compensation awards granted	During the six months ended June 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.
Schedule of Common Stock Outstanding Roll Forward	We had the following changes to our outstanding common stock during the three and six months ended June 30, 2024: Three Months Ended June 30, 2024 Six Months Ended June 30, 2024 Common stock shares outstanding at beginning of period 315,822,587 315,434,531 Shares issued: Stock-based compensation 20,488 162,666 401(k) 122,300 246,600 Stock investment plan 114,026 235,604 Common stock shares outstanding at end of period 316,079,401 316,079,401

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	6 Months Ended
	Jun. 30, 2024
Short-Term Debt [Abstract]
Schedule of short-term borrowings and weighted-average interest rates	The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) June 30, 2024 December 31, 2023 Commercial paper Amount outstanding $ 756.8 $ 2,017.2 Weighted-average interest rate on amounts outstanding 5.46 % 5.49 % Operating expense loans Amount outstanding (1) $ 4.5 $ 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.
Schedule of credit agreements and remaining available capacity	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 June 30, 2024 WEC Energy Group September 2026 $ 1,500.0 WEC Energy Group October 2024 200.0 WE September 2026 500.0 WPS September 2026 400.0 WG September 2026 350.0 PGL September 2026 350.0 Total short-term credit capacity $ 3,300.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 756.8 Available capacity under existing agreements $ 2,540.9

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	6 Months Ended
	Jun. 30, 2024
Long-Term Debt, Unclassified [Abstract]
Schedule of convertible debt	The following is a summary of our convertible debt instruments as of June 30, 2024: (in millions) Principal Amount Unamortized Debt Issuance Costs Net Carrying Amount Fair Value Amount (1) 2027 Notes $ 862.5 $ (9.0) $ 853.5 $ 856.4 2029 Notes 862.5 (9.2) 853.3 856.5 (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.
Schedule of convertible debt interest expense	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 June 30, 2024 Six Months Ended June 30, 2024 2027 Notes Contractual interest expense $ 3.5 $ 3.5 Amortization of debt issuance costs 0.3 0.3 Total interest expense - 2027 Notes 3.8 3.8 2029 Notes Contractual interest expense 3.5 3.5 Amortization of debt issuance costs 0.2 0.2 Total interest expense - 2029 Notes $ 3.7 $ 3.7

LEASES (Tables)

LEASES (Tables)	6 Months Ended
	Jun. 30, 2024
Leases [Abstract]
Schedule of future minimum lease payments for Renegade finance lease	Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance lease for Renegade as of June 30, 2024, were as follows: (in millions) Six Months Ended December 31, 2024 $ 0.7 2025 0.3 2026 0.9 2027 0.9 2028 0.9 2029 0.9 Thereafter 70.5 Total minimum lease payments 75.1 Less: Interest (56.4) Present value of minimum lease payments 18.7 Less: Short-term lease liabilities — Long-term lease liabilities $ 18.7

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	6 Months Ended
	Jun. 30, 2024
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventories consisted of: (in millions) June 30, 2024 December 31, 2023 Materials and supplies $ 350.3 $ 320.0 Natural gas in storage 239.0 327.8 Fossil fuel 106.5 127.4 Total $ 695.8 $ 775.2

INCOME TAXES (Tables)

INCOME TAXES (Tables)	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
Schedule of effective income tax rate reconciliation	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 June 30, 2024 Three Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 53.1 21.0 % $ 71.1 21.0 % State income taxes net of federal tax benefit 15.6 6.2 % 21.0 6.2 % PTCs, net (22.2) (8.8) % (33.9) (10.0) % Federal excess deferred tax amortization (4.9) (1.9) % (7.3) (2.2) % Other, net — — % (2.4) (0.7) % Total income tax expense $ 41.6 16.5 % $ 48.5 14.3 % Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 202.2 21.0 % $ 193.2 21.0 % State income taxes net of federal tax benefit 59.0 6.1 % 56.8 6.2 % PTCs, net (110.2) (11.4) % (100.1) (10.9) % Federal excess deferred tax amortization (20.3) (2.1) % (20.4) (2.2) % Other, net (1.4) (0.2) % (6.9) (0.8) % Total income tax expense $ 129.3 13.4 % $ 122.6 13.3 %

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	6 Months Ended
	Jun. 30, 2024
Fair Value Disclosures [Abstract]
Schedule of fair value of assets and liabilities measured on a recurring basis categorized by level within the fair value hierarchy	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: June 30, 2024 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 4.0 $ 9.3 $ — $ 13.3 FTRs and TCRs — — 20.8 20.8 Coal contracts — 0.2 — 0.2 Total derivative assets $ 4.0 $ 9.5 $ 20.8 $ 34.3 Investments held in rabbi trust $ 47.9 $ — $ — $ 47.9 Derivative liabilities Natural gas contracts $ 27.6 $ 13.0 $ — $ 40.6 Coal contracts — 15.7 — 15.7 Total derivative liabilities $ 27.6 $ 28.7 $ — $ 56.3 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
Reconciliation of changes in fair value of items categorized as level 3 measurements	The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Balance at the beginning of the period $ 2.6 $ 3.0 $ 7.2 $ 7.8 Purchases 25.8 19.2 26.8 19.5 Net realized and unrealized losses included in earnings (1) (0.2) (0.2) (1.0) (0.5) Settlements (7.4) (5.2) (12.2) (10.0) Balance at the end of the period $ 20.8 $ 16.8 $ 20.8 $ 16.8 Net unrealized losses included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1) $ (0.2) $ (0.1) $ (0.2) $ (0.1) (1) Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized losses are recorded in operating revenues on our income statements.
Schedule of carrying value and fair value of financial instruments not recorded at fair value	The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: June 30, 2024 December 31, 2023 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 21.2 $ 30.4 $ 21.4 Long-term debt, including current portion (1) 17,900.6 16,632.6 16,631.1 15,564.3 (1) The carrying amount of long-term debt excludes finance lease obligations of $164.6 million and $145.9 million at June 30, 2024 and December 31, 2023, respectively.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	6 Months Ended
	Jun. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative assets and liabilities	The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments. June 30, 2024 December 31, 2023 (in millions) Derivative Derivative Derivative Derivative Current Natural gas contracts $ 13.1 $ 38.4 $ 10.4 $ 78.1 FTRs and TCRs 20.8 — 7.2 — Coal contracts 0.1 10.8 0.3 10.9 Total current 34.0 49.2 17.9 89.0 Long-term Natural gas contracts 0.2 2.2 0.1 8.0 Coal contracts 0.1 4.9 — 9.4 Total long-term 0.3 7.1 0.1 17.4 Total $ 34.3 $ 56.3 $ 18.0 $ 106.4
Schedule of estimated notional sales volumes and realized gains and losses	Our estimated notional sales volumes and realized gains and losses were as follows: Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 48.1 Dth $ (29.8) 47.7 Dth $ (69.1) FTRs and TCRs 7.6 MWh 2.0 7.5 MWh 4.1 Total $ (27.8) $ (65.0) Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 115.9 Dth $ (86.7) 106.4 Dth $ (144.4) FTRs and TCRs 15.2 MWh 3.6 14.8 MWh 4.5 Total $ (83.1) $ (139.9)
Schedule of net derivative instruments	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: June 30, 2024 December 31, 2023 (in millions) Derivative Derivative Derivative Derivative Gross amount recognized on the balance sheet $ 34.3 $ 56.3 $ 18.0 $ 106.4 Gross amount not offset on the balance sheet (4.5) (28.1) (1) (3.1) (71.0) (2) Net amount $ 29.8 $ 28.2 $ 14.9 $ 35.4 (1) Includes cash collateral posted of $23.6 million. (2) Includes cash collateral posted of $67.9 million.

GUARANTEES (Tables)

GUARANTEES (Tables)	6 Months Ended
	Jun. 30, 2024
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees: Total Amounts Committed at June 30, 2024 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 136.5 $ 19.7 $ — $ 116.8 Surety bonds (2) 34.0 32.1 1.9 — Other guarantees (3) 11.0 — — 11.0 Total guarantees $ 181.5 $ 51.8 $ 1.9 $ 127.8 (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.

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	6 Months Ended
	Jun. 30, 2024
Retirement Benefits [Abstract]
Schedule of net benefit cost (credit)	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 June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 5.4 $ 5.4 $ 12.1 $ 12.0 Interest cost 28.8 30.4 58.3 61.2 Expected return on plan assets (45.3) (46.4) (91.1) (93.8) Amortization of prior service cost — — — 0.1 Amortization of net actuarial loss 15.3 9.3 29.7 16.7 Net periodic benefit cost (credit) $ 4.2 $ (1.3) $ 9.0 $ (3.8) OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 2.6 $ 2.4 $ 5.4 $ 4.9 Interest cost 5.7 5.4 11.4 10.8 Expected return on plan assets (13.1) (13.2) (26.3) (26.5) Amortization of prior service credit (3.4) (3.7) (6.8) (7.4) Amortization of net actuarial gain (1.9) (3.0) (3.8) (6.2) Net periodic benefit credit $ (10.1) $ (12.1) $ (20.1) $ (24.4)

GOODWILL AND INTANGIBLES (Table

GOODWILL AND INTANGIBLES (Tables)	6 Months Ended
	Jun. 30, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill balance by segment	The table below shows our goodwill balances by segment at June 30, 2024. We had no changes to the carrying amount of goodwill during the six months ended June 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 June 30, 2024.
Schedule of intangible liabilities obtained through acquisitions by WECI	The intangible liabilities below were all obtained through acquisitions by WECI. June 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 $ (93.0) $ 560.9 $ 653.9 $ (66.6) $ 587.3 Proxy revenue swap (2) 7.2 (3.8) 3.4 7.2 (3.5) 3.7 Interconnection agreements (3) 4.7 (1.0) 3.7 4.7 (0.9) 3.8 Total intangible liabilities $ 665.8 $ (97.8) $ 568.0 $ 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 five years. (3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 16 years.
Schedule of amortization over the next five years	Amortization for the next five years, including amounts recorded through June 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

INVESTMENT IN TRANSMISSION AF_2

INVESTMENT IN TRANSMISSION AFFILIATES (Tables) - Transmission Affiliates	6 Months Ended
	Jun. 30, 2024
Investment in transmission affiliates
Schedule of changes to our investments in transmission affiliates	The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco: Three Months Ended June 30, 2024 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 2,001.6 $ 25.5 $ 2,027.1 Add: Earnings from equity method investment 46.2 0.6 46.8 Add: Capital contributions 18.2 — 18.2 Less: Distributions 36.3 — 36.3 Balance at end of period $ 2,029.7 $ 26.1 $ 2,055.8 Three Months Ended June 30, 2023 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,896.2 $ 25.5 $ 1,921.7 Add: Earnings from equity method investment 43.1 0.5 43.6 Add: Capital contributions 27.2 — 27.2 Less: Distributions 34.7 1.9 36.6 Balance at end of period $ 1,931.8 $ 24.1 $ 1,955.9 Six Months Ended June 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 90.6 1.0 91.6 Add: Capital contributions 30.3 — 30.3 Less: Distributions 72.0 — 72.0 Balance at end of period $ 2,029.7 $ 26.1 $ 2,055.8 Six Months Ended June 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 86.0 1.4 87.4 Add: Capital contributions 33.3 — 33.3 Less: Distributions 72.1 1.9 74.0 Balance at end of period $ 1,931.8 $ 24.1 $ 1,955.9
Schedule of significant related party transactions with ATC	The following table summarizes our significant related party transactions with ATC: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Charges to ATC for services and construction $ 6.3 $ 4.0 $ 11.0 $ 7.8 Charges from ATC for network transmission services 103.2 94.3 206.5 188.8
Schedule of receivables and payables with ATC	Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) June 30, 2024 December 31, 2023 Accounts receivable for services provided to ATC $ 1.6 $ 1.6 Accounts payable for services received from ATC 50.0 49.9 Amounts due from ATC for transmission infrastructure upgrades (1) 42.3 46.1 (1) These transmission infrastructure upgrades were primarily related to the construction of WE's and WPS's renewable energy projects.
Schedule of summarized income statement data for ATC	Summarized financial data for ATC is included in the tables below: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Income statement data Operating revenues $ 218.3 $ 203.8 $ 430.2 $ 404.2 Operating expenses 109.2 101.5 214.0 200.6 Other expense, net 35.8 32.9 71.0 65.4 Net income $ 73.3 $ 69.4 $ 145.2 $ 138.2
Schedule of summarized balance sheet data for ATC	(in millions) June 30, 2024 December 31, 2023 Balance sheet data Current assets $ 146.5 $ 115.2 Noncurrent assets 6,539.3 6,337.0 Total assets $ 6,685.8 $ 6,452.2 Current liabilities $ 586.0 $ 495.9 Long-term debt 2,810.5 2,736.0 Other noncurrent liabilities 573.3 585.2 Members' equity 2,716.0 2,635.1 Total liabilities and members' equity $ 6,685.8 $ 6,452.2

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2024
Segment Reporting [Abstract]
Schedule of financial information related to our reportable segments	The following tables show summarized financial information related to our reportable segments for the three and six months ended June 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 June 30, 2024 External revenues $ 1,368.2 $ 276.8 $ 71.0 $ 1,716.0 $ — $ 56.0 $ — $ — $ 1,772.0 Intersegment revenues — — — — — 119.6 — (119.6) — Other operation and maintenance 389.2 102.6 24.6 516.4 — 25.0 (4.0) (4.0) 533.4 Depreciation and amortization 228.3 63.7 11.5 303.5 — 49.6 5.4 (21.9) 336.6 Equity in earnings of transmission affiliates — — — — 46.8 — — — 46.8 Interest expense 157.3 23.5 4.0 184.8 4.9 24.1 76.5 (89.7) 200.6 Income tax expense (benefit) 34.4 10.2 0.3 44.9 10.5 (20.2) 6.4 — 41.6 Net income (loss) 132.4 25.7 0.6 158.7 31.4 91.7 (71.8) — 210.0 Net income (loss) attributed to common shareholders 132.1 25.7 0.6 158.4 31.4 93.3 (71.8) — 211.3 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 June 30, 2023 External revenues $ 1,424.5 $ 273.5 $ 81.9 $ 1,779.9 $ — $ 50.0 $ 0.1 $ — $ 1,830.0 Intersegment revenues — — — — — 119.0 — (119.0) — Other operation and maintenance 351.8 105.3 21.8 478.9 — 20.3 0.7 (3.9) 496.0 Depreciation and amortization 210.3 58.5 10.6 279.4 — 48.4 5.2 (19.1) 313.9 Equity in earnings of transmission affiliates — — — — 43.6 — — — 43.6 Interest expense 150.1 21.4 4.1 175.6 4.8 25.1 62.0 (88.8) 178.7 Income tax expense (benefit) 53.6 10.9 1.3 65.8 9.7 (19.7) (7.3) — 48.5 Net income (loss) 185.9 30.1 3.7 219.7 29.1 85.9 (44.7) — 290.0 Net income (loss) attributed to common shareholders 185.6 30.1 3.7 219.4 29.1 85.9 (44.7) — 289.7 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 Six Months Ended June 30, 2024 External revenues $ 3,147.0 $ 942.8 $ 255.6 $ 4,345.4 $ — $ 106.8 $ — $ — $ 4,452.2 Intersegment revenues — — — — — 239.7 — (239.7) — Other operation and maintenance 779.1 209.6 45.2 1,033.9 — 43.2 (7.4) (5.5) 1,064.2 Depreciation and amortization 452.9 127.2 22.9 603.0 — 98.7 11.0 (42.7) 670.0 Equity in earnings of transmission affiliates — — — — 91.6 — — — 91.6 Interest expense 315.1 48.5 8.0 371.6 9.7 48.2 143.1 (180.0) 392.6 Income tax expense (benefit) 109.3 82.3 13.3 204.9 20.4 (43.6) (52.4) — 129.3 Net income (loss) 399.1 213.2 39.2 651.5 61.5 186.0 (66.4) — 832.6 Net income (loss) attributed to common shareholders 398.5 213.2 39.2 650.9 61.5 187.6 (66.4) — 833.6 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 Six Months Ended June 30, 2023 External revenues $ 3,420.8 $ 873.2 $ 331.9 $ 4,625.9 $ — $ 92.1 $ 0.1 $ — $ 4,718.1 Intersegment revenues — — — — — 243.1 — (243.1) — Other operation and maintenance 732.6 219.0 46.5 998.1 — 38.1 (0.7) (5.5) 1,030.0 Depreciation and amortization 417.6 117.0 21.0 555.6 — 91.1 10.3 (37.6) 619.4 Equity in earnings of transmission affiliates — — — — 87.4 — — — 87.4 Interest expense 300.7 43.0 8.3 352.0 9.6 45.0 117.6 (173.3) 350.9 Income tax expense (benefit) 119.5 52.9 12.5 184.9 19.4 (37.5) (44.2) — 122.6 Net income (loss) 443.4 143.2 36.9 623.5 58.4 174.2 (58.5) — 797.6 Net income (loss) attributed to common shareholders 442.8 143.2 36.9 622.9 58.4 174.4 (58.5) — 797.2

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of balance sheet impact of WEPCo Environmental Trust	The following table summarizes the impact of WEPCo Environmental Trust on our balance sheets: (in millions) June 30, 2024 December 31, 2023 Assets Other current assets (restricted cash) $ 0.3 $ 0.8 Regulatory assets 82.3 85.9 Other long-term assets (restricted cash) 0.3 0.6 Liabilities Current portion of long-term debt 9.1 9.0 Accounts payable 0.1 — Other current liabilities (accrued interest) 0.1 0.1 Long-term debt 80.9 85.3

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	6 Months Ended
	Jun. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of regulatory assets and reserves related to manufactured gas plant sites	We have established the following regulatory assets and reserves for manufactured gas plant sites: (in millions) June 30, 2024 December 31, 2023 Regulatory assets $ 575.2 $ 596.8 Reserves for future environmental remediation 437.0 463.7

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2024
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Six Months Ended June 30 (in millions) 2024 2023 Cash paid for interest, net of amount capitalized $ 377.7 $ 312.8 Cash paid (received) for income taxes, net (1) (172.8) 15.8 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 167.1 156.7 Common stock issued for stock-based compensation plans 6.4 — Increase in receivables related to insurance proceeds 2.2 5.6 (1) Cash received for income taxes in 2024 includes $173.0 million related to 2023 and 2024 PTCs that were sold to third parties.
Reconciliation of 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) June 30, 2024 December 31, 2023 Cash and cash equivalents $ 224.0 $ 42.9 Restricted cash included in other current assets 51.3 70.1 Restricted cash included in other long-term assets 27.6 52.2 Cash, cash equivalents, and restricted cash $ 302.9 $ 165.2

REGULATORY ENVIRONMENT - (Table

REGULATORY ENVIRONMENT - (Tables)	6 Months Ended
	Jun. 30, 2024
Public Service Commission of Wisconsin (PSCW)
Public Utilities, General Disclosures [Line Items]
Schedule of rate requests	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.

GENERAL INFORMATION - GENERAL (

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Jun. 30, 2024 customer
Electric
Product information [Line Items]
Number Of Customers	1.7
Natural gas
Product information [Line Items]
Number Of Customers	3

GENERAL INFORMATION - INVESTMEN

GENERAL INFORMATION - INVESTMENTS (Details)	Jun. 30, 2024
ATC
Schedule of Investments [Line Items]
Equity method investment, ownership interest (as a percent)	60%

ACQUISITIONS - WEST RIVERSIDE (

ACQUISITIONS - WEST RIVERSIDE (Details) - West Riverside Energy Center - WE $ in Millions	1 Months Ended
	May 31, 2024 USD ($) MW
Asset Acquisition [Line Items]
Capacity of generation unit | MW	100
Acquisition purchase price | $	$ 98.2
Jointly Owned Utility Plant, Proportionate Ownership Share of Capacity | MW	200
Joint plant ownership percentage	27.50%
Asset acquisition, total consideration transferred | $	$ 193.5

ACQUISITIONS - RED BARN (Detail

ACQUISITIONS - RED BARN (Details) - Red Barn Wind Park - WPS $ in Millions	1 Months Ended
	Apr. 30, 2023 USD ($) MW
Asset Acquisition [Line Items]
Capacity of generation unit | MW	82
Acquisition purchase price | $	$ 143.8

ACQUISITIONS - WHITEWATER (Deta

ACQUISITIONS - WHITEWATER (Details) - Whitewater cogeneration facility - WE and WPS $ in Millions	1 Months Ended
	Jan. 31, 2023 USD ($)	Jan. 01, 2023 MW
Asset Acquisition [Line Items]
Capacity of generation unit | MW		236.5
Acquisition purchase price | $	$ 76

ACQUISITIONS - MAPLE FLATS SOLA

ACQUISITIONS - MAPLE FLATS SOLAR (Details) - Maple Flats Solar - WECI $ in Millions	1 Months Ended
	May 31, 2024 USD ($)	Oct. 31, 2022 MW
Asset Acquisition [Line Items]
Ownership interest of solar generating facility acquired		80%
Capacity of generation unit | MW		250
Duration of offtake agreement for the sale of energy produced		15 years
Additional ownership interest acquired	10%
Acquisition purchase price, expected | $	$ 431

ACQUISITIONS - SAPPHIRE SKY (De

ACQUISITIONS - SAPPHIRE SKY (Details) - Sapphire Sky - WECI $ in Millions	1 Months Ended
	Feb. 28, 2023 USD ($) MW
Asset Acquisition [Line Items]
Ownership interest of wind generating facility acquired	90%
Capacity of generation unit | MW	250
Acquisition purchase price | $	$ 442.6
Duration of offtake agreement for the sale of energy produced	12 years

ACQUISITIONS - DELILAH I (Detai

ACQUISITIONS - DELILAH I (Details) - Delilah Solar Energy LLC - WECI $ in Millions	1 Months Ended
	Mar. 31, 2024 USD ($) MW
Asset Acquisition [Line Items]
Ownership interest of solar generating facility acquired	90%
Capacity of generation unit | MW	300
Acquisition purchase price, expected | $	$ 459
Duration of offtake agreement for the sale of energy produced	15 years

ACQUISITIONS - SAMSON I (Detail

ACQUISITIONS - SAMSON I (Details) - Samson I Solar Energy Center - WECI $ in Millions	1 Months Ended
	Feb. 28, 2023 USD ($) MW	Jan. 31, 2024 USD ($)
Asset Acquisition [Line Items]
Ownership interest of solar generating facility acquired	80%
Capacity of generation unit | MW	250
Acquisition purchase price	$ 257.3
Duration of offtake agreement for the sale of energy produced	15 years
Additional ownership interest acquired		10%
Additional acquisition purchase price		$ 28.1

DISPOSITIONS - WE (Details)

DISPOSITIONS - WE (Details) - WE $ in Millions	3 Months Ended
	Jun. 30, 2023 USD ($) a
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of Acres Sold | a	192
Proceeds from sale of real estate	$ 23
Pre-tax gain on sale of real estate	$ 22.2

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Total operating revenues	$ 1,772	$ 1,830	$ 4,452.2	$ 4,718.1
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,743.4	1,810	4,347.9	4,668.2
Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	28.6	20	104.3	49.9
Utility operations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,683.1	1,755.8	4,232.1	4,566.9
Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,148.5	1,178.5	2,333.8	2,382.3
Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	534.6	577.3	1,898.3	2,184.6
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	60.3	54.2	115.8	101.3
Reconciling Eliminations
Disaggregation of Operating Revenues
Total operating revenues	(119.6)	(119)	(239.7)	(243.1)
Reconciling Eliminations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(14.7)	(17.4)	(30.5)	(40.1)
Reconciling Eliminations | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	(104.9)	(101.6)	(209.2)	(203)
Reconciling Eliminations | Utility operations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(10.8)	(13.6)	(25)	(34.7)
Reconciling Eliminations | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Reconciling Eliminations | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(10.8)	(13.6)	(25)	(34.7)
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(3.9)	(3.8)	(5.5)	(5.4)
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	534	576.8	1,897.4	2,183.9
Total Utility Operations | Operating Segments
Disaggregation of Operating Revenues
Total operating revenues	1,716	1,779.9	4,345.4	4,625.9
Total Utility Operations | Operating Segments | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	28.6	19.9	104.3	49.8
Total Utility Operations | Operating Segments | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,687.4	1,760	4,241.1	4,576.1
Total Utility Operations | Operating Segments | Utility operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,682.5	1,755.3	4,231.2	4,566.2
Total Utility Operations | Operating Segments | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,148.5	1,178.5	2,333.8	2,382.3
Total Utility Operations | Operating Segments | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	534	576.8	1,897.4	2,183.9
Total Utility Operations | Operating Segments | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.9	4.7	9.9	9.9
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,148.5	1,178.5	2,333.8	2,382.3
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	215.1	239.9	801.1	1,024.3
Wisconsin | Operating Segments
Disaggregation of Operating Revenues
Total operating revenues	1,368.2	1,424.5	3,147	3,420.8
Wisconsin | Operating Segments | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	4.6	6.1	12.1	14.2
Wisconsin | Operating Segments | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,363.6	1,418.4	3,134.9	3,406.6
Wisconsin | Operating Segments | Utility operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,363.6	1,418.4	3,134.9	3,406.6
Wisconsin | Operating Segments | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,148.5	1,178.5	2,333.8	2,382.3
Wisconsin | Operating Segments | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	215.1	239.9	801.1	1,024.3
Wisconsin | Operating Segments | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Illinois | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	255.5	260	859.3	837.7
Illinois | Operating Segments
Disaggregation of Operating Revenues
Total operating revenues	276.8	273.5	942.8	873.2
Illinois | Operating Segments | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	21.3	13.5	83.5	35.5
Illinois | Operating Segments | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	255.5	260	859.3	837.7
Illinois | Operating Segments | Utility operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	255.5	260	859.3	837.7
Illinois | Operating Segments | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Illinois | Operating Segments | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	255.5	260	859.3	837.7
Illinois | Operating Segments | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Other States | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	63.4	76.9	237	321.9
Other States | Operating Segments
Disaggregation of Operating Revenues
Total operating revenues	71	81.9	255.6	331.9
Other States | Operating Segments | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	2.7	0.3	8.7	0.1
Other States | Operating Segments | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	68.3	81.6	246.9	331.8
Other States | Operating Segments | Utility operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	63.4	76.9	237	321.9
Other States | Operating Segments | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Other States | Operating Segments | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	63.4	76.9	237	321.9
Other States | Operating Segments | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.9	4.7	9.9	9.9
Non-Utility Energy Infrastructure | Operating Segments
Disaggregation of Operating Revenues
Total operating revenues	175.6	169	346.5	335.2
Non-Utility Energy Infrastructure | Operating Segments | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	70.7	67.4	137.3	132.2
Non-Utility Energy Infrastructure | Operating Segments | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	104.9	101.6	209.2	203
Non-Utility Energy Infrastructure | Operating Segments | Utility operations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	11.4	14.1	25.9	35.4
Non-Utility Energy Infrastructure | Operating Segments | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Non-Utility Energy Infrastructure | Operating Segments | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	11.4	14.1	25.9	35.4
Non-Utility Energy Infrastructure | Operating Segments | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	59.3	53.3	111.4	96.8
Corporate and Other | Operating Segments
Disaggregation of Operating Revenues
Total operating revenues	0	0.1	0	0.1
Corporate and Other | Operating Segments | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Operating Segments | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	0	0.1	0	0.1
Corporate and Other | Operating Segments | Utility operations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Operating Segments | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Operating Segments | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Operating Segments | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 0	$ 0	$ 0	$ 0

OPERATING REVENUES - DISAGGRE_2

OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 1,743.4	$ 1,810	$ 4,347.9	$ 4,668.2
Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,148.5	1,178.5	2,333.8	2,382.3
Wisconsin | Electric | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,148.5	1,178.5	2,333.8	2,382.3
Wisconsin | Electric | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,074.3	1,107.7	2,174.7	2,225.6
Wisconsin | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	458.6	459.1	941.8	945.6
Wisconsin | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	383.6	401.5	775.3	795.1
Wisconsin | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	224.9	239.9	442.5	469.7
Wisconsin | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.2	7.2	15.1	15.2
Wisconsin | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	27.7	30.4	53.3	64.6
Wisconsin | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	37.8	31.9	82.9	72.5
Wisconsin | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.1	4.6	14.3	15.6
Wisconsin | Electric | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 4.6	$ 3.9	$ 8.6	$ 4

OPERATING REVENUES - DISAGGRE_3

OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 1,743.4	$ 1,810	$ 4,347.9	$ 4,668.2
Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	534.6	577.3	1,898.3	2,184.6
Total Utility Operations | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	534	576.8	1,897.4	2,183.9
Total Utility Operations | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	428	472.9	1,664.8	2,065.7
Total Utility Operations | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	317.1	353.7	1,201.1	1,441.9
Total Utility Operations | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	110.9	119.2	463.7	623.8
Total Utility Operations | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	80	75.4	211.5	191.8
Total Utility Operations | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	26	28.5	21.1	(73.6)
Wisconsin | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	215.1	239.9	801.1	1,024.3
Wisconsin | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	178.1	170.7	767.5	1,020.7
Wisconsin | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	124.9	120.1	522.5	674.9
Wisconsin | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	53.2	50.6	245	345.8
Wisconsin | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	21.3	20.4	51.1	49.3
Wisconsin | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	15.7	48.8	(17.5)	(45.7)
Illinois | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	255.5	260	859.3	837.7
Illinois | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	203.6	222.4	685.6	709.2
Illinois | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	162.1	180	537.1	548.9
Illinois | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	41.5	42.4	148.5	160.3
Illinois | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	52.5	48.8	142.6	125.4
Illinois | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	(0.6)	(11.2)	31.1	3.1
Other States | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	63.4	76.9	237	321.9
Other States | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	46.3	79.8	211.7	335.8
Other States | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	30.1	53.6	141.5	218.1
Other States | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	16.2	26.2	70.2	117.7
Other States | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	6.2	6.2	17.8	17.1
Other States | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 10.9	$ (9.1)	$ 7.5	$ (31)

OPERATING REVENUES - OTHER NON-

OPERATING REVENUES - OTHER NON-UTILITY OPERATING REVENUES (Details) - Revenues from contracts with customers - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 1,743.4	$ 1,810	$ 4,347.9	$ 4,668.2
Other non-utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	60.3	54.2	115.8	101.3
Other non-utility revenues | We Power revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	6.1	5.9	12.1	11.8
Transferred over time | Other non-utility revenues | Wind generation revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	49.3	43.6	93.8	79.6
Transferred over time | Other non-utility revenues | Appliance service revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 4.9	$ 4.7	$ 9.9	$ 9.9

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Other operating revenues - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Other operating revenues	$ 28.6	$ 20	$ 104.3	$ 49.9
Late payment charges
Disaggregation of Operating Revenues
Other operating revenues	14.1	16.2	28.7	33.4
Alternative revenues
Disaggregation of Operating Revenues
Other operating revenues	12.3	2.1	72.8	13.9
Other
Disaggregation of Operating Revenues
Other operating revenues	$ 2.2	$ 1.7	$ 2.8	$ 2.6

CREDIT LOSSES - GROSS RECEIVABL

CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,409.6		$ 1,696.7
Allowance for credit losses	166.9	$ 190.7	193.5	$ 178.7	$ 213.8	$ 199.3
Accounts receivable and unbilled revenues, net	1,242.7		1,503.2
Total accounts receivable, net - past due greater than 90 days	$ 125.5		$ 98.8
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	95.10%		94.50%
Amount of net accounts receivable with regulatory protections	$ 729.6
Percent of net accounts receivable with regulatory protections	58.70%
Public Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,366.8		$ 1,654.4
Allowance for credit losses	166.9		193.5
Accounts receivable and unbilled revenues, net	1,199.9		1,460.9
Total accounts receivable, net - past due greater than 90 days	$ 125.5		$ 98.8
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	95.10%		94.50%
Wisconsin | Public Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 966		$ 1,078
Allowance for credit losses	68.7	83	77.4	76.4	90.9	82
Accounts receivable and unbilled revenues, net	897.3		1,000.6
Total accounts receivable, net - past due greater than 90 days	$ 66.9		$ 51.7
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	94.40%		93.60%
Illinois | Public Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 364		$ 481.5
Allowance for credit losses	93.2	104.6	109.7	97	116.5	111
Accounts receivable and unbilled revenues, net	270.8		371.8
Total accounts receivable, net - past due greater than 90 days	$ 56.2		$ 45
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	100%		100%
Other States | Public Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 36.8		$ 94.9
Allowance for credit losses	5	$ 3.1	6.4	$ 5.3	$ 6.4	$ 6.3
Accounts receivable and unbilled revenues, net	31.8		88.5
Total accounts receivable, net - past due greater than 90 days	$ 2.4		$ 2.1
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	0%		0%
Non-Utility Energy Infrastructure
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 37.1		$ 33.9
Allowance for credit losses	0		0
Accounts receivable and unbilled revenues, net	37.1		33.9
Total accounts receivable, net - past due greater than 90 days	$ 0		$ 0
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	0%		0%
Corporate and Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 5.7		$ 8.4
Allowance for credit losses	0		0
Accounts receivable and unbilled revenues, net	5.7		8.4
Total accounts receivable, net - past due greater than 90 days	$ 0		$ 0
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	0%		0%

CREDIT LOSSES - ROLLFORWARD OF

CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	$ 190.7	$ 213.8	$ 193.5	$ 199.3
Provision for credit losses	23.7	11.1	49.6	32.1
Write-offs charged against the allowance	(59.3)	(51.5)	(124.2)	(105)
Recovery of amounts previously written off	17.9	17.7	37.1	29.1
Balance at end of period	166.9	178.7	166.9	178.7
Change in allowance for credit losses			26.6	20.6
Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	(6.1)	(12.4)	10.9	23.2
Public Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period			193.5
Balance at end of period	166.9		166.9
Wisconsin | Public Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	83	90.9	77.4	82
Provision for credit losses	9.8	6.7	23.6	17.9
Write-offs charged against the allowance	(35.9)	(29.1)	(71.5)	(58)
Recovery of amounts previously written off	10.4	11.8	22.1	18
Balance at end of period	68.7	76.4	68.7	76.4
Wisconsin | Public Utilities | Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	1.4	(3.9)	17.1	16.5
Illinois | Public Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	104.6	116.5	109.7	111
Provision for credit losses	12.2	4.8	27.3	13.3
Write-offs charged against the allowance	(22.3)	(21.3)	(50.3)	(44.3)
Recovery of amounts previously written off	6.2	5.5	12.7	10.3
Balance at end of period	93.2	97	93.2	97
Illinois | Public Utilities | Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	(7.5)	(8.5)	(6.2)	6.7
Other States | Public Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	3.1	6.4	6.4	6.3
Provision for credit losses	1.7	(0.4)	(1.3)	0.9
Write-offs charged against the allowance	(1.1)	(1.1)	(2.4)	(2.7)
Recovery of amounts previously written off	1.3	0.4	2.3	0.8
Balance at end of period	5	5.3	5	5.3
Other States | Public Utilities | Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	$ 0	$ 0	$ 0	$ 0

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Regulatory assets
Other current assets	$ 41.9	$ 24.9
Regulatory assets	3,393.1	3,249.8
Total regulatory assets	3,435	3,274.7
Plant retirement related items
Regulatory assets
Total regulatory assets	824.6	646.2
Plant retirement related items | Coal Combustion Residuals Rule
Regulatory assets
Total regulatory assets	116
Pension and OPEB costs
Regulatory assets
Total regulatory assets	725.1	731.7
Environmental remediation costs
Regulatory assets
Total regulatory assets	575.2	596.8
Income tax related items
Regulatory assets
Total regulatory assets	442.8	449.9
Asset retirement obligations
Regulatory assets
Total regulatory assets	167.1	162
Uncollectible expense
Regulatory assets
Total regulatory assets	123.9	127.7
System support resource
Regulatory assets
Total regulatory assets	107.9	113.2
Decoupling
Regulatory assets
Total regulatory assets	102.1	27.3
Securitization
Regulatory assets
Total regulatory assets	82.3	85.9
Derivatives
Regulatory assets
Total regulatory assets	62.7	130.3
Bluewater
Regulatory assets
Total regulatory assets	53.5	45.3
Energy efficiency programs
Regulatory assets
Total regulatory assets	30.1	33.9
Other, net
Regulatory assets
Total regulatory assets	$ 137.7	$ 124.5

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Regulatory liabilities
Other current liabilities	$ 59.9	$ 47.5
Regulatory liabilities	3,834.7	3,697.7
Total regulatory liabilities	3,894.6	3,745.2
Income tax related items
Regulatory liabilities
Total regulatory liabilities	1,852	1,901.8
Removal costs
Regulatory liabilities
Total regulatory liabilities	1,401.5	1,329.9
Pension and OPEB benefits
Regulatory liabilities
Total regulatory liabilities	300.3	299.2
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	143.1	72.4
Derivatives
Regulatory liabilities
Total regulatory liabilities	39.8	19.2
Electric transmission costs
Regulatory liabilities
Total regulatory liabilities	29.5	30.3
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	24.8	21.2
Energy efficiency programs
Regulatory liabilities
Total regulatory liabilities	19.4	17.2
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 84.2	$ 54

REGULATORY ASSETS AND LIABILI_5

REGULATORY ASSETS AND LIABILITIES - PLANT RETIREMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Oak Creek Power Plant Units 5 and 6
Regulatory assets	$ 3,435	$ 3,274.7
Regulatory liability	3,894.6	3,745.2
Removal costs
Oak Creek Power Plant Units 5 and 6
Regulatory liability	1,401.5	1,329.9
Plant retirement related items
Oak Creek Power Plant Units 5 and 6
Regulatory assets	824.6	$ 646.2
Oak Creek Power Plant Units 5 and 6
Oak Creek Power Plant Units 5 and 6
Deferred tax liabilities	9.4
Oak Creek Power Plant Units 5 and 6 | Removal costs
Oak Creek Power Plant Units 5 and 6
Regulatory liability	43.9
Oak Creek Power Plant Units 5 and 6 | Plant retirement related items
Oak Creek Power Plant Units 5 and 6
Regulatory assets	$ 78.3

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT - PLANT TO BE RETIRED (Details) $ in Millions	Jun. 30, 2024 USD ($)	May 31, 2024 MW
WE | OCPP
Property, plant, and equipment
Net book value of plant to be retired	$ 675.8
WE | West Riverside Energy Center
Property, plant, and equipment
Jointly Owned Utility Plant, Proportionate Ownership Share of Capacity | MW		200
WPS | Columbia Energy Center
Property, plant, and equipment
Net book value of plant to be retired	$ 252.1

PROPERTY, PLANT, AND EQUIPMEN_2

PROPERTY, PLANT, AND EQUIPMENT - SAMSON I SOLAR ENERGY CENTER LLC (Details) - Samson I Solar Energy Center - Samson I Solar Energy Center $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($)
Property, plant, and equipment
Impairment of Samson I	$ 2.3
Insurance receivable	$ 2.3

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Balance at January 1	$ 374.2	$ 479.3
Accretion	7.4	8.5
Additions	165.7	16.6
Liabilities settled	(3.7)	(1.5)
Balance at June 30	$ 543.6	$ 502.9

COMMON EQUITY - STOCK-BASED COM

COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details)	6 Months Ended
	Jun. 30, 2024 $ / shares shares
Stock options
Stock-based compensation
Stock options granted | shares	294,990
Stock options granted, weighted average exercise price | $ / shares	$ 84.92
Stock options granted, weighted-average grant date fair value | $ / shares	$ 16.19
Restricted shares
Stock-based compensation
Awards granted | shares	108,484
Restricted shares granted, weighted-average grant date fair value | $ / shares	$ 84.97
Performance units
Stock-based compensation
Awards granted | shares	205,051

COMMON EQUITY - COMMON STOCK IS

COMMON EQUITY - COMMON STOCK ISSUED (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Equity [Abstract]
Stock Issued During Period, Shares, New Issues		0		0
Roll Forward of Common Stock Outstanding
Common Stock, Shares, Outstanding, Beginning Balance	315,822,587		315,434,531
Shares Issued - Stock-based compensation	20,488		162,666
Stock Issued - 401(k)	122,300		246,600
Stock Issued - Stock investment plan	114,026		235,604
Common Stock, Shares, Outstanding, Ending Balance	316,079,401		316,079,401

COMMON EQUITY - COMMON STOCK DI

COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares		3 Months Ended
	Jul. 18, 2024	Jun. 30, 2024	Mar. 31, 2024	Jun. 30, 2023	Mar. 31, 2023
Dividends payable
Common stock dividend declared (in dollars per share)		$ 0.8350	$ 0.8350	$ 0.7800	$ 0.7800
Subsequent event
Dividends payable
Common stock dividend declared (in dollars per share)	$ 0.835

SHORT-TERM DEBT AND LINES OF _3

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 756.8	$ 2,017.2
Weighted average interest rate on amounts outstanding	5.46%	5.49%
Average amount of commercial paper outstanding during the period	$ 1,836.4
Weighted-average interest rate on amounts outstanding during the period	5.50%
Operating expense loans
Short-term borrowings
Operating expense loan outstanding	$ 4.5	$ 3.7

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Revolving credit facilities
Short-term credit capacity	$ 3,300
Available capacity under existing credit facility	2,540.9
Letter of credit
Revolving credit facilities
Letters of credit issued inside credit facilities	2.3
Commercial paper
Revolving credit facilities
Commercial paper outstanding	756.8	$ 2,017.2
WE | Credit facility maturing September 2026
Revolving credit facilities
Short-term credit capacity	500
WPS | Credit facility maturing September 2026
Revolving credit facilities
Short-term credit capacity	400
WG | Credit facility maturing September 2026
Revolving credit facilities
Short-term credit capacity	350
PGL | Credit facility maturing September 2026
Revolving credit facilities
Short-term credit capacity	350
WEC Energy Group | Credit facility maturing September 2026
Revolving credit facilities
Short-term credit capacity	1,500
WEC Energy Group | Credit facility maturing October 2024
Revolving credit facilities
Short-term credit capacity	$ 200

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details)		1 Months Ended		3 Months Ended		6 Months Ended
	Feb. 07, 2024 USD ($)	May 31, 2024 USD ($)	Mar. 31, 2024 USD ($)	Jun. 30, 2024 USD ($) d $ / shares	Jun. 30, 2023 USD ($)	Jun. 30, 2024 USD ($) $ / shares shares	Jun. 30, 2023 USD ($)
Debt Instrument [Line Items]
Interest expense				$ 200,600,000	$ 178,700,000	$ 392,600,000	$ 350,900,000
5.00% WE Debentures due 05/15/2029 | WE
Debt Instrument [Line Items]
Interest rate on long-term debt		5%
Proceeds from issuance of debt		$ 350,000,000
WEC Energy Group | Floating Rate WEC Energy Group Junior Notes Due 2067
Debt Instrument [Line Items]
Extinguishment of debt	$ 122,100,000	19,000,000
Unsecured debt	500,000,000	377,900,000
Repayment of long-term debt	115,200,000	$ 18,700,000
Gain on early extinguishment of debt	$ 6,900,000
WEC Energy Group | WEC 0.80% Senior Notes $600M due March 15, 2024
Debt Instrument [Line Items]
Repayment of long-term debt			$ 600,000,000
Interest rate on long-term debt			0.80%
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2027
Debt Instrument [Line Items]
Interest rate on long-term debt				4.375%		4.375%
Proceeds from issuance of debt				$ 862,500,000
Initial conversion ratio				10.1243
Principal amount conversion rate applied to				$ 1,000		$ 1,000
Initial conversion price, per share | $ / shares				$ 98.77		$ 98.77
Senior Notes				$ 862,500,000		$ 862,500,000
Unamortized debt issuance costs				(9,000,000)		(9,000,000)
Net carrying amount				853,500,000		853,500,000
Fair value amount				856,400,000		856,400,000
Contractual interest expense				3,500,000		3,500,000
Amortization of debt issuance costs				300,000		300,000
Interest expense				$ 3,800,000		$ 3,800,000
Number of shares outstanding related to the potential conversion of the Notes included in diluted eps | shares						0
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2027 | Early redemption terms
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage				100%
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2027 | Debt conversion terms one
Debt Instrument [Line Items]
Threshold percentage of trigger				130%
Trading days | d				20
Consecutive trading days | d				30
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2027 | Debt conversion terms two
Debt Instrument [Line Items]
Threshold percentage of trigger				98%
Trading days | d				5
Consecutive trading days | d				10
Principal amount conversion rate applied to				$ 1,000		$ 1,000
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2027 | Debt conversion terms four
Debt Instrument [Line Items]
Trading days prior to maturity | d				2
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2029
Debt Instrument [Line Items]
Interest rate on long-term debt				4.375%		4.375%
Proceeds from issuance of debt				$ 862,500,000
Initial conversion ratio				10.1243
Principal amount conversion rate applied to				$ 1,000		$ 1,000
Initial conversion price, per share | $ / shares				$ 98.77		$ 98.77
Senior Notes				$ 862,500,000		$ 862,500,000
Unamortized debt issuance costs				(9,200,000)		(9,200,000)
Net carrying amount				853,300,000		853,300,000
Fair value amount				856,500,000		856,500,000
Contractual interest expense				3,500,000		3,500,000
Amortization of debt issuance costs				200,000		200,000
Interest expense				$ 3,700,000		$ 3,700,000
Number of shares outstanding related to the potential conversion of the Notes included in diluted eps | shares						0
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2029 | Early redemption terms
Debt Instrument [Line Items]
Trading days prior to early redemption | d				41
Threshold percentage of trigger				130%
Trading days | d				20
Consecutive trading days | d				30
Debt instrument, redemption price, percentage				100%
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2029 | Debt conversion terms one
Debt Instrument [Line Items]
Threshold percentage of trigger				130%
Trading days | d				20
Consecutive trading days | d				30
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2029 | Debt conversion terms two
Debt Instrument [Line Items]
Threshold percentage of trigger				98%
Trading days | d				5
Consecutive trading days | d				10
Principal amount conversion rate applied to				$ 1,000		$ 1,000
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2029 | Debt conversion terms three
Debt Instrument [Line Items]
Trading days prior to redemption | d				2
WEC Energy Group | WEC 4.375% Convertible Notes due June 1, 2029 | Debt conversion terms four
Debt Instrument [Line Items]
Trading days prior to maturity | d				2

LEASES - LAND LEASES - RENEGADE

LEASES - LAND LEASES - RENEGADE (Details) - Land Lease - Utility Solar Generation - UMERC $ in Millions	Jun. 30, 2024 USD ($)
Leases
Lease initial term	25 years
Renewal term	25 years
Finance lease obligations	$ 18.7
Finance lease right of use asset	$ 18.7
Weighted average discount rate - finance leases	5.86%

LEASES - RENEGADE FUTURE MINIMU

LEASES - RENEGADE FUTURE MINIMUM LEASE PAYMENTS (Details) - Land Lease - Utility Solar Generation - UMERC $ in Millions	Jun. 30, 2024 USD ($)
Leases
Six months ended December 31, 2024	$ 0.7
2025	0.3
2026	0.9
2027	0.9
2028	0.9
2029	0.9
Thereafter	70.5
Total minimum lease payments	75.1
Less: interest	(56.4)
Present value of minimum lease payments	18.7
Less: short-term lease liabilities	0
Long-term lease liabilities	$ 18.7

LEASES - KOSHKONONG (Details)

LEASES - KOSHKONONG (Details)	Jul. 30, 2024 MW
Koshkonong Solar Park | Wisconsin Electric Power Company And Wisconsin Public Service Corporation | Subsequent event
Leases
Jointly owned utility plant, proportionate ownership share of solar capacity	270

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Energy Related Inventory
Materials and supplies	$ 350.3	$ 320
Natural gas in storage	239	327.8
Fossil fuel	106.5	127.4
Total	695.8	$ 775.2
LIFO Method Related Items
LIFO liquidation debit	$ 0.3

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount	$ 53.1	$ 71.1	$ 202.2	$ 193.2
State income taxes net of federal tax benefit, amount	15.6	21	59	56.8
PTCs, net, amount	(22.2)	(33.9)	(110.2)	(100.1)
Federal excess deferred tax amortization, amount	(4.9)	(7.3)	(20.3)	(20.4)
Other, net, amount	0	(2.4)	(1.4)	(6.9)
Total income tax expense, amount	$ 41.6	$ 48.5	$ 129.3	$ 122.6
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage	21%	21%	21%	21%
State income taxes net of federal tax benefit, percentage	6.20%	6.20%	6.10%	6.20%
PTCs, net, percentage	(8.80%)	(10.00%)	(11.40%)	(10.90%)
Federal excess deferred tax amortization, percentage	(1.90%)	(2.20%)	(2.10%)	(2.20%)
Other, net, percentage	0%	(0.70%)	(0.20%)	(0.80%)
Total income tax expense, percent	16.50%	14.30%	13.40%	13.30%

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Assets
Derivative assets	$ 34.3	$ 18
Liabilities
Derivative liabilities	56.3	106.4
Fair value measurements on a recurring basis
Assets
Derivative assets	34.3	18
Investments held in rabbi trust	47.9	51.7
Liabilities
Derivative liabilities	56.3	106.4
Fair value measurements on a recurring basis | Level 1
Assets
Derivative assets	4	2.2
Investments held in rabbi trust	47.9	51.7
Liabilities
Derivative liabilities	27.6	70.1
Fair value measurements on a recurring basis | Level 2
Assets
Derivative assets	9.5	8.6
Investments held in rabbi trust	0	0
Liabilities
Derivative liabilities	28.7	36.3
Fair value measurements on a recurring basis | Level 3
Assets
Derivative assets	20.8	7.2
Investments held in rabbi trust	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative assets	13.3	10.5
Liabilities
Derivative liabilities	40.6	86.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative assets	4	2.2
Liabilities
Derivative liabilities	27.6	70.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative assets	9.3	8.3
Liabilities
Derivative liabilities	13	16
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | FTRs and TCRs
Assets
Derivative assets	20.8	7.2
Fair value measurements on a recurring basis | FTRs and TCRs | Level 1
Assets
Derivative assets	0	0
Fair value measurements on a recurring basis | FTRs and TCRs | Level 2
Assets
Derivative assets	0	0
Fair value measurements on a recurring basis | FTRs and TCRs | Level 3
Assets
Derivative assets	20.8	7.2
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative assets	0.2	0.3
Liabilities
Derivative liabilities	15.7	20.3
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative assets	0.2	0.3
Liabilities
Derivative liabilities	15.7	20.3
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative assets	0	0
Liabilities
Derivative liabilities	$ 0	$ 0

FAIR VALUE MEASUREMENTS - UNREA

FAIR VALUE MEASUREMENTS - UNREALIZED GAIN OR LOSS ON INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Fair Value Disclosures [Abstract]
Net unrealized gains included in earnings related to investments held at end of period	$ 1.5	$ 3.6	$ 5.2	$ 6.4

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Level 3 rollforward
Balance at the beginning of the period	$ 2.6	$ 3	$ 7.2	$ 7.8
Purchases	25.8	19.2	26.8	19.5
Net realized and unrealized losses included in earnings	(0.2)	(0.2)	(1)	(0.5)
Settlements	(7.4)	(5.2)	(12.2)	(10)
Balance at the end of the period	20.8	16.8	20.8	16.8
Net unrealized losses included in earnings attributable to level 3 derivatives held at the end of the reporting period	$ (0.2)	$ (0.1)	$ (0.2)	$ (0.1)

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Financial instruments
Preferred stock of subsidiary	$ 30.4	$ 30.4
Carrying amount
Financial instruments
Preferred stock of subsidiary	30.4	30.4
Long-term debt, including current portion	17,900.6	16,631.1
Finance lease obligations	164.6	145.9
Fair value
Financial instruments
Preferred stock of subsidiary	21.2	21.4
Long-term debt, including current portion	$ 16,632.6	$ 15,564.3

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) $ in Millions	Jun. 30, 2024 USD ($) Instruments	Dec. 31, 2023 USD ($) Instruments
Derivative assets
Current derivative assets	$ 34	$ 17.9
Long-term derivative assets	0.3	0.1
Total derivative assets	$ 34.3	$ 18
Current derivative assets balance sheet location	Other	Other
Long-term derivative assets balance sheet location	Other Assets, Noncurrent	Other Assets, Noncurrent
Derivative liabilities
Current derivative liabilities	$ 49.2	$ 89
Long-term derivative liabilities	7.1	17.4
Derivative liabilities	$ 56.3	$ 106.4
Current derivative liabilities balance sheet location	Other Liabilities, Current	Other Liabilities, Current
Long-term derivative liabilities balance sheet location	Other noncurrent liabilities	Other noncurrent liabilities
Natural gas contracts
Derivative assets
Current derivative assets	$ 13.1	$ 10.4
Long-term derivative assets	0.2	0.1
Derivative liabilities
Current derivative liabilities	38.4	78.1
Long-term derivative liabilities	2.2	8
FTRs and TCRs
Derivative assets
Current derivative assets	20.8	7.2
Derivative liabilities
Current derivative liabilities	0	0
Coal contracts
Derivative assets
Current derivative assets	0.1	0.3
Long-term derivative assets	0.1	0
Derivative liabilities
Current derivative liabilities	10.8	10.9
Long-term derivative liabilities	$ 4.9	$ 9.4
Designated as hedging instrument
Derivative instruments
Number of derivative instruments | Instruments	0	0

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024 USD ($) MMBTU MWh	Jun. 30, 2023 USD ($) MMBTU MWh	Jun. 30, 2024 USD ($) MMBTU MWh	Jun. 30, 2023 USD ($) MWh MMBTU
Realized gains and losses
Gains (losses)	$ (27.8)	$ (65)	$ (83.1)	$ (139.9)
Natural gas contracts
Realized gains and losses
Gains (losses)	$ (29.8)	$ (69.1)	$ (86.7)	$ (144.4)
Notional sales volumes
Notional sales volumes | MMBTU	48.1	47.7	115.9	106.4
FTRs and TCRs
Realized gains and losses
Gains (losses)	$ 2	$ 4.1	$ 3.6	$ 4.5
Notional sales volumes
Notional sales volumes | MWh	7.6	7.5	15.2	14.8
Non-Utility Energy Infrastructure
Realized gains and losses
Realized gains and losses on derivatives income statement location	Total operating revenues	Total operating revenues	Total operating revenues	Total operating revenues
Utility operations
Realized gains and losses
Realized gains and losses on derivatives income statement location	Cost of sales	Cost of sales	Cost of sales	Cost of sales

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Cash collateral
Cash collateral posted	$ 52.9	$ 100.3
Offsetting derivative assets
Gross amount recognized on the balance sheet	34.3	18
Gross amount not offset on the balance sheet	(4.5)	(3.1)
Net amount	29.8	14.9
Offsetting derivative liabilities
Gross amount recognized on the balance sheet	56.3	106.4
Gross amount not offset on the balance sheet	(28.1)	(71)
Net amount	28.2	35.4
Cash collateral posted	$ 23.6	$ 67.9

GUARANTEES (Details)

GUARANTEES (Details) $ in Millions	Jun. 30, 2024 USD ($)
Guarantees
Total guarantees	$ 181.5
Guarantees expiring in less than 1 year	51.8
Guarantees expiring within 1 to 3 years	1.9
Guarantees with expiration over 3 years	127.8
Standby letters of credit
Guarantees
Total guarantees	136.5
Guarantees expiring in less than 1 year	19.7
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	116.8
Surety bonds
Guarantees
Total guarantees	34
Guarantees expiring in less than 1 year	32.1
Guarantees expiring within 1 to 3 years	1.9
Guarantees with expiration over 3 years	0
Other guarantees
Guarantees
Total guarantees	11
Guarantees expiring in less than 1 year	0
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	$ 11

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Components of net periodic benefit cost (credit)
Contributions and payments related to pension and OPEB plans			$ 7.5	$ 9.2
Total regulatory assets	$ 3,435		3,435		$ 3,274.7
Pension Benefits
Components of net periodic benefit cost (credit)
Service cost	5.4	$ 5.4	12.1	12
Interest cost	28.8	30.4	58.3	61.2
Expected return on plan assets	(45.3)	(46.4)	(91.1)	(93.8)
Amortization of prior service (credit) cost	0	0	0	0.1
Amortization of net actuarial (gain) loss	15.3	9.3	29.7	16.7
Net periodic benefit (credit) cost	4.2	(1.3)	9	(3.8)
Contributions and payments related to pension and OPEB plans			6.8
Estimated future employer contributions for the remainder of the year	6.5		6.5
Pension Benefits | Pension and Other Postretirement Plans Cost
Components of net periodic benefit cost (credit)
Total regulatory assets	15.5		15.5
Other Postretirement Benefits
Components of net periodic benefit cost (credit)
Service cost	2.6	2.4	5.4	4.9
Interest cost	5.7	5.4	11.4	10.8
Expected return on plan assets	(13.1)	(13.2)	(26.3)	(26.5)
Amortization of prior service (credit) cost	(3.4)	(3.7)	(6.8)	(7.4)
Amortization of net actuarial (gain) loss	(1.9)	(3)	(3.8)	(6.2)
Net periodic benefit (credit) cost	(10.1)	$ (12.1)	(20.1)	$ (24.4)
Contributions and payments related to pension and OPEB plans			0.7
Estimated future employer contributions for the remainder of the year	1.3		1.3
Other Postretirement Benefits | Pension and Other Postretirement Plans Cost
Components of net periodic benefit cost (credit)
Total regulatory assets	$ 26.5		$ 26.5

GOODWILL AND INTANGIBLES - GOOD

GOODWILL AND INTANGIBLES - GOODWILL (Details) $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($)
Goodwill balance by segment
Changes to the carrying amount of goodwill	$ 0
Goodwill	3,052.8
Accumulated impairment losses	0
Wisconsin
Goodwill balance by segment
Goodwill	2,104.3
Illinois
Goodwill balance by segment
Goodwill	758.7
Other States
Goodwill balance by segment
Goodwill	183.2
Non-Utility Energy Infrastructure
Goodwill balance by segment
Goodwill	$ 6.6

GOODWILL AND INTANGIBLES - INDE

GOODWILL AND INTANGIBLES - INDEFINITE LIVED INTANGIBLE ASSETS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Indefinite-lived Intangible Assets
Indefinite-lived intangible asset	$ 29.3		$ 29.3		$ 29.3
Amortization	13.4	$ 13.4	26.8	$ 23.8
MGU | Trade name
Indefinite-lived Intangible Assets
Indefinite-lived intangible asset	$ 5.2		$ 5.2		$ 5.2

GOODWILL AND INTANGIBLES - INTA

GOODWILL AND INTANGIBLES - INTANGIBLE LIABILITIES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Finite-Lived Intangible Liabilities
Net carrying amount	$ 568		$ 568		$ 594.8
Amortization	13.4	$ 13.4	$ 26.8	$ 23.8
Period of amortization			5 years
Amortization to be recorded as an increase to operating revenues
Amortization to be recorded in the next five years
2024	53.4		$ 53.4
2025	53.4		53.4
2026	53.4		53.4
2027	53.4		53.4
2028	53.4		53.4
Amortization to be recorded as a decrease to other operation and maintenance
Amortization to be recorded in the next five years
2024	0.2		0.2
2025	0.2		0.2
2026	0.2		0.2
2027	0.2		0.2
2028	0.2		0.2
WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	665.8		665.8		665.8
Accumulated amortization	(97.8)		(97.8)		(71)
Net carrying amount	568		568		594.8
PPAs | WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	653.9		653.9		653.9
Accumulated amortization	(93)		(93)		(66.6)
Net carrying amount	560.9		$ 560.9		587.3
PPAs | Blooming Grove , Tatanka Ridge, Jayhawk, Thunderhead, Samson I, and Sapphire Sky
Finite-Lived Intangible Liabilities
Weighted average remaining useful life			11 years
Proxy revenue swap | WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	7.2		$ 7.2		7.2
Accumulated amortization	(3.8)		(3.8)		(3.5)
Net carrying amount	$ 3.4		$ 3.4		3.7
Proxy revenue swap | Upstream
Finite-Lived Intangible Liabilities
Weighted average remaining useful life			5 years
Length of proxy revenue contract, in years	10 years		10 years
Interconnection agreements | WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	$ 4.7		$ 4.7		4.7
Accumulated amortization	(1)		(1)		(0.9)
Net carrying amount	$ 3.7		$ 3.7		$ 3.8
Interconnection agreements | Tatanka Ridge and Bishop Hill III
Finite-Lived Intangible Liabilities
Weighted average remaining useful life			16 years

INVESTMENT IN TRANSMISSION AF_3

INVESTMENT IN TRANSMISSION AFFILIATES - CHANGES TO INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Changes to investments in transmission affiliates
Add: Earnings from equity method investment	$ 46.8	$ 43.6	$ 91.6	$ 87.4
Add: Capital contributions			30.3	33.3
Transmission Affiliates
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	2,027.1	1,921.7	2,005.9	1,909.2
Add: Earnings from equity method investment	46.8	43.6	91.6	87.4
Add: Capital contributions	18.2	27.2	30.3	33.3
Less: Distributions	36.3	36.6	72	74
Investment in transmission affiliates, balance at end of period	$ 2,055.8	1,955.9	$ 2,055.8	1,955.9
ATC
Investment in transmission affiliates
Equity method investment, ownership interest (as a percent)	60%		60%
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 2,001.6	1,896.2	$ 1,980.8	1,884.6
Add: Earnings from equity method investment	46.2	43.1	90.6	86
Add: Capital contributions	18.2	27.2	30.3	33.3
Less: Distributions	36.3	34.7	72	72.1
Investment in transmission affiliates, balance at end of period	$ 2,029.7	1,931.8	$ 2,029.7	1,931.8
ATC Holdco
Investment in transmission affiliates
Equity method investment, ownership interest (as a percent)	75%		75%
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 25.5	25.5	$ 25.1	24.6
Add: Earnings from equity method investment	0.6	0.5	1	1.4
Add: Capital contributions	0	0	0	0
Less: Distributions	0	1.9	0	1.9
Investment in transmission affiliates, balance at end of period	$ 26.1	$ 24.1	$ 26.1	$ 24.1

INVESTMENT IN TRANSMISSION AF_4

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Investment in transmission affiliates
Charges to ATC for services and construction	$ 6.3	$ 4	$ 11	$ 7.8
Charges from ATC for network transmission services	$ 103.2	$ 94.3	$ 206.5	$ 188.8

INVESTMENT IN TRANSMISSION AF_5

INVESTMENT IN TRANSMISSION AFFILIATES - RECEIVABLES AND PAYABLES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Investment in transmission affiliates
Accounts payable for services received from ATC	$ 799.9	$ 896.6
ATC
Investment in transmission affiliates
Accounts receivable for services provided to ATC	1.6	1.6
Accounts payable for services received from ATC	50	49.9
Amounts due from ATC for transmission infrastructure upgrade	$ 42.3	$ 46.1

INVESTMENT IN TRANSMISSION AF_6

INVESTMENT IN TRANSMISSION AFFILIATES - SUMMARIZED FINANCIAL DATA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Summarized financial data
Operating revenues	$ 1,772	$ 1,830	$ 4,452.2	$ 4,718.1
Operating expenses	1,407.2	1,404.7	3,274	3,623.5
Other expense, net	113.2	86.8	216.3	174.4
Current assets	2,584.1		2,584.1		$ 2,795.7
Noncurrent assets	41,998.1		41,998.1		41,144
Total assets	44,582.2		44,582.2		43,939.7
Current liabilities	3,491.6		3,491.6		5,114.8
Other noncurrent liabilities	794.2		794.2		835.3
Total liabilities and members' equity	44,582.2		44,582.2		43,939.7
ATC
Summarized financial data
Operating revenues	218.3	203.8	430.2	404.2
Operating expenses	109.2	101.5	214	200.6
Other expense, net	35.8	32.9	71	65.4
Net income	73.3	$ 69.4	145.2	$ 138.2
Current assets	146.5		146.5		115.2
Noncurrent assets	6,539.3		6,539.3		6,337
Total assets	6,685.8		6,685.8		6,452.2
Current liabilities	586		586		495.9
Long-term debt	2,810.5		2,810.5		2,736
Other noncurrent liabilities	573.3		573.3		585.2
Members' equity	2,716		2,716		2,635.1
Total liabilities and members' equity	$ 6,685.8		$ 6,685.8		$ 6,452.2

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2024 USD ($)	Mar. 31, 2024 USD ($)	Jun. 30, 2023 USD ($)	Mar. 31, 2023 USD ($)	Jun. 30, 2024 USD ($) numberOfSegments	Jun. 30, 2023 USD ($)
Segment information
Number of reportable segments | numberOfSegments					6
Operating revenues	$ 1,772		$ 1,830		$ 4,452.2	$ 4,718.1
Other operation and maintenance	533.4		496		1,064.2	1,030
Depreciation and amortization	336.6		313.9		670	619.4
Equity in earnings of transmission affiliates	46.8		43.6		91.6	87.4
Interest expense	200.6		178.7		392.6	350.9
Income tax expense (benefit)	41.6		48.5		129.3	122.6
Net income (loss)	210		290		832.6	797.6
Net income (loss) attributed to common shareholders	211.3	$ 622.3	289.7	$ 507.5	833.6	797.2
External revenues
Segment information
Operating revenues	1,772		1,830		4,452.2	4,718.1
Intersegment revenues
Segment information
Operating revenues	0		0		0	0
Utility operations
Segment information
Other operation and maintenance	516.4		478.9		1,033.9	998.1
Depreciation and amortization	303.5		279.4		603	555.6
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	184.8		175.6		371.6	352
Income tax expense (benefit)	44.9		65.8		204.9	184.9
Net income (loss)	158.7		219.7		651.5	623.5
Net income (loss) attributed to common shareholders	158.4		219.4		650.9	622.9
Utility operations | External revenues
Segment information
Operating revenues	1,716		1,779.9		4,345.4	4,625.9
Utility operations | Intersegment revenues
Segment information
Operating revenues	0		0		0	0
Reconciling eliminations
Segment information
Other operation and maintenance	(4)		(3.9)		(5.5)	(5.5)
Depreciation and amortization	(21.9)		(19.1)		(42.7)	(37.6)
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	(89.7)		(88.8)		(180)	(173.3)
Income tax expense (benefit)	0		0		0	0
Net income (loss)	0		0		0	0
Net income (loss) attributed to common shareholders	0		0		0	0
Reconciling eliminations | External revenues
Segment information
Operating revenues	0		0		0	0
Reconciling eliminations | Intersegment revenues
Segment information
Operating revenues	$ (119.6)		(119)		$ (239.7)	(243.1)
ATC
Segment information
Ownership interest (as a percent)	60%				60%
Equity in earnings of transmission affiliates	$ 46.2		43.1		$ 90.6	86
ATC Holdco
Segment information
Ownership interest (as a percent)	75%				75%
Equity in earnings of transmission affiliates	$ 0.6		0.5		$ 1	1.4
Wisconsin | Operating Segments
Segment information
Operating revenues	1,368.2		1,424.5		3,147	3,420.8
Wisconsin | Operating Segments | Utility operations
Segment information
Other operation and maintenance	389.2		351.8		779.1	732.6
Depreciation and amortization	228.3		210.3		452.9	417.6
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	157.3		150.1		315.1	300.7
Income tax expense (benefit)	34.4		53.6		109.3	119.5
Net income (loss)	132.4		185.9		399.1	443.4
Net income (loss) attributed to common shareholders	132.1		185.6		398.5	442.8
Wisconsin | Operating Segments | Utility operations | External revenues
Segment information
Operating revenues	1,368.2		1,424.5		3,147	3,420.8
Wisconsin | Operating Segments | Utility operations | Intersegment revenues
Segment information
Operating revenues	0		0		0	0
Illinois | Operating Segments
Segment information
Operating revenues	276.8		273.5		942.8	873.2
Illinois | Operating Segments | Utility operations
Segment information
Other operation and maintenance	102.6		105.3		209.6	219
Depreciation and amortization	63.7		58.5		127.2	117
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	23.5		21.4		48.5	43
Income tax expense (benefit)	10.2		10.9		82.3	52.9
Net income (loss)	25.7		30.1		213.2	143.2
Net income (loss) attributed to common shareholders	25.7		30.1		213.2	143.2
Illinois | Operating Segments | Utility operations | External revenues
Segment information
Operating revenues	276.8		273.5		942.8	873.2
Illinois | Operating Segments | Utility operations | Intersegment revenues
Segment information
Operating revenues	0		0		0	0
Other States | Operating Segments
Segment information
Operating revenues	71		81.9		255.6	331.9
Other States | Operating Segments | Utility operations
Segment information
Other operation and maintenance	24.6		21.8		45.2	46.5
Depreciation and amortization	11.5		10.6		22.9	21
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	4		4.1		8	8.3
Income tax expense (benefit)	0.3		1.3		13.3	12.5
Net income (loss)	0.6		3.7		39.2	36.9
Net income (loss) attributed to common shareholders	0.6		3.7		39.2	36.9
Other States | Operating Segments | Utility operations | External revenues
Segment information
Operating revenues	71		81.9		255.6	331.9
Other States | Operating Segments | Utility operations | Intersegment revenues
Segment information
Operating revenues	0		0		0	0
Electric Transmission | Operating Segments
Segment information
Other operation and maintenance	0		0		0	0
Depreciation and amortization	0		0		0	0
Equity in earnings of transmission affiliates	46.8		43.6		91.6	87.4
Interest expense	4.9		4.8		9.7	9.6
Income tax expense (benefit)	10.5		9.7		20.4	19.4
Net income (loss)	31.4		29.1		61.5	58.4
Net income (loss) attributed to common shareholders	31.4		29.1		61.5	58.4
Electric Transmission | Operating Segments | External revenues
Segment information
Operating revenues	0		0		0	0
Electric Transmission | Operating Segments | Intersegment revenues
Segment information
Operating revenues	$ 0		0		$ 0	0
Electric Transmission | ATC
Segment information
Ownership interest (as a percent)	60%				60%
Electric Transmission | ATC Holdco
Segment information
Ownership interest (as a percent)	75%				75%
Non-Utility Energy Infrastructure
Segment information
Natural gas storage needs provided to Wisconsin utilities					33%
Non-Utility Energy Infrastructure | Operating Segments
Segment information
Operating revenues	$ 175.6		169		$ 346.5	335.2
Other operation and maintenance	25		20.3		43.2	38.1
Depreciation and amortization	49.6		48.4		98.7	91.1
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	24.1		25.1		48.2	45
Income tax expense (benefit)	(20.2)		(19.7)		(43.6)	(37.5)
Net income (loss)	91.7		85.9		186	174.2
Net income (loss) attributed to common shareholders	93.3		85.9		187.6	174.4
Non-Utility Energy Infrastructure | Operating Segments | External revenues
Segment information
Operating revenues	56		50		106.8	92.1
Non-Utility Energy Infrastructure | Operating Segments | Intersegment revenues
Segment information
Operating revenues	119.6		119		239.7	243.1
Corporate and Other | Operating Segments
Segment information
Operating revenues	0		0.1		0	0.1
Other operation and maintenance	(4)		0.7		(7.4)	(0.7)
Depreciation and amortization	5.4		5.2		11	10.3
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	76.5		62		143.1	117.6
Income tax expense (benefit)	6.4		(7.3)		(52.4)	(44.2)
Net income (loss)	(71.8)		(44.7)		(66.4)	(58.5)
Net income (loss) attributed to common shareholders	(71.8)		(44.7)		(66.4)	(58.5)
Corporate and Other | Operating Segments | External revenues
Segment information
Operating revenues	0		0.1		0	0.1
Corporate and Other | Operating Segments | Intersegment revenues
Segment information
Operating revenues	$ 0		$ 0		$ 0	$ 0

VARIABLE INTEREST ENTITIES - WE

VARIABLE INTEREST ENTITIES - WEPCO ENVIRONMENTAL TRUST (Details) - USD ($) $ in Millions	1 Months Ended
	Nov. 30, 2020	Jun. 30, 2024	Dec. 31, 2023
Assets
Other current assets (restricted cash)		$ 51.3	$ 70.1
Regulatory assets		3,393.1	3,249.8
Other long-term assets (restricted cash)		27.6	52.2
Liabilities
Current portion of long-term debt		1,157.4	1,264.2
Accounts payable		799.9	896.6
WEPCo Environmental Trust
Variable interest entities
Securitization of environmental control costs related to Pleasant Prairie power plant	$ 100
Assets
Other current assets (restricted cash)		0.3	0.8
Regulatory assets		82.3	85.9
Other long-term assets (restricted cash)		0.3	0.6
Liabilities
Current portion of long-term debt		9.1	9
Accounts payable		0.1	0
Other current liabilities (accrued interest)		0.1	0.1
Long-term debt		$ 80.9	$ 85.3

VARIABLE INTEREST ENTITIES - TR

VARIABLE INTEREST ENTITIES - TRANSMISSION AFFILIATES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022
ATC
Variable interest entities
Ownership interest (as a percent)	60%
Equity investment	$ 2,029.7	$ 2,001.6	$ 1,980.8	$ 1,931.8	$ 1,896.2	$ 1,884.6
ATC Holdco
Variable interest entities
Ownership interest (as a percent)	75%
Equity investment	$ 26.1	$ 25.5	$ 25.1	$ 24.1	$ 25.5	$ 24.6

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions	Jun. 30, 2024 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 10.1

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended					6 Months Ended
	May 31, 2024 MMBTU performance_obligations	Feb. 29, 2024 micrograms	Oct. 31, 2023 States mo	Aug. 31, 2023	Dec. 31, 2020 micrograms	Jun. 30, 2024 USD ($) MW	Dec. 31, 2023 USD ($)
Manufactured gas plant remediation
Regulatory assets | $						$ 3,435	$ 3,274.7
Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets | $						$ 575.2	596.8
Cross State Air Pollution Rule - Good Neighbor Rule | Electric | Maximum
Air quality
RICE Unit megawatts | MW						25
Mercury and Air Toxics Standards | Electric
Air quality
Previous level of particulate matter in pounds per million british thermal unit | MMBTU	0.03
New limit for particulate matter published in the EPA's final rule | MMBTU	0.01
National Ambient Air Quality Standards | Electric
Air quality
Number of states that failed to submit timely SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard | States			11
Number of months after May 2025 deadline for SIP that offset sanctions will take effect if the state SIP revision is not approved | mo			18
Current level of micrograms per cubic meter that particulate matter needs to be below | micrograms					12
Current level of micrograms per cubic meter under 24-hour standard that particulate matter needs to be below | micrograms					35
National Ambient Air Quality Standards | Electric | Maximum
Air quality
Period of time for EPA review of ozone plan				5 years
New primary annual PM2.5 level | micrograms		9
National Ambient Air Quality Standards | Electric | Minimum
Air quality
Period of time for EPA review of ozone plan				3 years
Number of years between evaluation of attainment status				3 years
Climate Change | Electric
Air quality
Number of applicable GHG performance standards for coal plants | performance_obligations	0
Percent capacity factor that if combined cycle natural gas plants are above it causes the rule to be highly dependent on hydrogen or carbon capture	40%
Number of applicable GHG limits for new simple cycle natural gas-fired combustion turbines | performance_obligations	0
Percent capacity factor for simple cycle natural gas fired combustion turbines that there are no applicable limits if the capacity factor is less than this.	20%
Capacity of coal-fired generation retired, in megawatts | MW						2,500
Capacity of fossil-fueled generation to be retired by the end of 2031, in megawatts | MW						1,200
Company goal for percentage of carbon emissions reduction below 2005 levels by the end of 2025						60%
Company goal for percentage of carbon emissions reduction below 2005 levels by the end of 2030						80%
Climate Change | Electric | Maximum
Air quality
RICE Unit megawatts | MW						25
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Number of new ELG rule requirements that affect our electric utilities | performance_obligations	3
Compliance costs through 2023 associated with the ELG rule that were required to achieve discharge limits | $							105
Number of existing coal categories that were kept as part of the 2024 supplemental ELG rule requirements | performance_obligations	1
Number of new categories that were created as part of the 2024 supplemental ELG rule requirements | performance_obligations	1
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Reserves for future environmental remediation | $						$ 437	463.7
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets | $						$ 575.2	$ 596.8

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Supplemental cash flow information
Cash paid for interest, net of amount capitalized	$ 377.7	$ 312.8
Cash paid (received) for income taxes, net	(172.8)	15.8
Cash received from sale of production tax credits	173
Significant non-cash investing and financing transactions
Accounts payable related to construction costs	167.1	156.7
Common stock issued for stock-based compensation plans	6.4	0
Increase in receivables related to insurance proceeds	$ 2.2	$ 5.6

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH, CASH EQUIVALENTS, AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023	Jun. 30, 2023	Dec. 31, 2022
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 224	$ 42.9
Restricted cash included in other current assets	51.3	70.1
Restricted cash included in other long-term assets	27.6	52.2
Cash, cash equivalents, and restricted cash	$ 302.9	$ 165.2	$ 140.1	$ 182.2

REGULATORY ENVIRONMENT - WI 202

REGULATORY ENVIRONMENT - WI 2025 and 2026 Rates (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions	Apr. 12, 2024 USD ($)
Public Utilities, General Disclosures [Line Items]
Percentage of first 15 basis points of additional earnings retained by the utility	100%
Return on equity in excess of authorized amount (as a percent)	0.15%
Percentage of additional earnings between 15 and 75 basis points refunded to customers	50%
Return on equity in excess of first 15 basis points above authorized amount (as a percent)	0.60%
Percentage of earnings in excess of 75 basis points refunded to customers	100%
WE
Public Utilities, General Disclosures [Line Items]
Requested return on equity (as a percent)	10%
Requested common equity component average (as a percent)	53.50%
WPS
Public Utilities, General Disclosures [Line Items]
Requested return on equity (as a percent)	10%
Requested common equity component average (as a percent)	53.50%
WG
Public Utilities, General Disclosures [Line Items]
Requested return on equity (as a percent)	10%
Requested common equity component average (as a percent)	53.50%
2025 Rates | WE | Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 240.7
Requested rate increase (as a percent)	6.90%
2025 Rates | WE | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 57.5
Requested rate increase (as a percent)	10%
2025 Rates | WE | Steam Rate Request
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 2.5
Requested rate increase (as a percent)	8.40%
2025 Rates | WPS | Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 110.1
Requested rate increase (as a percent)	8.50%
2025 Rates | WPS | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 26.8
Requested rate increase (as a percent)	6.80%
2025 Rates | WG | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 67.7
Requested rate increase (as a percent)	8.20%
2026 Rates | WE | Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 177.9
Requested rate increase (as a percent)	4.60%
2026 Rates | WE | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 31
Requested rate increase (as a percent)	4.60%
2026 Rates | WPS | Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 64.3
Requested rate increase (as a percent)	4.50%
2026 Rates | WPS | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 16.1
Requested rate increase (as a percent)	3.70%
2026 Rates | WG | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 30.6
Requested rate increase (as a percent)	3.30%

REGULATORY ENVIRONMENT - PGL AN

REGULATORY ENVIRONMENT - PGL AND NSG 2023 RATE ORDER (Details) - Illinois Commerce Commission (ICC) - 2023 Rate Order - USD ($) $ in Millions			3 Months Ended
	May 30, 2024	Nov. 16, 2023	Dec. 31, 2023
Public Utilities, General Disclosures [Line Items]
Impairment of property, plant, and equipment			$ 178.9
PGL
Public Utilities, General Disclosures [Line Items]
Approved rate increase	$ 1.6	$ 304.6
Approved rate increase (as a percent)		43.50%
Approved return on equity (as a percent)		9.38%
Approved common equity component average (as a percent)		50.79%
Disallowed capital costs		$ 236.2
Additional capital spend approved	$ 28.5
Impairment of property, plant, and equipment			177.2
NSG
Public Utilities, General Disclosures [Line Items]
Approved rate increase		$ 11
Approved rate increase (as a percent)		11.60%
Approved return on equity (as a percent)		9.38%
Approved common equity component average (as a percent)		52.58%
Disallowed capital costs		$ 1.7
Impairment of property, plant, and equipment			$ 1.7

REGULATORY ENVIRONMENT - PGL _2

REGULATORY ENVIRONMENT - PGL AND NSG UEA RIDER (Details) - Illinois Commerce Commission (ICC) - Uncollectible Expense Adjustment Rider Reconciliation $ in Millions	1 Months Ended
	May 31, 2023 USD ($)	Jun. 30, 2024 USD ($) Assurance
Public Utilities, General Disclosures [Line Items]
Amount of assurance that PGL's QIP rider costs will be recoverable | Assurance		0
Minimum annual costs included in UEA rider during open reconciliation years		$ 10
Maximum annual costs included in UEA rider during open reconciliation years		$ 40
PGL
Public Utilities, General Disclosures [Line Items]
Refunds required to customers	$ 15.4
Refund period	9 months
NSG
Public Utilities, General Disclosures [Line Items]
Refunds required to customers	$ 0.7
Refund period	9 months

REGULATORY ENVIRONMENT - PGL QI

REGULATORY ENVIRONMENT - PGL QIP RIDER (Details) - Illinois Commerce Commission (ICC) - PGL - Rider QIP Reconciliation $ in Millions	Jun. 30, 2024 USD ($) Assurance
Public Utilities, General Disclosures [Line Items]
Minimum annual costs included in PGL's QIP rider during open reconciliation years	$ 192
Maximum annual costs included in PGL's QIP rider during open reconciliation years	$ 348
Amount of assurance that PGL's QIP rider costs will be recoverable | Assurance	0

REGULATORY ENVIRONMENT - 2023 M

REGULATORY ENVIRONMENT - 2023 MERC RATE ORDER (Details) - Minnesota Public Utilities Commission (MPUC) - MERC - USD ($) $ in Millions	1 Months Ended		3 Months Ended
	Nov. 30, 2023	Dec. 31, 2022	Jun. 30, 2024
Public Utilities, General Disclosures [Line Items]
Interim rate increase		$ 37
Approved rate increase	$ 28.8
Approved rate increase (as a percent)	7.10%
Approved return on equity (as a percent)	9.65%
Approved common equity component average (as a percent)	53%
Revenue Subject to Refund
Public Utilities, General Disclosures [Line Items]
Interim rate refunds made to customers			$ 8.9

REGULATORY ENVIRONMENT - 2024 M

REGULATORY ENVIRONMENT - 2024 MGU RATE CASE (Details) - MPSC - MGU $ in Millions	Mar. 01, 2024 USD ($)
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 17.6
Requested rate increase (as a percent)	9.70%
Requested return on equity (as a percent)	10.25%
Requested common equity component average (as a percent)	50.90%

REGULATORY ENVIRONMENT - UMERC

REGULATORY ENVIRONMENT - UMERC 2024 RATE CASE (Details) - MPSC - UMERC $ in Millions	May 01, 2024 USD ($)
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 11.2
Requested rate increase (as a percent)	13.80%
Requested return on equity (as a percent)	10.25%
Requested common equity component average (as a percent)	50%