WEC Energy (WEC) 10-Q 3 Aug 22 2022 Q2 Quarterly report Financial data

COVER PAGE

COVER PAGE	6 Months Ended
	Jun. 30, 2022 shares
Cover [Abstract]
Document type	10-Q
Document Quarterly Report	true
Document period end date	Jun. 30, 2022
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
Small company	false
Emerging growth company	false
Entity Shell Company	false
Entity common stock, shares outstanding	315,434,531
Entity central index key	0000783325
Current fiscal year end date	--12-31
Document fiscal year focus	2022
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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Statement [Abstract]
Operating revenues	$ 2,127.9	$ 1,676.2	$ 5,036	$ 4,367.6
Operating expenses
Cost of sales	935	525.9	2,318.4	1,791.5
Other operation and maintenance	449	463.8	903.4	943.7
Depreciation and amortization	279.6	266.2	557.7	527.6
Property and revenue taxes	56.1	51.5	116.9	106.7
Total operating expenses	1,719.7	1,307.4	3,896.4	3,369.5
Operating income	408.2	368.8	1,139.6	998.1
Equity in earnings of transmission affiliates	43	41.3	84.7	83.9
Other income, net	19.8	39.7	59.4	72.5
Interest expense	119.8	120	237.4	239.5
Other expense	(57)	(39)	(93.3)	(83.1)
Income before income taxes	351.2	329.8	1,046.3	915
Income tax expense	63.4	54.1	190.5	129
Net income	287.8	275.7	855.8	786
Preferred stock dividends of subsidiary	0.3	0.3	0.6	0.6
Net (income) loss attributable to noncontrolling interests	0	(0.6)	1.8	(0.7)
Net income attributed to common shareholders	$ 287.5	$ 276	$ 853.4	$ 786.1
Earnings per share
Basic (in dollars per share)	$ 0.91	$ 0.88	$ 2.71	$ 2.49
Diluted (in dollars per share)	$ 0.91	$ 0.87	$ 2.70	$ 2.49
Weighted average common shares outstanding
Basic (in shares)	315.4	315.4	315.4	315.4
Diluted (in shares)	316.2	316.3	316.2	316.3

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Statement of Other Comprehensive Income [Abstract]
Net income	$ 287.8	$ 275.7	$ 855.8	$ 786
Derivatives accounted for as cash flow hedges
Reclassification of realized net derivative (gain) loss to net income, net of tax	0	1	(0.1)	2
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0	0.1	0.1	0.2
Other comprehensive income, net of tax	0	1.1	0	2.2
Comprehensive income	287.8	276.8	855.8	788.2
Preferred stock dividends of subsidiary	0.3	0.3	0.6	0.6
Comprehensive (income) loss attributed to noncontrolling interests	0	0.6	(1.8)	0.7
Comprehensive income attributed to common shareholders	$ 287.5	$ 277.1	$ 853.4	$ 788.3

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 30.3	$ 16.3
Accounts receivable and unbilled revenues, net of reserves of $175.8 and $198.3, respectively	1,447.7	1,505.7
Materials, supplies, and inventories	572.2	635.8
Prepaid taxes	193	182.1
Other prepayments	33.5	63.4
Amounts recoverable from customers	134.2	102.3
Derivative assets	189.8	107
Other	41.8	44.1
Current assets	2,642.5	2,656.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,183.2 and $9,889.3, respectively	27,626.2	26,982.4
Regulatory assets (June 30, 2022 and December 31, 2021 include $96.1 and $100.7, respectively, related to WEPCo Environmental Trust)	3,144.7	3,264.8
Equity investment in transmission affiliates	1,837.2	1,789.4
Goodwill	3,052.8	3,052.8
Pension and OPEB assets	942.1	881.3
Other	361.6	361.1
Long-term assets	36,964.6	36,331.8
Total assets	39,607.1	38,988.5
Current liabilities
Short-term debt	1,629.1	1,897
Current portion of long-term debt (June 30, 2022 and December 31, 2021 each include $8.8, respectively, related to WEPCo Environmental Trust)	174.4	169.4
Accounts payable	1,078.2	1,005.7
Other	936.1	680.9
Current liabilities	3,817.8	3,753
Long-term liabilities
Long-term debt (June 30, 2022 and December 31, 2021 include $98.4 and $102.7, respectively, related to WEPCo Environmental Trust)	13,523.4	13,523.7
Deferred income taxes	4,493.1	4,308.5
Deferred revenue, net	378.7	389.2
Regulatory liabilities	4,000.1	3,946
Environmental remediation liabilities	504.3	532.6
Pension and OPEB obligations	222.2	219
Other	1,176.9	1,203.2
Long-term liabilities	24,298.7	24,122.2
Commitments and contingencies (Note 21)
Common shareholders' equity
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,434,531 shares outstanding	3.2	3.2
Additional paid in capital	4,121.1	4,138.1
Retained earnings	7,169.5	6,775.1
Accumulated other comprehensive loss	(3.2)	(3.2)
Common shareholders' equity	11,290.6	10,913.2
Preferred stock of subsidiary	30.4	30.4
Noncontrolling interests	169.6	169.7
Total liabilities and equity	$ 39,607.1	$ 38,988.5

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 175.8	$ 198.3
Property, plant, and equipment, accumulated depreciation and amortization	$ 10,183.2	$ 9,889.3
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	325,000,000	325,000,000
Common stock, shares outstanding	315,434,531	315,434,531
Regulatory assets (June 30, 2022 and December 31, 2021 include $96.1 and $100.7, respectively, related to WEPCo Environmental Trust)	$ 3,144.7	$ 3,264.8
WEPCo Environmental Trust
Regulatory assets (June 30, 2022 and December 31, 2021 include $96.1 and $100.7, respectively, related to WEPCo Environmental Trust)	96.1	100.7
Current portion of long-term debt (June 30, 2022 and December 31, 2021 each include $8.8, respectively, related to WEPCo Environmental Trust)	8.8	8.8
Long-term debt (June 30, 2022 and December 31, 2021 include $98.4 and $102.7, respectively, related to WEPCo Environmental Trust)	$ 98.4	$ 102.7

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Operating activities
Net income	$ 855.8	$ 786
Reconciliation to cash provided by operating activities
Depreciation and amortization	557.7	527.6
Deferred income taxes and ITCs, net	163.2	164.4
Contributions and payments related to pension and OPEB plans	(8.6)	(7.6)
Equity income in transmission affiliates, net of distributions	(17.5)	(17.7)
Change in –
Accounts receivable and unbilled revenues, net	36.3	70
Materials, supplies, and inventories	63.6	75.9
Prepaid taxes	(10.9)	(46.8)
Other prepayments	29.9	26.5
Amounts recoverable from customers	(31.9)	(193.6)
Other current assets	4.5	12.5
Accounts payable	1.5	(119.3)
Temporary LIFO liquidation credit	107.6	26.7
Other current liabilities	128.4	(9.5)
Other, net	(117)	(68.9)
Net cash provided by operating activities	1,762.6	1,226.2
Investing activities
Capital expenditures	(1,028.8)	(1,010.1)
Acquisition of Jayhawk	0	(119.7)
Capital contributions to transmission affiliates	(30.3)	0
Proceeds from the sale of assets	65	20.8
Proceeds from the sale of investments held in rabbi trust	15.4	12.7
Insurance proceeds received for property damage	41.3	0
Other, net	(0.1)	21.7
Net cash used in investing activities	(937.5)	(1,074.6)
Financing activities
Exercise of stock options	23	4
Purchase of common stock	(48.4)	(11.3)
Dividends paid on common stock	(459)	(427.5)
Issuance of long-term debt	0	1,018.8
Retirement of long-term debt	(49.1)	(341.2)
Issuance of short-term loan	1.4	0
Repayment of short-term loan	0	(340)
Change in other short-term debt	(269.3)	(12.4)
Other, net	(6.3)	(14.9)
Net cash used in financing activities	(807.7)	(124.5)
Net change in cash, cash equivalents, and restricted cash	17.4	27.1
Cash, cash equivalents, and restricted cash at beginning of period	87.5	72.6
Cash, cash equivalents, and restricted cash at end of period	$ 104.9	$ 99.7

CONDENSED CONSOLIDATED STATEM_3

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, 2020	$ 10,662.5	$ 10,469.7	$ 3.2	$ 4,143.7	$ 6,329.6	$ (6.8)	$ 30.4	$ 162.4
Statements of equity
Net income attributed to common shareholders	510.1	510.1	0	0	510.1	0	0	0
Net income (loss) attributable to noncontrolling interests	(0.1)	0	0	0	0	0	0	(0.1)
Other comprehensive income	1.1	1.1	0	0	0	1.1	0	0
Common stock dividends	(213.7)	(213.7)	0	0	(213.7)	0	0	0
Exercise of stock options	1.2	1.2	0	1.2	0	0	0	0
Purchase of common stock	(6.6)	(6.6)	0	(6.6)	0	0	0	0
Acquisition of a noncontrolling interest	6.2	0	0	0	0	0	0	6.2
Capital contributions from noncontrolling interest	2	0	0	0	0	0	0	2
Distributions to noncontrolling interests	(0.4)	0	0	0	0	0	0	(0.4)
Stock-based compensation and other	5.3	5.3	0	5.3	0	0	0	0
Balance at Mar. 31, 2021	10,967.6	10,767.1	3.2	4,143.6	6,626	(5.7)	30.4	170.1
Balance at Dec. 31, 2020	10,662.5	10,469.7	3.2	4,143.7	6,329.6	(6.8)	30.4	162.4
Statements of equity
Net income attributed to common shareholders	786.1
Net income (loss) attributable to noncontrolling interests	(0.7)
Other comprehensive income	2.2
Balance at Jun. 30, 2021	11,030.4	10,830.9	3.2	4,144.1	6,688.2	(4.6)	30.4	169.1
Balance at Mar. 31, 2021	10,967.6	10,767.1	3.2	4,143.6	6,626	(5.7)	30.4	170.1
Statements of equity
Net income attributed to common shareholders	276	276	0	0	276	0	0	0
Net income (loss) attributable to noncontrolling interests	(0.6)	0	0	0	0	0	0	(0.6)
Other comprehensive income	1.1	1.1	0	0	0	1.1	0	0
Common stock dividends	(213.8)	(213.8)	0	0	(213.8)	0	0	0
Exercise of stock options	2.8	2.8	0	2.8	0	0	0	0
Purchase of common stock	(4.7)	(4.7)	0	(4.7)	0	0	0	0
Capital contributions from noncontrolling interest	0.5	0	0	0	0	0	0	0.5
Distributions to noncontrolling interests	(0.9)	0	0	0	0	0	0	(0.9)
Stock-based compensation and other	2.4	2.4	0	2.4	0	0	0	0
Balance at Jun. 30, 2021	11,030.4	10,830.9	3.2	4,144.1	6,688.2	(4.6)	30.4	169.1
Balance at Dec. 31, 2021	11,113.3	10,913.2	3.2	4,138.1	6,775.1	(3.2)	30.4	169.7
Statements of equity
Net income attributed to common shareholders	565.9	565.9	0	0	565.9	0	0	0
Net income (loss) attributable to noncontrolling interests	1.8	0	0	0	0	0	0	1.8
Common stock dividends	(229.6)	(229.6)	0	0	(229.6)	0	0	0
Exercise of stock options	11.8	11.8	0	11.8	0	0	0	0
Purchase of common stock	(23.4)	(23.4)	0	(23.4)	0	0	0	0
Capital contributions from noncontrolling interest	0.4	0	0	0	0	0	0	0.4
Distributions to noncontrolling interests	(1)	0	0	0	0	0	0	(1)
Stock-based compensation and other	5.3	5.3	0	5.3	0	0	0	0
Balance at Mar. 31, 2022	11,444.5	11,243.2	3.2	4,131.8	7,111.4	(3.2)	30.4	170.9
Balance at Dec. 31, 2021	11,113.3	10,913.2	3.2	4,138.1	6,775.1	(3.2)	30.4	169.7
Statements of equity
Net income attributed to common shareholders	853.4
Net income (loss) attributable to noncontrolling interests	1.8
Other comprehensive income	0
Balance at Jun. 30, 2022	11,490.6	11,290.6	3.2	4,121.1	7,169.5	(3.2)	30.4	169.6
Balance at Mar. 31, 2022	11,444.5	11,243.2	3.2	4,131.8	7,111.4	(3.2)	30.4	170.9
Statements of equity
Net income attributed to common shareholders	287.5	287.5	0	0	287.5	0	0	0
Net income (loss) attributable to noncontrolling interests	0
Other comprehensive income	0
Common stock dividends	(229.4)	(229.4)	0	0	(229.4)	0	0	0
Exercise of stock options	11.2	11.2	0	11.2	0	0	0	0
Purchase of common stock	(25)	(25)	0	(25)	0	0	0	0
Capital contributions from noncontrolling interest	0.1	0	0	0	0	0	0	0.1
Distributions to noncontrolling interests	(1.2)	0	0	0	0	0	0	(1.2)
Stock-based compensation and other	2.9	3.1	0	3.1	0	0	0	(0.2)
Balance at Jun. 30, 2022	$ 11,490.6	$ 11,290.6	$ 3.2	$ 4,121.1	$ 7,169.5	$ (3.2)	$ 30.4	$ 169.6

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021
Statement of Stockholders' Equity [Abstract]
Common stock dividend declared (in dollars per share)	$ 0.7275	$ 0.7275	$ 0.6775	$ 0.6775

GENERAL INFORMATION

GENERAL INFORMATION	6 Months Ended
	Jun. 30, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	GENERAL INFORMATION WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple wind 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 at Bishop Hill III, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties. We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 18, Investment in Transmission Affiliates, for more information. We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2021. 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, 2022, are not necessarily indicative of expected results for 2022 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, 2022
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 (or disposals) of assets or businesses, and transaction costs are capitalized in asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs and interconnection agreements. See Note 17, Goodwill and Intangibles, for more information. Acquisition of Electric Generation Facility in Wisconsin In November 2021, WE and WPS signed an asset purchase agreement to acquire Whitewater, a commercially operational 236.5 MW dual-fueled (natural gas and low sulfur fuel oil) combined-cycle electrical generation facility in Whitewater, Wisconsin, for $72.7 million. The transaction is expected to close in early 2023. In December 2021, WE and WPS filed an application with the PSCW for approval to acquire Whitewater. Acquisition of a Wind Energy Generation Facility in Illinois In June 2021, WECI signed an agreement to acquire a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility under construction in McLean County, Illinois, for approximately $412 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for a period of 12 years. WECI's investment in Sapphire Sky is expected to qualify for PTCs. The transaction is subject to FERC approval and commercial operation is expected to begin by the end of 2022, at which time the transaction is expected to close. Sapphire Sky will be included in the non-utility energy infrastructure segment. Acquisition of a Wind Energy Generation Facility in Kansas In February 2021, WECI completed the acquisition of a 90% ownership interest in Jayhawk, a 190 MW wind generating facility in Bourbon and Crawford counties, Kansas, for $119.9 million, which included transaction costs. The project became commercially operational in December 2021. Subsequent to the acquisition, WECI incurred an additional $153.6 million of capital expenditures as of June 30, 2022 for the project for a current total investment of $273.5 million. The project has an offtake agreement with an unaffiliated third party for all of the energy produced by the facility for a period of 10 years. WECI's investment in Jayhawk qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 10 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest. Jayhawk is included in the non-utility energy infrastructure segment. Acquisition of Wind Generation Facility in Nebraska In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million. The project has an offtake agreement for all of the energy to be produced by the facility for 12 years. WECI's investment in Thunderhead is expected to qualify for PTCs. The transaction was approved by FERC in April 2020, and commercial operation was initially expected to begin by the end of 2020. However, due to a delay in construction of the required substation, Thunderhead is now expected to begin commercial operation in the fall of 2022. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment.

DISPOSITION

DISPOSITION	6 Months Ended
	Jun. 30, 2022
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITION	DISPOSITION Sale of Certain Real Estate by The Peoples Gas Light and Coke Company In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $55.1 million. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $54.5 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

OPERATING REVENUES

OPERATING REVENUES	6 Months Ended
	Jun. 30, 2022
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 2021 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 have 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 Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Three Months Ended June 30, 2022 Electric $ 1,221.1 $ — $ — $ 1,221.1 $ — $ — $ — $ 1,221.1 Natural gas 329.5 442.2 95.8 867.5 12.0 — (11.0) 868.5 Total regulated revenues 1,550.6 442.2 95.8 2,088.6 12.0 — (11.0) 2,089.6 Other non-utility revenues — — 4.5 4.5 31.1 — (4.0) 31.6 Total revenues from contracts with customers 1,550.6 442.2 100.3 2,093.1 43.1 — (15.0) 2,121.2 Other operating revenues 6.8 0.2 (0.4) 6.6 100.5 0.1 (100.5) (1) 6.7 Total operating revenues $ 1,557.4 $ 442.4 $ 99.9 $ 2,099.7 $ 143.6 $ 0.1 $ (115.5) $ 2,127.9 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Three Months Ended June 30, 2021 Electric $ 1,083.2 $ — $ — $ 1,083.2 $ — $ — $ — $ 1,083.2 Natural gas 212.7 266.1 66.9 545.7 9.4 — (8.7) 546.4 Total regulated revenues 1,295.9 266.1 66.9 1,628.9 9.4 — (8.7) 1,629.6 Other non-utility revenues — — 4.4 4.4 24.2 — (3.9) 24.7 Total revenues from contracts with customers 1,295.9 266.1 71.3 1,633.3 33.6 — (12.6) 1,654.3 Other operating revenues 11.6 9.4 0.8 21.8 99.9 0.1 (99.9) (1) 21.9 Total operating revenues $ 1,307.5 $ 275.5 $ 72.1 $ 1,655.1 $ 133.5 $ 0.1 $ (112.5) $ 1,676.2 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2022 Electric $ 2,408.6 $ — $ — $ 2,408.6 $ — $ — $ 2,408.6 Natural gas 1,076.3 1,122.1 334.0 2,532.4 27.3 — (25.8) 2,533.9 Total regulated revenues 3,484.9 1,122.1 334.0 4,941.0 27.3 — (25.8) 4,942.5 Other non-utility revenues — — 9.1 9.1 74.8 — (5.6) 78.3 Total revenues from contracts with customers 3,484.9 1,122.1 343.1 4,950.1 102.1 — (31.4) 5,020.8 Other operating revenues 14.8 2.4 (2.3) 14.9 201.0 0.3 (201.0) (1) 15.2 Total operating revenues $ 3,499.7 $ 1,124.5 $ 340.8 $ 4,965.0 $ 303.1 $ 0.3 $ (232.4) $ 5,036.0 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2021 Electric $ 2,178.2 $ — $ — $ 2,178.2 $ — $ — $ — $ 2,178.2 Natural gas 840.0 959.6 292.5 2,092.1 24.0 — (22.0) 2,094.1 Total regulated revenues 3,018.2 959.6 292.5 4,270.3 24.0 — (22.0) 4,272.3 Other non-utility revenues — — 9.1 9.1 47.4 — (5.5) 51.0 Total revenues from contracts with customers 3,018.2 959.6 301.6 4,279.4 71.4 — (27.5) 4,323.3 Other operating revenues 21.0 19.3 3.8 44.1 199.7 0.2 (199.7) (1) 44.3 Total operating revenues $ 3,039.2 $ 978.9 $ 305.4 $ 4,323.5 $ 271.1 $ 0.2 $ (227.2) $ 4,367.6 (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) 2022 2021 2022 2021 Residential $ 449.7 $ 419.0 $ 912.8 $ 842.7 Small commercial and industrial 378.4 346.6 748.5 678.0 Large commercial and industrial 268.1 224.5 497.3 434.0 Other 7.2 6.9 15.0 14.7 Total retail revenues 1,103.4 997.0 2,173.6 1,969.4 Wholesale 40.8 38.6 83.2 78.3 Resale 60.7 37.4 117.5 100.1 Steam 4.7 4.2 16.8 19.0 Other utility revenues 11.5 6.0 17.5 11.4 Total electric utility operating revenues $ 1,221.1 $ 1,083.2 $ 2,408.6 $ 2,178.2 Natural Gas Utility Operating Revenues The following tables disaggregate natural gas utility operating revenues into customer class: (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended June 30, 2022 Residential $ 198.5 $ 268.6 $ 63.5 $ 530.6 Commercial and industrial 102.1 78.2 36.6 216.9 Total retail revenues 300.6 346.8 100.1 747.5 Transportation 18.0 54.5 6.0 78.5 Other utility revenues (1) 10.9 40.9 (10.3) 41.5 Total natural gas utility operating revenues $ 329.5 $ 442.2 $ 95.8 $ 867.5 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended June 30, 2021 Residential $ 188.6 $ 199.1 $ 37.9 $ 425.6 Commercial and industrial 90.2 51.5 17.3 159.0 Total retail revenues 278.8 250.6 55.2 584.6 Transportation 17.8 48.8 6.6 73.2 Other utility revenues (1) (83.9) (33.3) 5.1 (112.1) Total natural gas utility operating revenues $ 212.7 $ 266.1 $ 66.9 $ 545.7 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2022 Residential $ 701.0 $ 734.1 $ 224.8 $ 1,659.9 Commercial and industrial 374.6 236.5 123.4 734.5 Total retail revenues 1,075.6 970.6 348.2 2,394.4 Transportation 43.5 135.4 19.9 198.8 Other utility revenues (1) (42.8) 16.1 (34.1) (60.8) Total natural gas utility operating revenues $ 1,076.3 $ 1,122.1 $ 334.0 $ 2,532.4 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2021 Residential $ 536.2 $ 533.0 $ 125.8 $ 1,195.0 Commercial and industrial 266.6 154.2 61.2 482.0 Total retail revenues 802.8 687.2 187.0 1,677.0 Transportation 42.2 123.0 17.6 182.8 Other utility revenues (1) (5.0) 149.4 87.9 232.3 Total natural gas utility operating revenues $ 840.0 $ 959.6 $ 292.5 $ 2,092.1 (1) Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. The amounts for the three months ended June 30, 2022 reflect higher natural gas costs incurred than were anticipated in rates. During the six months ended June 30, 2022, we continued to recover natural gas costs we under-collected from our customers in 2021, related to the extreme weather. As these amounts were billed to customers, they were reflected in retail revenues with an offsetting decrease in other utility revenues. The negative amount during this period also relates to the over-collection of natural gas costs recorded in a regulatory liability due to these costs being lower than what was anticipated in rates. See Note 6, Regulatory Assets and Liabilities, for more information. The negative amount for the three months ended June 30, 2021 primarily relates to the approval by our utility commissions to recover from customers, over the second quarter of 2021, the higher natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. As these amounts were billed to customers, they were reflected in retail revenues with an offsetting decrease in other utility revenues. For the six months ended June 30, 2021, in addition to costs related to the extreme weather event, we incurred higher natural gas costs as a result of an increase in the price of natural gas. See Note 23, Regulatory Environment, for more information. Other Natural Gas Operating Revenues We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. 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) 2022 2021 2022 2021 Wind generation revenues $ 21.3 $ 14.5 $ 57.5 $ 30.3 We Power revenues (1) 5.8 5.8 11.7 11.6 Appliance service revenues 4.5 4.4 9.1 9.1 Total other non-utility operating revenues $ 31.6 $ 24.7 $ 78.3 $ 51.0 (1) As part of the construction of the We Power EGUs, 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) 2022 2021 2022 2021 Late payment charges $ 16.3 $ 17.3 $ 29.9 $ 32.3 Alternative revenues (1) (11.3) 2.9 (17.3) 9.1 Other 1.7 1.7 2.6 2.9 Total other operating revenues $ 6.7 $ 21.9 $ 15.2 $ 44.3 (1) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges.

CREDIT LOSSES

CREDIT LOSSES	6 Months Ended
	Jun. 30, 2022
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 wind 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, 2022 and December 31, 2021, by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated June 30, 2022 Accounts receivable and unbilled revenues $ 1,029.1 $ 485.2 $ 79.9 $ 1,594.2 $ 23.7 $ 5.6 $ 1,623.5 Allowance for credit losses 78.0 91.0 6.8 175.8 — — 175.8 Accounts receivable and unbilled revenues, net (1) $ 951.1 $ 394.2 $ 73.1 $ 1,418.4 $ 23.7 $ 5.6 $ 1,447.7 Total accounts receivable, net – past due greater than 90 days (1) $ 71.6 $ 66.8 $ 7.4 $ 145.8 $ — $ — $ 145.8 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.2 % 100.0 % — % 93.6 % — % — % 93.6 % (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2021 Accounts receivable and unbilled revenues $ 1,053.1 $ 523.1 $ 105.7 $ 1,681.9 $ 17.0 $ 5.1 $ 1,704.0 Allowance for credit losses 84.0 105.5 8.8 198.3 — — 198.3 Accounts receivable and unbilled revenues, net (1) $ 969.1 $ 417.6 $ 96.9 $ 1,483.6 $ 17.0 $ 5.1 $ 1,505.7 Total accounts receivable, net – past due greater than 90 days (1) $ 46.5 $ 36.6 $ 3.4 $ 86.5 $ — $ — $ 86.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.6 % 100.0 % — % 94.8 % — % — % 94.8 % (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, 2022, $782.2 million, or 54.0%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. A rollforward of the allowance for credit losses by reportable segment is included below: Three Months Ended June 30, 2022 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 85.7 $ 107.0 $ 7.9 $ 200.6 Provision for credit losses 11.8 7.1 (0.1) 18.8 Provision for credit losses deferred for future recovery or refund (5.4) (11.2) — (16.6) Write-offs charged against the allowance (22.1) (17.9) (1.2) (41.2) Recoveries of amounts previously written off 8.0 6.0 0.2 14.2 Balance at June 30, 2022 $ 78.0 $ 91.0 $ 6.8 $ 175.8 Six Months Ended June 30, 2022 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 84.0 $ 105.5 $ 8.8 $ 198.3 Provision for credit losses 23.6 18.4 0.1 42.1 Provision for credit losses deferred for future recovery or refund 3.4 0.9 — 4.3 Write-offs charged against the allowance (50.9) (45.2) (2.6) (98.7) Recoveries of amounts previously written off 17.9 11.4 0.5 29.8 Balance at June 30, 2022 $ 78.0 $ 91.0 $ 6.8 $ 175.8 On a consolidated basis, there was a $22.5 million decrease in the allowance for credit losses at June 30, 2022, compared to December 31, 2021. The decrease was driven by customer write-offs related to collection practices returning to pre-pandemic levels in 2021, including the restoration of our ability to disconnect customers. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. Partially offsetting the decrease in the allowance for credit losses, we believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. Three Months Ended June 30, 2021 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 129.5 $ 122.0 $ 7.6 $ 259.1 Provision for credit losses 9.4 5.2 1.0 15.6 Provision for credit losses deferred for future recovery or refund (12.2) (18.9) — (31.1) Write-offs charged against the allowance (16.5) (4.0) (0.6) (21.1) Recoveries of amounts previously written off 4.2 4.7 0.3 9.2 Balance at June 30, 2021 $ 114.4 $ 109.0 $ 8.3 $ 231.7 Six Months Ended June 30, 2021 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 102.1 $ 111.6 $ 6.4 $ 220.1 Provision for credit losses 23.1 12.3 2.3 37.7 Provision for credit losses deferred for future recovery or refund 10.1 (15.8) — (5.7) Write-offs charged against the allowance (35.0) (6.8) (1.1) (42.9) Recoveries of amounts previously written off 14.1 7.7 0.7 22.5 Balance at June 30, 2021 $ 114.4 $ 109.0 $ 8.3 $ 231.7 The increase in the allowance for credit losses at June 30, 2021, compared to December 31, 2020, was driven by higher past due accounts receivable balances related to our utility operations, primarily associated with our residential customers. This increase in accounts receivable balances in arrears related to the continued economic disruptions caused by the COVID-19 pandemic, including high unemployment rates. However, as seen in the quarterly rollforward above, the allowance for credit losses began to decrease in the second quarter of 2021, which we believe was related to the start of normal collection practices in our Wisconsin and Illinois service territories.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	6 Months Ended
	Jun. 30, 2022
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, 2022 and December 31, 2021. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2021 Annual Report on Form 10-K. (in millions) June 30, 2022 December 31, 2021 Regulatory assets Pension and OPEB costs $ 762.6 $ 802.3 Plant retirement related items 705.9 722.3 Environmental remediation costs 621.6 630.9 Income tax related items 457.0 458.8 Asset retirement obligations 180.6 194.2 System support resource 126.7 129.5 Energy costs recoverable through rate adjustments 120.0 85.4 Securitization 96.1 100.7 MERC extraordinary natural gas costs 47.1 59.7 Derivatives (1) 38.5 33.1 Uncollectible expense 30.0 42.6 Energy efficiency programs 23.9 22.0 Other, net 68.9 85.6 Total regulatory assets $ 3,278.9 $ 3,367.1 Balance sheet presentation Amounts recoverable from customers $ 134.2 $ 102.3 Regulatory assets 3,144.7 3,264.8 Total regulatory assets $ 3,278.9 $ 3,367.1 (1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 14, Derivative Instruments, for more information on our derivative asset and liability balances. (in millions) June 30, 2022 December 31, 2021 Regulatory liabilities Income tax related items $ 1,970.3 $ 1,998.5 Removal costs 1,252.2 1,248.0 Pension and OPEB benefits 388.3 397.3 Derivatives (1) 247.7 124.1 Energy costs refundable through rate adjustments (2) 78.3 13.7 Electric transmission costs (3) 42.9 84.2 Uncollectible expense 33.4 37.1 Earnings sharing mechanisms (3) 17.1 28.4 Other, net 53.8 29.0 Total regulatory liabilities $ 4,084.0 $ 3,960.3 Balance sheet presentation Other current liabilities $ 83.9 $ 14.3 Regulatory liabilities 4,000.1 3,946.0 Total regulatory liabilities $ 4,084.0 $ 3,960.3 (1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 14, Derivative Instruments, for more information on our derivative asset and liability balances. (2) The increase in these regulatory liabilities was primarily related to lower natural gas costs incurred during 2022, compared to what was anticipated in rates. (3) The decrease in these regulatory liability balances was primarily related to the PSCW's approval of certain accounting treatments that allowed our Wisconsin utilities to forego applying for a 2022 base rate increase, and instead maintain base rates consistent with 2021 levels. Among the accounting treatments approved was the amortization of certain regulatory liability balances in 2022, to offset a portion of the forecasted revenue deficiency. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	6 Months Ended
	Jun. 30, 2022
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	PROPERTY, PLANT, AND EQUIPMENT Wisconsin Segment Plant to be Retired Columbia Units 1 and 2 As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by June 1, 2026. The retirement date for these plants was pushed back from the end of 2023 for unit 1 and the end of 2024 for unit 2. See Note 23, Regulatory Environment, for more information on the Columbia generating units' retirement. The net book value of WPS's ownership share of unit 1 and unit 2 was $86.6 million and $185.6 million, respectively, at June 30, 2022. These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheets. 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. Public Service Building and Steam Tunnel Assets During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s PSB. The damage to the building and adjacent steam tunnel assets from the flooding and steam was extensive and required significant repairs and restorations. As of June 30, 2022, WE had incurred $95.3 million of costs related to these repairs and restorations. In 2020, WE received $20.0 million of insurance proceeds to cover a portion of these costs and wrote off $12.5 million of costs that we do not intend to seek recovery for through other operation and maintenance expense. In the first quarter of 2022, WE received $41.0 million of insurance proceeds as a result of a settlement that was reached in February 2022. The remaining $21.8 million of costs is expected to be recovered through rates. In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, and in light of the agreement with insurers noted above, we do not currently expect a significant impact to our future results of operations.

COMMON EQUITY

COMMON EQUITY	6 Months Ended
	Jun. 30, 2022
Equity [Abstract]
COMMON EQUITY	COMMON EQUITY Stock-Based Compensation During the six months ended June 30, 2022, 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) 437,269 Restricted shares (2) 72,211 Performance units 171,492 (1) Stock options awarded had a weighted-average exercise price of $96.04 and a weighted-average grant date fair value of $14.71 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $96.04 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 2021 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 Dividends On July 21, 2022, our Board of Directors declared a quarterly cash dividend of $0.7275 per share, payable on September 1, 2022, to shareholders of record on August 12, 2022.

SHORT-TERM DEBT AND LINES OF CR

SHORT-TERM DEBT AND LINES OF CREDIT	6 Months Ended
	Jun. 30, 2022
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, 2022 December 31, 2021 Commercial paper Amount outstanding $ 1,626.8 $ 1,896.1 Weighted-average interest rate on amounts outstanding 1.90 % 0.26 % Operating expense loans Amount outstanding (1) $ 2.3 $ 0.9 (1) Coyote Ridge and Tatanka Ridge 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, 2022 was $1,421.5 million with a weighted-average interest rate during the period of 0.68%. 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, 2022 WEC Energy Group September 2026 $ 1,500.0 WE September 2026 500.0 WPS (1) September 2026 400.0 WG September 2026 350.0 PGL September 2026 350.0 Total short-term credit capacity $ 3,100.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 1,626.8 Available capacity under existing agreements $ 1,470.9 (1) In April 2022, WPS received approval from the PSCW to extend the maturity of its facility to September 2026.

LEASES

LEASES	6 Months Ended
	Jun. 30, 2022
Lessee Disclosure [Abstract]
LEASES	LEASES WE and WPS have partnered with an unaffiliated utility to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system in Kenosha County, Wisconsin. WE and WPS own 75% and 15%, respectively, of Paris. Once fully constructed, WE and WPS will collectively own 180 MW of solar generation and 99 MW of battery storage of this projec t. The PSCW has approved the acquisition and construction of P aris, and commercial operation for the solar portion of the project is targeted in 2023. Related to their investment in Paris, WE and WPS, along with their unaffiliated utility partner, entered into several land leases in Kenosha County, Wisconsin that commenced in the second quarter of 2022. 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. The lease payments will be recovered through rates. Our total obligation under the land-related finance leases for Paris was approximately $52.5 million at June 30, 2022, and will decrease to zero over the remaining lives of the leases. Long-term lease liabilities related to our finance land leases for Paris were included in long-term debt on the balance sheet. Our finance lease right of use asset related to Paris was $52.5 million as of June 30, 2022, and was included in property, plant, and equipment on our balance sheet. In accordance with Accounting Standards Codification Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the expense recognition pattern associated with Paris leases resembles that of an operating lease, as amortization of the right of use assets has been modified from what would typically be recorded for a finance lease under Topic 842. The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset in accordance with Subtopic 980-842 on our balance sheet. At June 30, 2022, our weighted-average discount rate for the Paris finance leases was 5.28%. We used the fully collateralized incremental borrowing rates 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 leases for Paris as of June 30, 2022, were as follows: (in millions) Six months ended December 31, 2022 $ 0.7 2023 2.2 2024 2.3 2025 2.3 2026 2.4 2027 2.4 Thereafter 176.0 Total minimum lease payments 188.3 Less: Interest (135.8) Present value of minimum lease payments 52.5 Less: Short-term lease liabilities — Long-term lease liabilities $ 52.5

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	6 Months Ended
	Jun. 30, 2022
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) June 30, 2022 December 31, 2021 Natural gas in storage $ 244.4 $ 326.0 Materials and supplies 242.7 225.3 Fossil fuel 85.1 84.5 Total $ 572.2 $ 635.8 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, 2022, we had a temporary LIFO liquidation credit of $107.6 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end. Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

INCOME TAXES

INCOME TAXES	6 Months Ended
	Jun. 30, 2022
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, 2022 Three Months Ended June 30, 2021 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 73.7 21.0 % $ 69.1 21.0 % State income taxes net of federal tax benefit 22.2 6.3 % 20.8 6.3 % PTCs (22.9) (6.5) % (13.5) (4.1) % Federal excess deferred tax amortization (8.4) (2.4) % (7.9) (2.4) % Federal excess deferred tax amortization – Wisconsin unprotected (0.2) — % (16.3) (5.0) % Other (1.0) (0.3) % 1.9 0.6 % Total income tax expense $ 63.4 18.1 % $ 54.1 16.4 % Six Months Ended June 30, 2022 Six Months Ended June 30, 2021 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 219.2 21.0 % $ 191.9 21.0 % State income taxes net of federal tax benefit 65.8 6.3 % 57.7 6.3 % PTCs (67.7) (6.5) % (47.5) (5.2) % Federal excess deferred tax amortization (24.2) (2.3) % (22.5) (2.5) % Federal excess deferred tax amortization – Wisconsin unprotected (0.5) (0.1) % (46.6) (5.1) % Other (2.1) (0.2) % (4.0) (0.4) % Total income tax expense $ 190.5 18.2 % $ 129.0 14.1 % The effective tax rates of 18.1% and 18.2% for the three and six months ended June 30, 2022, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment 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 effective tax rates of 16.4% and 14.1% for the three and six months ended June 30, 2021, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in wind generation facilities in our non-utility energy infrastructure segment and the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. Effective January 1, 2020, in accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities began amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. In addition, the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, drove a decrease in the effective tax rate. These items were partially offset by state income taxes. The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on unprotected tax benefits.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	6 Months Ended
	Jun. 30, 2022
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTSFair 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 are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our derivative instruments categorized as Level 3 consisted of both FTRs and TCRs at June 30, 2022 and of only FTRs at December 31, 2021. These derivative instruments 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, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 108.0 $ 17.3 $ — $ 125.3 FTRs and TCRs — — 19.9 19.9 Coal contracts — 74.8 — 74.8 Total derivative assets $ 108.0 $ 92.1 $ 19.9 $ 220.0 Investments held in rabbi trust $ 49.7 $ — $ — $ 49.7 Derivative liabilities Natural gas contracts $ 25.8 $ 9.6 $ — $ 35.4 December 31, 2021 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 46.4 $ 18.2 $ — $ 64.6 FTRs — — 2.4 2.4 Coal contracts — 53.0 — 53.0 Total derivative assets $ 46.4 $ 71.2 $ 2.4 $ 120.0 Investments held in rabbi trust $ 79.6 $ — $ — $ 79.6 Derivative liabilities Natural gas contracts $ 8.4 $ 6.7 $ — $ 15.1 The derivative assets and liabilities listed in the tables above include options, swaps, 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 SPP Integrated Marketplace, respectively. We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. During the three months ended June 30, 2022, we recorded $10.1 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $5.8 million of net unrealized gains recorded during the same quarter in 2021. For the six months ended June 30, 2022, we recorded $13.4 million of net unrealized losses in earnings related to the investments held at the end of the period, compared with $9.8 million of net unrealized gains recorded during the same period in 2021. 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) 2022 2021 2022 2021 Balance at the beginning of the period $ 1.0 $ 0.9 $ 2.4 $ 2.4 Purchases 21.9 6.0 21.9 6.1 Realized and unrealized gains included in earnings (1) 1.8 — 1.8 — Settlements (4.8) (1.5) (6.2) (3.1) Balance at the end of the period $ 19.9 $ 5.4 $ 19.9 $ 5.4 Gains included in earnings attributable to the change in unrealized gains of Level 3 derivatives held at the end of the reporting period (1) $ 0.9 $ — $ 0.9 $ — (1) Amounts relate to FTRs and TCRs acquired by our non-utility wind parks. These realized and unrealized gains and losses are recorded in operating revenues on our income statements. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: June 30, 2022 December 31, 2021 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 26.4 $ 30.4 $ 30.3 Long-term debt, including current portion (1) 13,518.7 12,530.8 13,563.4 14,819.4 (1) The carrying amount of long-term debt excludes finance lease obligations of $179.1 million and $129.7 million at June 30, 2022 and December 31, 2021, 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, 2022
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 not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below were designated as hedging instruments. June 30, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts (1) $ 116.4 $ 30.0 $ 60.6 $ 14.0 FTRs and TCRs 19.9 — 2.4 — Coal contracts 53.5 — 44.0 — Total current 189.8 30.0 107.0 14.0 Long-term Natural gas contracts (1) 8.9 5.4 4.0 1.1 Coal contracts 21.3 — 9.0 — Total long-term 30.2 5.4 13.0 1.1 Total $ 220.0 $ 35.4 $ 120.0 $ 15.1 (1) Our natural gas derivative assets increased from December 31, 2021 to June 30, 2022 primarily due to the significant increase in natural gas prices. Realized gains and losses on derivatives used in our regulatory utility operations are recorded in cost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations are recorded in operating revenues on the income statements. Our estimated notional sales volumes and realized gains and losses were as follows: Three Months Ended June 30, 2022 Three Months Ended June 30, 2021 (in millions) Volumes Gains Volumes Gains Natural gas contracts 41.1 Dth $ 108.9 47.9 Dth $ 4.8 FTRs and TCRs 7.0 MWh 4.3 7.4 MWh 10.2 Total $ 113.2 $ 15.0 Six Months Ended June 30, 2022 Six Months Ended June 30, 2021 (in millions) Volumes Gains Volumes Gains (Losses) Natural gas contracts 100.6 Dth $ 140.5 107.7 Dth $ (2.7) FTRs and TCRs 14.0 MWh 5.3 15.8 MWh 12.3 Total $ 145.8 $ 9.6 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, 2022 and December 31, 2021, we had posted cash collateral of $14.1 million and $13.9 million, respectively. These amounts were recorded on our balance sheets in other current assets. At June 30, 2022 and December 31, 2021, we had also received cash collateral of $98.5 million and $13.2 million, respectively. These amounts were recorded on our balance sheets in other current liabilities. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: June 30, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 220.0 $ 35.4 $ 120.0 $ 15.1 Gross amount not offset on the balance sheet (110.1) (1) (27.8) (2) (15.2) (3) (9.2) (4) Net amount $ 109.9 $ 7.6 $ 104.8 $ 5.9 (1) Includes cash collateral received of $84.2 million. (2) Includes cash collateral posted of $1.9 million. (3) Includes cash collateral received of $6.4 million. (4) Includes cash collateral posted of $0.4 million. Cash Flow Hedges Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps provided a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes. As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses were deferred in accumulated other comprehensive loss and were amortized to interest expense as interest was accrued on the 2007 Junior Notes. 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 table below shows the amounts related to these cash flow hedges that were reclassified to interest expense, along with our total interest expense on the income statements: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense $ 0.1 $ (1.3) $ 0.2 $ (2.7) Total interest expense line item on the income statements 119.8 120.0 237.4 239.5 We estimate that during the next twelve months $0.4 million will be reclassified from accumulated other comprehensive loss as a decrease to interest expense.

GUARANTEES

GUARANTEES	6 Months Ended
	Jun. 30, 2022
Guarantees [Abstract]
GUARANTEES	GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed at June 30, 2022 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 83.8 $ 10.5 $ 0.2 $ 73.1 Surety bonds (2) 12.9 12.9 — — Other guarantees (3) 9.5 — — 9.5 Total guarantees $ 106.2 $ 23.4 $ 0.2 $ 82.6 (1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (2) Primarily for 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, 2022
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	EMPLOYEE BENEFITS The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Service cost $ 14.2 $ 13.6 $ 26.6 $ 27.5 Interest cost 22.4 21.7 45.2 43.6 Expected return on plan assets (52.5) (50.1) (105.2) (100.7) Loss on plan settlement 2.2 1.9 2.2 2.0 Amortization of prior service cost 0.4 0.4 0.8 0.8 Amortization of net actuarial loss 19.1 28.2 38.2 55.6 Net periodic benefit cost $ 5.8 $ 15.7 $ 7.8 $ 28.8 OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Service cost $ 3.3 $ 3.6 $ 7.1 $ 7.8 Interest cost 3.8 3.6 7.7 7.2 Expected return on plan assets (17.3) (16.6) (34.5) (33.0) Amortization of prior service credit (3.9) (3.9) (7.9) (7.9) Amortization of net actuarial gain (6.3) (6.5) (12.3) (12.2) Net periodic benefit credit $ (20.4) $ (19.8) $ (39.9) $ (38.1) During the six months ended June 30, 2022, we made contributions and payments of $5.7 million related to our pension plans and $2.9 million related to our OPEB plans. We expect to make contributions and payments of $5.5 million related to our pension plans during the remainder of 2022, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to make any contributions or payments related to our OPEB plans during the remainder of 2022.

GOODWILL AND INTANGIBLES

GOODWILL AND INTANGIBLES	6 Months Ended
	Jun. 30, 2022
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, 2022. We had no changes to the carrying amount of goodwill during the six months ended June 30, 2022. (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, 2022. Intangible Assets At June 30, 2022 and December 31, 2021, we had $5.7 million of indefinite-lived intangible assets primarily related to a MGU trade name obtained through an acquisition, which is included in other long-term assets on our balance sheets. We had no changes to the carrying amount of these intangible assets during the six months ended June 30, 2022. Intangible Liabilities The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. June 30, 2022 December 31, 2021 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount PPAs (1) $ 87.9 $ (10.4) $ 77.5 $ 87.9 $ (6.5) $ 81.4 Proxy revenue swap (2) 7.2 (2.4) 4.8 7.2 (2.1) 5.1 Interconnection agreements (3) 4.7 (0.6) 4.1 4.7 (0.5) 4.2 Total intangible liabilities $ 99.8 $ (13.4) $ 86.4 $ 99.8 $ (9.1) $ 90.7 (1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is 10 years. (2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap is seven years. (3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 18 years. Amortization related to these intangibles for the three and six months ended June 30, 2022, was $2.1 million and $4.3 million, respectively. Amortization for the three and six months ended June 30, 2021, was $1.9 million and $3.7 million, respectively. Amortization for the next five years, including amounts recorded through June 30, 2022, is estimated to be: For the Years Ending December 31 (in millions) 2022 2023 2024 2025 2026 Amortization to be recorded in operating revenues $ 8.5 $ 8.4 $ 8.4 $ 8.4 $ 8.4 Amortization to be recorded in 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, 2022
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, 2022 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,795.0 $ 23.2 $ 1,818.2 Add: Earnings from equity method investment 42.6 0.4 43.0 Add: Capital contributions 9.2 — 9.2 Less: Distributions 33.2 — 33.2 Balance at end of period $ 1,813.6 $ 23.6 $ 1,837.2 Three Months Ended June 30, 2021 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,741.9 $ 31.7 $ 1,773.6 Add: Earnings from equity method investment 40.7 0.6 41.3 Less: Distributions 32.8 — 32.8 Less: Other 0.1 — 0.1 Balance at end of period $ 1,749.7 $ 32.3 $ 1,782.0 Six Months Ended June 30, 2022 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,766.9 $ 22.5 $ 1,789.4 Add: Earnings from equity method investment 83.6 1.1 84.7 Add: Capital contributions 30.3 — 30.3 Less: Distributions 67.2 — 67.2 Balance at end of period $ 1,813.6 $ 23.6 $ 1,837.2 Six Months Ended June 30, 2021 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,733.5 $ 30.8 $ 1,764.3 Add: Earnings from equity method investment 82.4 1.5 83.9 Less: Distributions 66.2 — 66.2 Balance at end of period $ 1,749.7 $ 32.3 $ 1,782.0 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) 2022 2021 2022 2021 Charges to ATC for services and construction $ 4.7 $ 5.7 $ 10.9 $ 11.7 Charges from ATC for network transmission services 90.8 89.1 181.9 181.7 Our balance sheets included the following receivables and payables for services provided to or received from ATC: (in millions) June 30, 2022 December 31, 2021 Accounts receivable for services provided to ATC $ 1.4 $ 2.0 Accounts payable for services received from ATC 30.6 30.2 Amounts due from ATC for transmission infrastructure upgrades (1) 14.9 13.0 (1) The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of Paris, as well as WE's continued construction of Badger Hollow II. Summarized financial data for ATC is included in the tables below: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Income statement data Operating revenues $ 191.6 $ 185.9 $ 382.6 $ 374.6 Operating expenses 95.2 92.4 190.7 187.5 Other expense, net 28.8 28.1 56.8 56.6 Net income $ 67.6 $ 65.4 $ 135.1 $ 130.5 (in millions) June 30, 2022 December 31, 2021 Balance sheet data Current assets $ 106.0 $ 89.8 Noncurrent assets 5,801.8 5,628.1 Total assets $ 5,907.8 $ 5,717.9 Current liabilities $ 482.7 $ 436.9 Long-term debt 2,562.4 2,513.0 Other noncurrent liabilities 438.5 422.0 Members' equity 2,424.2 2,346.0 Total liabilities and members' equity $ 5,907.8 $ 5,717.9

SEGMENT INFORMATION

SEGMENT INFORMATION	6 Months Ended
	Jun. 30, 2022
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, 2022, 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 and non-utility operations of MERC and MGU. • 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 our ownership interests in the following wind generating facilities: ▪ 90% ownership interest in Bishop Hill III, located in Henry County, Illinois, ▪ 80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota, ▪ 90% ownership interest in Upstream, located in Antelope County, Nebraska, ▪ 90% ownership interest in Blooming Grove, located in McLean County, Illinois, ▪ 85% ownership interest in Tatanka Ridge, located in Deuel County, South Dakota, and ▪ 90% ownership interest in Jayhawk, located in Bourbon and Crawford counties, Kansas. See Note 2, Acquisitions, for more information on Jayhawk. • 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 WEC Business Services LLC. All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three and six months ended June 30, 2022 and 2021: 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, 2022 External revenues $ 1,557.4 $ 442.4 $ 99.9 $ 2,099.7 $ — $ 28.1 $ 0.1 $ — $ 2,127.9 Intersegment revenues — — — — — 115.5 — (115.5) — Other operation and maintenance 337.9 79.1 22.9 439.9 — 13.9 (0.9) (3.9) 449.0 Depreciation and amortization 187.7 57.4 10.2 255.3 — 34.3 6.8 (16.8) 279.6 Equity in earnings of transmission affiliates — — — — 43.0 — — — 43.0 Interest expense 135.6 18.0 3.2 156.8 4.8 17.4 24.6 (83.8) 119.8 Income tax expense (benefit) 49.3 21.2 0.9 71.4 9.3 (7.3) (10.0) — 63.4 Net income (loss) 148.7 56.4 2.7 207.8 29.0 80.3 (29.3) — 287.8 Net income (loss) attributed to common shareholders 148.4 56.4 2.7 207.5 29.0 80.3 (29.3) — 287.5 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, 2021 External revenues $ 1,307.5 $ 275.5 $ 72.1 $ 1,655.1 $ — $ 21.0 $ 0.1 $ — $ 1,676.2 Intersegment revenues — — — — — 112.5 — (112.5) — Other operation and maintenance 346.1 90.8 21.2 458.1 — 12.4 (2.8) (3.9) 463.8 Depreciation and amortization 179.8 54.0 9.4 243.2 — 31.3 6.4 (14.7) 266.2 Equity in earnings of transmission affiliates — — — — 41.3 — — — 41.3 Interest expense 139.8 16.6 1.5 157.9 4.8 17.9 24.6 (85.2) 120.0 Income tax expense 23.1 16.0 0.8 39.9 9.4 0.7 4.1 — 54.1 Net income (loss) 146.8 43.6 2.5 192.9 27.0 68.2 (12.4) — 275.7 Net income (loss) attributed to common shareholders 146.5 43.6 2.5 192.6 27.0 68.8 (12.4) — 276.0 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, 2022 External revenues $ 3,499.7 $ 1,124.5 $ 340.8 $ 4,965.0 $ — $ 70.7 $ 0.3 $ — $ 5,036.0 Intersegment revenues — — — — — 232.4 — (232.4) — Other operation and maintenance 650.5 192.7 47.5 890.7 — 24.8 (6.6) (5.5) 903.4 Depreciation and amortization 374.8 114.2 20.2 509.2 — 68.3 13.3 (33.1) 557.7 Equity in earnings of transmission affiliates — — — — 84.7 — — — 84.7 Interest expense 271.9 35.7 6.5 314.1 9.7 34.6 47.2 (168.2) 237.4 Income tax expense (benefit) 144.7 63.3 11.3 219.3 18.2 (12.2) (34.8) — 190.5 Net income (loss) 437.1 169.8 34.2 641.1 56.8 173.6 (15.7) — 855.8 Net income (loss) attributed to common shareholders 436.5 169.8 34.2 640.5 56.8 171.8 (15.7) — 853.4 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, 2021 External revenues $ 3,039.2 $ 978.9 $ 305.4 $ 4,323.5 $ — $ 43.9 $ 0.2 $ — $ 4,367.6 Intersegment revenues — — — — — 227.2 — (227.2) — Other operation and maintenance 688.0 200.1 44.4 932.5 — 21.3 (4.6) (5.5) 943.7 Depreciation and amortization 356.0 106.7 18.6 481.3 — 62.3 13.0 (29.0) 527.6 Equity in earnings of transmission affiliates — — — — 83.9 — — — 83.9 Interest expense 279.9 33.1 3.0 316.0 9.7 35.9 48.8 (170.9) 239.5 Income tax expense (benefit) 71.2 57.4 9.2 137.8 19.2 0.8 (28.8) — 129.0 Net income 403.4 155.7 27.2 586.3 55.0 139.5 5.2 — 786.0 Net income attributed to common shareholders 402.8 155.7 27.2 585.7 55.0 140.2 5.2 — 786.1

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 2022
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 source of funds to satisfy the debt obligation. The bondholders have no recourse to WE or any of WE's affiliates other than WEPCo Environmental Trust. 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 an indenture trustee of WEPCo Environmental Trust. 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 sheet. (in millions) June 30, 2022 December 31, 2021 Assets Other current assets (restricted cash) $ 3.1 $ 2.4 Regulatory assets 96.1 100.7 Other long-term assets (restricted cash) 0.6 0.6 Liabilities Current portion of long-term debt 8.8 8.8 Other current liabilities (accrued interest) 0.1 0.1 Long-term debt 98.4 102.7 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, 2022 and December 31, 2021, our equity investment in ATC was $1,813.6 million and $1,766.9 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, 2022 and December 31, 2021, our equity investment in ATC Holdco was $23.6 million and $22.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco. See Note 18, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets. Power Purchase Commitment On May 31, 2022, WE's PPA with LSP-Whitewater Limited Partnership that represented a variable interest expired. This agreement was for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, and we accounted for it as a finance lease. In November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022 upon the expiration of the PPA. Concurrent with the execution of the tolling agreement, WE and WPS also entered into an agreement to purchase the natural gas-fired cogeneration facility for $72.7 million. This purchase agreement is subject to regulatory approval by the PSCW, which is expected by the end of 2022. The tolling agreement extends until the earlier of the closing of the asset purchase or December 31, 2022. The tolling agreement continues to represent a variable interest since its terms are substantially similar to the terms of the PPA. After examining the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we have determined we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the tolling agreement. Similar to the PPA, we account for the tolling agreement as a finance lease. We have $1.9 million of required capacity payments over the remaining term of the tolling agreement. We believe that the required capacity payments under the agreement will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	6 Months Ended
	Jun. 30, 2022
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 wind 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 wind generating facilities. Our minimum future commitments related to these purchase obligations as of June 30, 2022, including those of our subsidiaries, were approximately $10.5 billion. Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. Air Quality Cross State Air Pollution Rule – Good Neighbor Plan The EPA issued a proposed rule that would update and expand the Cross-State Air Pollution Rule's ozone-season NOx program to address the 2015 ozone NAAQS, resulting in more stringent regulation of ozone-season NOx emissions from EGUs in 26 states, relying on authorization through the CAA's “good neighbor provision." As part of the proposed rule, expected to take effect in May 2023, the EPA would establish a new trading program that would impose lower NOx emissions budgets on states, at levels that the EPA projected would be achievable through full operation of existing EGU emissions control equipment beginning during ozone season 2023, and through installation of additional control equipment at both EGU and non-EGU stationary sources by the start of the 2026 ozone season, as well as planned plant retirements. Based on a review of our existing units' 2020 and 2021 actual ozone season emissions and projected future emissions versus proposed NOx ozone season allocations, we anticipate that we should be able to comply with the expanded rule requirements without procuring additional allowances on the open market. Our RICE units in the Upper Peninsula of Michigan and planned RICE units in Wisconsin are not subject to this rule as proposed as each unit is expected to be less than 25 MW. We note that, to the extent we use RICE engines for natural gas distribution operations, those engines may be subject to the emission limits and operational requirements of the rule beginning in 2026. In June 2022, we submitted comments on this proposed rule seeking clarification of its applicability, as well as other items, and we will closely monitor the final rule for any changes from the proposed rule. National Ambient Air Quality Standards Ozone After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard. Under Executive Order 13990, the Biden Administration ordered that all agencies review existing regulations, orders, guidance documents, policies, and similar actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021. In October 2021, the EPA announced that it will reconsider the December 2020 decision to retain the 2015 ozone standards with no changes and that it is targeting the end of 2023 to complete this reconsideration. The EPA issued final nonattainment area designations for the 2015 ozone standard in April 2018. The following counties within our Wisconsin service territories were designated as partial nonattainment: Door, Kenosha, Sheboygan, Manitowoc, and Northern Milwaukee/Ozaukee. The area designations were challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. As a result of the July 2020 remand, in June 2021, the EPA published its final action to revise the nonattainment area designations and/or boundaries for 13 counties associated with six nonattainment areas, including several in Illinois and Wisconsin. Under the new designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the nonattainment area. Additionally, the Chicago, IL-IN-WI nonattainment area now includes an expanded portion of Kenosha County, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties were also expanded. In April 2022, the EPA proposed to find that the Milwaukee and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, and will be adjusted to "moderate" nonattainment status for the 2015 standard. Accordingly, Wisconsin must submit State Implementation Plan revisions to address the reclassifications. A final rulemaking for the designations is expected in October 2022. In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations adopted the standard and incorporated by reference the federal air pollution monitoring requirements related to the standard. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules. Particulate Matter In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine particulate matter. The EPA determined that no revisions were necessary to the current annual standard of 12 µg/m 3 or the 24-hour standard of 35 µg/m 3 . This determination was also subject to review under Executive Order 13990 and in June 2021, the EPA announced it would reconsider the December 2020 decision. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the particulate matter NAAQS to below the current level of 12 µg/m 3 , while retaining the 24-hour standard. In March 2022, the EPA’s CASAC sent a letter to the EPA finalizing its peer review of the particulate matter standards. Based on their review, the majority of the members of the CASAC found that lowering the annual standard to within a range of 8 to 10 µg/m 3 was appropriate, while a minority of the members of the committee found that a range of 10 to 11 µg/m 3 would be appropriate. Additionally, a majority of the CASAC members favored lowering the 24-hour standard, while a minority concurred with EPA’s preliminary conclusion to retain the 24-hour standard without revision. In May 2022, the EPA released its staff-written Policy Assessment for the reconsideration of the standard. Similar to the CASAC findings, the EPA staff found that conditions supported either an annual standard in the 10 to 12 µg/m 3 range or in the 8 to 10 µg/m 3 range. A proposed rule is expected in August 2022, and a final rule is expected in spring 2023. All counties within our service territories are in attainment with the current 2012 standards. If the EPA lowers the annual standard to 10 or 11 µg/m 3 , our generating facilities within our service territories should remain in attainment. If the EPA lowers it to below 10 µg/m 3 , there could be some non-attainment areas that may affect permitting of some smaller ancillary equipment located at our facilities. Climate Change The ACE rule, which replaced the Clean Power Plan, was vacated by the D.C. Circuit Court of Appeals in January 2021. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling vacating the EPA's ACE rule and in June 2022, the Supreme Court issued its decision. The Supreme Court found that the EPA may regulate GHGs under section 111 of the CAA but cannot rely on generation shifting to lower carbon emitting sources to do so. Based on an updated EPA regulatory timeline, we expect a new GHG replacement rule to be proposed in March 2023. In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants; however, it was vacated by the D.C. Circuit Court of Appeals in April 2021. Based on an updated EPA regulatory timeline, we expect a new rule to be proposed in March 2023. We continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions. Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirements in 2024-2025 of OCPP Units 5-8 and the planned retirement by June 2026 of jointly-owned Columbia Units 1-2. See Note 23, Regulatory Environment, for more information on the timing of the 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 making operating refinements, retiring less efficient generating units, and executing our capital plan. Over the longer term, the target for our generation fleet is net-zero CO 2 emissions by 2050. We also continue to reduce methane emissions by improving our natural gas distribution system, 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 utility systems. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental impacts. The federal rule became effective in October 2014 and 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. In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code. This new state rule, NR 111, became effective in June 2020, and the WDNR will apply it 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 a final BTA determination for Valley power plant. We have received interim BTA determinations for PWGS, OCPP Units 5-8 and Weston Units 2, 3, and 4. We believe that existing technology at the PWGS satisfies the BTA requirements; however, a final determination will not be made until the WPDES permit is renewed for this facility, which is expected to be by the third quarter of 2022. We also believe that existing technology installed at the OCPP facility meets the BTA requirements; however, depending on the timing of the permit reissuance, all four generating units may be retired prior to the WDNR making a final BTA decision anticipated in 2025. In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance in 2023. As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to continue to meet this regulation and do not expect to incur significant additional compliance costs. Steam Electric Effluent Limitation Guidelines The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be facility modifications to meet water permit requirements for the BATW system at Weston Unit 3, which is expected to be completed by December 2023. Modifications to OC 7 and OC 8 were completed and placed in-service in mid-2021. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require $100 million in capital investment. In December 2021, the PSCW Division of Energy Regulation and Analysis issued a Certificate of Authority approving the ERGS FGD wastewater treatment system modification. The BATW modifications do not require PSCW approval prior to construction. All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023. In July 2021, the EPA announced that it intends to initiate rulemaking to revise the ELG Rule as modified in 2020. The EPA has stated that the ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process. The EPA plans to propose a revised rule in the fall of 2022. Waters of the United States In December 2021, the EPA and the United States Army Corps of Engineers together released a proposed rule to repeal the April 2020 Navigable Waters Protection Rule that defined WOTUS. The purpose of this proposed rule will be to restore regulations defining WOTUS that were in place prior to 2015 and to update certain provisions to be consistent with relevant Supreme Court decisions. The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction. In January 2022, the Supreme Court granted certiorari in a case to evaluate the proper test for determining whether wetlands are WOTUS. At this point, our projects requiring federal permits are moving ahead, but we are monitoring to better understand potential future impacts. This case, once decided, should provide clarity regarding the definition of WOTUS. We will continue to monitor this litigation and any subsequent agency action. 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, 2022 December 31, 2021 Regulatory assets $ 621.6 $ 630.9 Reserves for future environmental remediation 504.3 532.6 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 are working with the EPA on a closeout process for the Consent Decree and expect that process to be completed in 2023. Joint Ownership Power Plants – Columbia and Edgewater In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric Company, 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 Wisconsin Power and Light Company, Madison Gas and Electric Company, 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. Wisconsin Power and Light Company expects to start the process to close out this Consent Decree in early 2023.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	6 Months Ended
	Jun. 30, 2022
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Six Months Ended June 30 (in millions) 2022 2021 Cash paid for interest, net of amount capitalized $ 234.9 $ 239.9 Cash paid for income taxes, net 37.3 28.2 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 210.2 127.9 Increase in receivable related to insurance proceeds — 39.6 Liabilities accrued for software licensing agreement 7.4 — The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of the 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. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. Our restricted cash also consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEC Infrastructure Wind Holding I LLC and WEPCo Environmental Trust. The restricted cash we received when WECI acquired ownership interests in certain wind generation projects is included in our restricted cash as well. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the wind generation facilities. 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, 2022 December 31, 2021 Cash and cash equivalents $ 30.3 $ 16.3 Restricted cash included in other current assets 21.9 19.6 Restricted cash included in other long term assets 52.7 51.6 Cash, cash equivalents, and restricted cash $ 104.9 $ 87.5

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	6 Months Ended
	Jun. 30, 2022
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Recovery of Natural Gas Costs Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. All of our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs. In March 2021, WE and WG received approval from the PSCW to recover approximately $54 million and $24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs over a period of three months, beginning in April 2021. In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $28 million of natural gas costs in excess of the benchmark set in its GCRM. WPS also recovered these excess costs over a period of three months, beginning in April 2021. PGL and NSG incurred approximately $131 million and $10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates. These costs were recovered over a period of 12 months, which started on April 1, 2021. PGL's and NSG's natural gas costs are being reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation. The ICC could order the refund of any costs determined to be imprudent as part of the reconciliation. A decision regarding this review is expected by the end of 2022. In February 2021, MERC incurred approximately $75 million of natural gas costs in excess of the benchmark set in its GCRM. In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs. MERC will recover $10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $65 million over 27 months, both of which started in September 2021. Recovery of these costs and the issue of prudence has been referred to a contested-case proceeding. As a result of the proceeding, the MPUC could disallow recovery or order the refund of any costs determined to be imprudent. A decision regarding this review is expected during the third quarter of 2022. Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant. Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC 2023 and 2024 Rates In April 2022, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2023. The requested increases in electric rates were driven by capital investments in new wind, solar, and battery storage; capital investments in natural gas generation; reliability investments, including grid hardening projects to bury power lines and strengthen WE's distribution system against severe weather; and changes in wholesale business with other utilities. Many of these investments have already been approved by the PSCW. The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system. In July 2022, WE, WPS, and WG updated their rate requests to reflect recent developments that impacted, as applicable, the respective utility's original proposal for rate increases in 2023. These recent developments included: • Delays in the in-service dates of Darien and the battery portion of Paris due to supply chain disruptions. • WE's decision to extend the operating life of the OCPP due to tight energy supply conditions in MISO and the delay in the renewable energy projects discussed above. The expected retirement of the OCPP units 5 and 6 was delayed one year, until May 2024, and the retirement of units 7 and 8 was delayed approximately 18 months, until late 2025. • Wisconsin Power & Light Company's decision to delay the retirements of the jointly-owned Columbia units. The retirements of the Columbia units, which were originally planned for the end of 2023 and 2024, were delayed until 2026. WPS holds a 27.5% ownership interest in these units. • Increases in the cost of Badger Hollow II. • The effect of anticipated increases in interest rates on borrowing costs. • An industry-wide update to S&P's methodology for assessing the impact of PPAs on utility's credit ratings. The updated rate request proposals include aggregate increases of approximately $30 million for WE, $6 million for WPS, and $2 million for WG from the original proposals and are reflected in the following table: WE WPS WG Proposed 2023 rate increase Electric $ 285.6 million / 9.2% $ 79.4 million / 6.6% N/A Gas $ 55.4 million / 11.7% $ 30.9 million / 8.4% $ 61.9 million / 8.6% Steam $ 3.6 million / 16.5% N/A N/A Proposed ROE (1) 10.0% 10.0% 10.2% Proposed common equity component average on a financial basis (1) 53.0% 53.0% 53.0% (1) The proposed ROEs are consistent with each utilities' currently authorized ROE. The common equity component average for each utility is currently 52.5%. The utilities are proposing to continue using an earnings sharing mechanism. Under the proposed earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility would retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points would be required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings would be required to be refunded to ratepayers. WE and WPS are seeking a limited rate case re-opener for 2024 to address additional revenue requirements associated with generation projects that are expected to be placed into service in 2023 and 2024. In addition, WE and WG are requesting a limited rate case re-opener for 2024 to address additional revenue requirements associated with LNG projects that are expected to be placed into service in 2023 and 2024, respectively. We expect a decision from the PSCW in the fourth quarter of 2022, with any rate adjustments expected to be effective January 1, 2023. The Peoples Gas Light and Coke Company 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 is in effect through 2023. PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending. As of June 30, 2022, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	6 Months Ended
	Jun. 30, 2022
Accounting Standards Update and Change in Accounting Principle [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Government Assistance In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832). The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of: (i) the types of assistance received; (ii) an entity’s accounting for the assistance; and (iii) the effect of the assistance on the entity’s financial statements. The update is effective for annual periods beginning after December 15, 2021. We plan to adopt this pronouncement for our fiscal year ending on December 31, 2022, and we are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

GENERAL INFORMATION (Policies)

GENERAL INFORMATION (Policies)	6 Months Ended
	Jun. 30, 2022
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 at Bishop Hill III, Blooming Grove, Coyote Ridge, Jayhawk, Tatanka Ridge, and Upstream held by third parties.
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, 2021. 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, 2022, are not necessarily indicative of expected results for 2022 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 wind 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
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.
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.
New accounting pronouncements	Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Government Assistance In November 2021, the FASB issued ASU No. 2021-10, Government Assistance (Topic 832). The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of: (i) the types of assistance received; (ii) an entity’s accounting for the assistance; and (iii) the effect of the assistance on the entity’s financial statements. The update is effective for annual periods beginning after December 15, 2021. We plan to adopt this pronouncement for our fiscal year ending on December 31, 2022, and we are currently evaluating the impact this guidance may have on our financial statements and related disclosures.
Other non-utility revenues
Disaggregation of Operating Revenues
Revenue Recognition	As part of the construction of the We Power EGUs, 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, 2022
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 have 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 Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Three Months Ended June 30, 2022 Electric $ 1,221.1 $ — $ — $ 1,221.1 $ — $ — $ — $ 1,221.1 Natural gas 329.5 442.2 95.8 867.5 12.0 — (11.0) 868.5 Total regulated revenues 1,550.6 442.2 95.8 2,088.6 12.0 — (11.0) 2,089.6 Other non-utility revenues — — 4.5 4.5 31.1 — (4.0) 31.6 Total revenues from contracts with customers 1,550.6 442.2 100.3 2,093.1 43.1 — (15.0) 2,121.2 Other operating revenues 6.8 0.2 (0.4) 6.6 100.5 0.1 (100.5) (1) 6.7 Total operating revenues $ 1,557.4 $ 442.4 $ 99.9 $ 2,099.7 $ 143.6 $ 0.1 $ (115.5) $ 2,127.9 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Three Months Ended June 30, 2021 Electric $ 1,083.2 $ — $ — $ 1,083.2 $ — $ — $ — $ 1,083.2 Natural gas 212.7 266.1 66.9 545.7 9.4 — (8.7) 546.4 Total regulated revenues 1,295.9 266.1 66.9 1,628.9 9.4 — (8.7) 1,629.6 Other non-utility revenues — — 4.4 4.4 24.2 — (3.9) 24.7 Total revenues from contracts with customers 1,295.9 266.1 71.3 1,633.3 33.6 — (12.6) 1,654.3 Other operating revenues 11.6 9.4 0.8 21.8 99.9 0.1 (99.9) (1) 21.9 Total operating revenues $ 1,307.5 $ 275.5 $ 72.1 $ 1,655.1 $ 133.5 $ 0.1 $ (112.5) $ 1,676.2 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2022 Electric $ 2,408.6 $ — $ — $ 2,408.6 $ — $ — $ 2,408.6 Natural gas 1,076.3 1,122.1 334.0 2,532.4 27.3 — (25.8) 2,533.9 Total regulated revenues 3,484.9 1,122.1 334.0 4,941.0 27.3 — (25.8) 4,942.5 Other non-utility revenues — — 9.1 9.1 74.8 — (5.6) 78.3 Total revenues from contracts with customers 3,484.9 1,122.1 343.1 4,950.1 102.1 — (31.4) 5,020.8 Other operating revenues 14.8 2.4 (2.3) 14.9 201.0 0.3 (201.0) (1) 15.2 Total operating revenues $ 3,499.7 $ 1,124.5 $ 340.8 $ 4,965.0 $ 303.1 $ 0.3 $ (232.4) $ 5,036.0 (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate Reconciling WEC Energy Group Consolidated Six Months Ended June 30, 2021 Electric $ 2,178.2 $ — $ — $ 2,178.2 $ — $ — $ — $ 2,178.2 Natural gas 840.0 959.6 292.5 2,092.1 24.0 — (22.0) 2,094.1 Total regulated revenues 3,018.2 959.6 292.5 4,270.3 24.0 — (22.0) 4,272.3 Other non-utility revenues — — 9.1 9.1 47.4 — (5.5) 51.0 Total revenues from contracts with customers 3,018.2 959.6 301.6 4,279.4 71.4 — (27.5) 4,323.3 Other operating revenues 21.0 19.3 3.8 44.1 199.7 0.2 (199.7) (1) 44.3 Total operating revenues $ 3,039.2 $ 978.9 $ 305.4 $ 4,323.5 $ 271.1 $ 0.2 $ (227.2) $ 4,367.6 (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) 2022 2021 2022 2021 Residential $ 449.7 $ 419.0 $ 912.8 $ 842.7 Small commercial and industrial 378.4 346.6 748.5 678.0 Large commercial and industrial 268.1 224.5 497.3 434.0 Other 7.2 6.9 15.0 14.7 Total retail revenues 1,103.4 997.0 2,173.6 1,969.4 Wholesale 40.8 38.6 83.2 78.3 Resale 60.7 37.4 117.5 100.1 Steam 4.7 4.2 16.8 19.0 Other utility revenues 11.5 6.0 17.5 11.4 Total electric utility operating revenues $ 1,221.1 $ 1,083.2 $ 2,408.6 $ 2,178.2
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, 2022 Residential $ 198.5 $ 268.6 $ 63.5 $ 530.6 Commercial and industrial 102.1 78.2 36.6 216.9 Total retail revenues 300.6 346.8 100.1 747.5 Transportation 18.0 54.5 6.0 78.5 Other utility revenues (1) 10.9 40.9 (10.3) 41.5 Total natural gas utility operating revenues $ 329.5 $ 442.2 $ 95.8 $ 867.5 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Three Months Ended June 30, 2021 Residential $ 188.6 $ 199.1 $ 37.9 $ 425.6 Commercial and industrial 90.2 51.5 17.3 159.0 Total retail revenues 278.8 250.6 55.2 584.6 Transportation 17.8 48.8 6.6 73.2 Other utility revenues (1) (83.9) (33.3) 5.1 (112.1) Total natural gas utility operating revenues $ 212.7 $ 266.1 $ 66.9 $ 545.7 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2022 Residential $ 701.0 $ 734.1 $ 224.8 $ 1,659.9 Commercial and industrial 374.6 236.5 123.4 734.5 Total retail revenues 1,075.6 970.6 348.2 2,394.4 Transportation 43.5 135.4 19.9 198.8 Other utility revenues (1) (42.8) 16.1 (34.1) (60.8) Total natural gas utility operating revenues $ 1,076.3 $ 1,122.1 $ 334.0 $ 2,532.4 (in millions) Wisconsin Illinois Other States Total Natural Gas Utility Operating Revenues Six Months Ended June 30, 2021 Residential $ 536.2 $ 533.0 $ 125.8 $ 1,195.0 Commercial and industrial 266.6 154.2 61.2 482.0 Total retail revenues 802.8 687.2 187.0 1,677.0 Transportation 42.2 123.0 17.6 182.8 Other utility revenues (1) (5.0) 149.4 87.9 232.3 Total natural gas utility operating revenues $ 840.0 $ 959.6 $ 292.5 $ 2,092.1 (1) Includes the revenues subject to the purchased gas recovery mechanisms of our utilities. The amounts for the three months ended June 30, 2022 reflect higher natural gas costs incurred than were anticipated in rates. During the six months ended June 30, 2022, we continued to recover natural gas costs we under-collected from our customers in 2021, related to the extreme weather. As these amounts were billed to customers, they were reflected in retail revenues with an offsetting decrease in other utility revenues. The negative amount during this period also relates to the over-collection of natural gas costs recorded in a regulatory liability due to these costs being lower than what was anticipated in rates. See Note 6, Regulatory Assets and Liabilities, for more information. The negative amount for the three months ended June 30, 2021 primarily relates to the approval by our utility commissions to recover from customers, over the second quarter of 2021, the higher natural gas costs that were incurred as a result of the extreme winter weather conditions in February 2021. As these amounts were billed to customers, they were reflected in retail revenues with an offsetting decrease in other utility revenues. For the six months ended June 30, 2021, in addition to costs related to the extreme weather event, we incurred higher natural gas costs as a result of an increase in the price of natural gas. See Note 23, Regulatory Environment, for more information.
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) 2022 2021 2022 2021 Wind generation revenues $ 21.3 $ 14.5 $ 57.5 $ 30.3 We Power revenues (1) 5.8 5.8 11.7 11.6 Appliance service revenues 4.5 4.4 9.1 9.1 Total other non-utility operating revenues $ 31.6 $ 24.7 $ 78.3 $ 51.0 (1) As part of the construction of the We Power EGUs, 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) 2022 2021 2022 2021 Late payment charges $ 16.3 $ 17.3 $ 29.9 $ 32.3 Alternative revenues (1) (11.3) 2.9 (17.3) 9.1 Other 1.7 1.7 2.6 2.9 Total other operating revenues $ 6.7 $ 21.9 $ 15.2 $ 44.3 (1) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges.

CREDIT LOSSES (Tables)

CREDIT LOSSES (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 and December 31, 2021, by reportable segment. (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated June 30, 2022 Accounts receivable and unbilled revenues $ 1,029.1 $ 485.2 $ 79.9 $ 1,594.2 $ 23.7 $ 5.6 $ 1,623.5 Allowance for credit losses 78.0 91.0 6.8 175.8 — — 175.8 Accounts receivable and unbilled revenues, net (1) $ 951.1 $ 394.2 $ 73.1 $ 1,418.4 $ 23.7 $ 5.6 $ 1,447.7 Total accounts receivable, net – past due greater than 90 days (1) $ 71.6 $ 66.8 $ 7.4 $ 145.8 $ — $ — $ 145.8 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.2 % 100.0 % — % 93.6 % — % — % 93.6 % (in millions) Wisconsin Illinois Other States Total Utility Non-Utility Energy Infrastructure Corporate WEC Energy Group Consolidated December 31, 2021 Accounts receivable and unbilled revenues $ 1,053.1 $ 523.1 $ 105.7 $ 1,681.9 $ 17.0 $ 5.1 $ 1,704.0 Allowance for credit losses 84.0 105.5 8.8 198.3 — — 198.3 Accounts receivable and unbilled revenues, net (1) $ 969.1 $ 417.6 $ 96.9 $ 1,483.6 $ 17.0 $ 5.1 $ 1,505.7 Total accounts receivable, net – past due greater than 90 days (1) $ 46.5 $ 36.6 $ 3.4 $ 86.5 $ — $ — $ 86.5 Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 97.6 % 100.0 % — % 94.8 % — % — % 94.8 % (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, 2022, $782.2 million, or 54.0%, 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 rollforward of the allowance for credit losses by reportable segment is included below: Three Months Ended June 30, 2022 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 85.7 $ 107.0 $ 7.9 $ 200.6 Provision for credit losses 11.8 7.1 (0.1) 18.8 Provision for credit losses deferred for future recovery or refund (5.4) (11.2) — (16.6) Write-offs charged against the allowance (22.1) (17.9) (1.2) (41.2) Recoveries of amounts previously written off 8.0 6.0 0.2 14.2 Balance at June 30, 2022 $ 78.0 $ 91.0 $ 6.8 $ 175.8 Six Months Ended June 30, 2022 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 84.0 $ 105.5 $ 8.8 $ 198.3 Provision for credit losses 23.6 18.4 0.1 42.1 Provision for credit losses deferred for future recovery or refund 3.4 0.9 — 4.3 Write-offs charged against the allowance (50.9) (45.2) (2.6) (98.7) Recoveries of amounts previously written off 17.9 11.4 0.5 29.8 Balance at June 30, 2022 $ 78.0 $ 91.0 $ 6.8 $ 175.8 On a consolidated basis, there was a $22.5 million decrease in the allowance for credit losses at June 30, 2022, compared to December 31, 2021. The decrease was driven by customer write-offs related to collection practices returning to pre-pandemic levels in 2021, including the restoration of our ability to disconnect customers. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. Partially offsetting the decrease in the allowance for credit losses, we believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses. Three Months Ended June 30, 2021 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 129.5 $ 122.0 $ 7.6 $ 259.1 Provision for credit losses 9.4 5.2 1.0 15.6 Provision for credit losses deferred for future recovery or refund (12.2) (18.9) — (31.1) Write-offs charged against the allowance (16.5) (4.0) (0.6) (21.1) Recoveries of amounts previously written off 4.2 4.7 0.3 9.2 Balance at June 30, 2021 $ 114.4 $ 109.0 $ 8.3 $ 231.7 Six Months Ended June 30, 2021 (in millions) Wisconsin Illinois Other States WEC Energy Group Consolidated Balance at the beginning of the period $ 102.1 $ 111.6 $ 6.4 $ 220.1 Provision for credit losses 23.1 12.3 2.3 37.7 Provision for credit losses deferred for future recovery or refund 10.1 (15.8) — (5.7) Write-offs charged against the allowance (35.0) (6.8) (1.1) (42.9) Recoveries of amounts previously written off 14.1 7.7 0.7 22.5 Balance at June 30, 2021 $ 114.4 $ 109.0 $ 8.3 $ 231.7 The increase in the allowance for credit losses at June 30, 2021, compared to December 31, 2020, was driven by higher past due accounts receivable balances related to our utility operations, primarily associated with our residential customers. This increase in accounts receivable balances in arrears related to the continued economic disruptions caused by the COVID-19 pandemic, including high unemployment rates. However, as seen in the quarterly rollforward above, the allowance for credit losses began to decrease in the second quarter of 2021, which we believe was related to the start of normal collection practices in our Wisconsin and Illinois service territories.

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2022
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	(in millions) June 30, 2022 December 31, 2021 Regulatory assets Pension and OPEB costs $ 762.6 $ 802.3 Plant retirement related items 705.9 722.3 Environmental remediation costs 621.6 630.9 Income tax related items 457.0 458.8 Asset retirement obligations 180.6 194.2 System support resource 126.7 129.5 Energy costs recoverable through rate adjustments 120.0 85.4 Securitization 96.1 100.7 MERC extraordinary natural gas costs 47.1 59.7 Derivatives (1) 38.5 33.1 Uncollectible expense 30.0 42.6 Energy efficiency programs 23.9 22.0 Other, net 68.9 85.6 Total regulatory assets $ 3,278.9 $ 3,367.1 Balance sheet presentation Amounts recoverable from customers $ 134.2 $ 102.3 Regulatory assets 3,144.7 3,264.8 Total regulatory assets $ 3,278.9 $ 3,367.1 (1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 14, Derivative Instruments, for more information on our derivative asset and liability balances.
Schedule of regulatory liabilities	(in millions) June 30, 2022 December 31, 2021 Regulatory liabilities Income tax related items $ 1,970.3 $ 1,998.5 Removal costs 1,252.2 1,248.0 Pension and OPEB benefits 388.3 397.3 Derivatives (1) 247.7 124.1 Energy costs refundable through rate adjustments (2) 78.3 13.7 Electric transmission costs (3) 42.9 84.2 Uncollectible expense 33.4 37.1 Earnings sharing mechanisms (3) 17.1 28.4 Other, net 53.8 29.0 Total regulatory liabilities $ 4,084.0 $ 3,960.3 Balance sheet presentation Other current liabilities $ 83.9 $ 14.3 Regulatory liabilities 4,000.1 3,946.0 Total regulatory liabilities $ 4,084.0 $ 3,960.3 (1) For most energy-related physical and financial contracts that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 14, Derivative Instruments, for more information on our derivative asset and liability balances. (2) The increase in these regulatory liabilities was primarily related to lower natural gas costs incurred during 2022, compared to what was anticipated in rates. (3) The decrease in these regulatory liability balances was primarily related to the PSCW's approval of certain accounting treatments that allowed our Wisconsin utilities to forego applying for a 2022 base rate increase, and instead maintain base rates consistent with 2021 levels. Among the accounting treatments approved was the amortization of certain regulatory liability balances in 2022, to offset a portion of the forecasted revenue deficiency. See Note 26, Regulatory Environment, in our 2021 Annual Report on Form 10-K for additional information on 2022 Wisconsin base rates.

COMMON EQUITY (Tables)

COMMON EQUITY (Tables)	6 Months Ended
	Jun. 30, 2022
Equity [Abstract]
Schedule of stock-based compensation awards granted	During the six months ended June 30, 2022, 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) 437,269 Restricted shares (2) 72,211 Performance units 171,492 (1) Stock options awarded had a weighted-average exercise price of $96.04 and a weighted-average grant date fair value of $14.71 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $96.04 per share.

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 December 31, 2021 Commercial paper Amount outstanding $ 1,626.8 $ 1,896.1 Weighted-average interest rate on amounts outstanding 1.90 % 0.26 % Operating expense loans Amount outstanding (1) $ 2.3 $ 0.9 (1) Coyote Ridge and Tatanka Ridge 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, 2022 WEC Energy Group September 2026 $ 1,500.0 WE September 2026 500.0 WPS (1) September 2026 400.0 WG September 2026 350.0 PGL September 2026 350.0 Total short-term credit capacity $ 3,100.0 Less: Letters of credit issued inside credit facilities $ 2.3 Commercial paper outstanding 1,626.8 Available capacity under existing agreements $ 1,470.9 (1) In April 2022, WPS received approval from the PSCW to extend the maturity of its facility to September 2026.

LEASES (Tables)

LEASES (Tables)	6 Months Ended
	Jun. 30, 2022
Leases [Abstract]
Schedule of minimum lease payments	Future minimum lease payments and the corresponding present value of our net minimum lease payments under the finance leases for Paris as of June 30, 2022, were as follows: (in millions) Six months ended December 31, 2022 $ 0.7 2023 2.2 2024 2.3 2025 2.3 2026 2.4 2027 2.4 Thereafter 176.0 Total minimum lease payments 188.3 Less: Interest (135.8) Present value of minimum lease payments 52.5 Less: Short-term lease liabilities — Long-term lease liabilities $ 52.5

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	6 Months Ended
	Jun. 30, 2022
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory consisted of: (in millions) June 30, 2022 December 31, 2021 Natural gas in storage $ 244.4 $ 326.0 Materials and supplies 242.7 225.3 Fossil fuel 85.1 84.5 Total $ 572.2 $ 635.8

INCOME TAXES (Tables)

INCOME TAXES (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 Three Months Ended June 30, 2021 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 73.7 21.0 % $ 69.1 21.0 % State income taxes net of federal tax benefit 22.2 6.3 % 20.8 6.3 % PTCs (22.9) (6.5) % (13.5) (4.1) % Federal excess deferred tax amortization (8.4) (2.4) % (7.9) (2.4) % Federal excess deferred tax amortization – Wisconsin unprotected (0.2) — % (16.3) (5.0) % Other (1.0) (0.3) % 1.9 0.6 % Total income tax expense $ 63.4 18.1 % $ 54.1 16.4 % Six Months Ended June 30, 2022 Six Months Ended June 30, 2021 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 219.2 21.0 % $ 191.9 21.0 % State income taxes net of federal tax benefit 65.8 6.3 % 57.7 6.3 % PTCs (67.7) (6.5) % (47.5) (5.2) % Federal excess deferred tax amortization (24.2) (2.3) % (22.5) (2.5) % Federal excess deferred tax amortization – Wisconsin unprotected (0.5) (0.1) % (46.6) (5.1) % Other (2.1) (0.2) % (4.0) (0.4) % Total income tax expense $ 190.5 18.2 % $ 129.0 14.1 %

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 108.0 $ 17.3 $ — $ 125.3 FTRs and TCRs — — 19.9 19.9 Coal contracts — 74.8 — 74.8 Total derivative assets $ 108.0 $ 92.1 $ 19.9 $ 220.0 Investments held in rabbi trust $ 49.7 $ — $ — $ 49.7 Derivative liabilities Natural gas contracts $ 25.8 $ 9.6 $ — $ 35.4 December 31, 2021 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 46.4 $ 18.2 $ — $ 64.6 FTRs — — 2.4 2.4 Coal contracts — 53.0 — 53.0 Total derivative assets $ 46.4 $ 71.2 $ 2.4 $ 120.0 Investments held in rabbi trust $ 79.6 $ — $ — $ 79.6 Derivative liabilities Natural gas contracts $ 8.4 $ 6.7 $ — $ 15.1
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) 2022 2021 2022 2021 Balance at the beginning of the period $ 1.0 $ 0.9 $ 2.4 $ 2.4 Purchases 21.9 6.0 21.9 6.1 Realized and unrealized gains included in earnings (1) 1.8 — 1.8 — Settlements (4.8) (1.5) (6.2) (3.1) Balance at the end of the period $ 19.9 $ 5.4 $ 19.9 $ 5.4 Gains included in earnings attributable to the change in unrealized gains of Level 3 derivatives held at the end of the reporting period (1) $ 0.9 $ — $ 0.9 $ —
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, 2022 December 31, 2021 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock of subsidiary $ 30.4 $ 26.4 $ 30.4 $ 30.3 Long-term debt, including current portion (1) 13,518.7 12,530.8 13,563.4 14,819.4 (1) The carrying amount of long-term debt excludes finance lease obligations of $179.1 million and $129.7 million at June 30, 2022 and December 31, 2021, respectively.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts (1) $ 116.4 $ 30.0 $ 60.6 $ 14.0 FTRs and TCRs 19.9 — 2.4 — Coal contracts 53.5 — 44.0 — Total current 189.8 30.0 107.0 14.0 Long-term Natural gas contracts (1) 8.9 5.4 4.0 1.1 Coal contracts 21.3 — 9.0 — Total long-term 30.2 5.4 13.0 1.1 Total $ 220.0 $ 35.4 $ 120.0 $ 15.1
Schedule of estimated notional sales volumes and realized gains (losses)	Our estimated notional sales volumes and realized gains and losses were as follows: Three Months Ended June 30, 2022 Three Months Ended June 30, 2021 (in millions) Volumes Gains Volumes Gains Natural gas contracts 41.1 Dth $ 108.9 47.9 Dth $ 4.8 FTRs and TCRs 7.0 MWh 4.3 7.4 MWh 10.2 Total $ 113.2 $ 15.0 Six Months Ended June 30, 2022 Six Months Ended June 30, 2021 (in millions) Volumes Gains Volumes Gains (Losses) Natural gas contracts 100.6 Dth $ 140.5 107.7 Dth $ (2.7) FTRs and TCRs 14.0 MWh 5.3 15.8 MWh 12.3 Total $ 145.8 $ 9.6
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, 2022 December 31, 2021 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 220.0 $ 35.4 $ 120.0 $ 15.1 Gross amount not offset on the balance sheet (110.1) (1) (27.8) (2) (15.2) (3) (9.2) (4) Net amount $ 109.9 $ 7.6 $ 104.8 $ 5.9 (1) Includes cash collateral received of $84.2 million. (2) Includes cash collateral posted of $1.9 million. (3) Includes cash collateral received of $6.4 million. (4) Includes cash collateral posted of $0.4 million.
Schedule of cash flow hedges reclassified to interest expense and total interest expense	The table below shows the amounts related to these cash flow hedges that were reclassified to interest expense, along with our total interest expense on the income statements: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense $ 0.1 $ (1.3) $ 0.2 $ (2.7) Total interest expense line item on the income statements 119.8 120.0 237.4 239.5

GUARANTEES (Tables)

GUARANTEES (Tables)	6 Months Ended
	Jun. 30, 2022
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees: Total Amounts Committed at June 30, 2022 Expiration (in millions) Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 83.8 $ 10.5 $ 0.2 $ 73.1 Surety bonds (2) 12.9 12.9 — — Other guarantees (3) 9.5 — — 9.5 Total guarantees $ 106.2 $ 23.4 $ 0.2 $ 82.6 (1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (2) Primarily for 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, 2022
Retirement Benefits [Abstract]
Schedule of net benefit cost (credit)	The following tables show the components of net periodic benefit cost (credit) for our benefit plans. Pension Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Service cost $ 14.2 $ 13.6 $ 26.6 $ 27.5 Interest cost 22.4 21.7 45.2 43.6 Expected return on plan assets (52.5) (50.1) (105.2) (100.7) Loss on plan settlement 2.2 1.9 2.2 2.0 Amortization of prior service cost 0.4 0.4 0.8 0.8 Amortization of net actuarial loss 19.1 28.2 38.2 55.6 Net periodic benefit cost $ 5.8 $ 15.7 $ 7.8 $ 28.8 OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2022 2021 2022 2021 Service cost $ 3.3 $ 3.6 $ 7.1 $ 7.8 Interest cost 3.8 3.6 7.7 7.2 Expected return on plan assets (17.3) (16.6) (34.5) (33.0) Amortization of prior service credit (3.9) (3.9) (7.9) (7.9) Amortization of net actuarial gain (6.3) (6.5) (12.3) (12.2) Net periodic benefit credit $ (20.4) $ (19.8) $ (39.9) $ (38.1)

GOODWILL AND INTANGIBLES (Table

GOODWILL AND INTANGIBLES (Tables)	6 Months Ended
	Jun. 30, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill balance by segment	The table below shows our goodwill balances by segment at June 30, 2022. We had no changes to the carrying amount of goodwill during the six months ended June 30, 2022. (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, 2022.
Schedule of intangible liabilities obtained through acquisitions by WECI	The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. June 30, 2022 December 31, 2021 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount PPAs (1) $ 87.9 $ (10.4) $ 77.5 $ 87.9 $ (6.5) $ 81.4 Proxy revenue swap (2) 7.2 (2.4) 4.8 7.2 (2.1) 5.1 Interconnection agreements (3) 4.7 (0.6) 4.1 4.7 (0.5) 4.2 Total intangible liabilities $ 99.8 $ (13.4) $ 86.4 $ 99.8 $ (9.1) $ 90.7 (1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, and Jayhawk expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is 10 years. (2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap is seven years. (3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 18 years.
Schedule of amortization over the next five years	Amortization for the next five years, including amounts recorded through June 30, 2022, is estimated to be: For the Years Ending December 31 (in millions) 2022 2023 2024 2025 2026 Amortization to be recorded in operating revenues $ 8.5 $ 8.4 $ 8.4 $ 8.4 $ 8.4 Amortization to be recorded in other operation and maintenance 0.2 0.2 0.2 0.2 0.2

INVESTMENT IN TRANSMISSION AF_2

INVESTMENT IN TRANSMISSION AFFILIATES (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,795.0 $ 23.2 $ 1,818.2 Add: Earnings from equity method investment 42.6 0.4 43.0 Add: Capital contributions 9.2 — 9.2 Less: Distributions 33.2 — 33.2 Balance at end of period $ 1,813.6 $ 23.6 $ 1,837.2 Three Months Ended June 30, 2021 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,741.9 $ 31.7 $ 1,773.6 Add: Earnings from equity method investment 40.7 0.6 41.3 Less: Distributions 32.8 — 32.8 Less: Other 0.1 — 0.1 Balance at end of period $ 1,749.7 $ 32.3 $ 1,782.0 Six Months Ended June 30, 2022 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,766.9 $ 22.5 $ 1,789.4 Add: Earnings from equity method investment 83.6 1.1 84.7 Add: Capital contributions 30.3 — 30.3 Less: Distributions 67.2 — 67.2 Balance at end of period $ 1,813.6 $ 23.6 $ 1,837.2 Six Months Ended June 30, 2021 (in millions) ATC ATC Holdco Total Balance at beginning of period $ 1,733.5 $ 30.8 $ 1,764.3 Add: Earnings from equity method investment 82.4 1.5 83.9 Less: Distributions 66.2 — 66.2 Balance at end of period $ 1,749.7 $ 32.3 $ 1,782.0
ATC
Investment in transmission affiliates
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) 2022 2021 2022 2021 Charges to ATC for services and construction $ 4.7 $ 5.7 $ 10.9 $ 11.7 Charges from ATC for network transmission services 90.8 89.1 181.9 181.7
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, 2022 December 31, 2021 Accounts receivable for services provided to ATC $ 1.4 $ 2.0 Accounts payable for services received from ATC 30.6 30.2 Amounts due from ATC for transmission infrastructure upgrades (1) 14.9 13.0 (1) The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of Paris, as well as WE's continued construction of Badger Hollow II.
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) 2022 2021 2022 2021 Income statement data Operating revenues $ 191.6 $ 185.9 $ 382.6 $ 374.6 Operating expenses 95.2 92.4 190.7 187.5 Other expense, net 28.8 28.1 56.8 56.6 Net income $ 67.6 $ 65.4 $ 135.1 $ 130.5
Schedule of summarized balance sheet data for ATC	(in millions) June 30, 2022 December 31, 2021 Balance sheet data Current assets $ 106.0 $ 89.8 Noncurrent assets 5,801.8 5,628.1 Total assets $ 5,907.8 $ 5,717.9 Current liabilities $ 482.7 $ 436.9 Long-term debt 2,562.4 2,513.0 Other noncurrent liabilities 438.5 422.0 Members' equity 2,424.2 2,346.0 Total liabilities and members' equity $ 5,907.8 $ 5,717.9

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2022
Segment Reporting [Abstract]
Financial information of reportable segments	The following tables show summarized financial information related to our reportable segments for the three and six months ended June 30, 2022 and 2021: 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, 2022 External revenues $ 1,557.4 $ 442.4 $ 99.9 $ 2,099.7 $ — $ 28.1 $ 0.1 $ — $ 2,127.9 Intersegment revenues — — — — — 115.5 — (115.5) — Other operation and maintenance 337.9 79.1 22.9 439.9 — 13.9 (0.9) (3.9) 449.0 Depreciation and amortization 187.7 57.4 10.2 255.3 — 34.3 6.8 (16.8) 279.6 Equity in earnings of transmission affiliates — — — — 43.0 — — — 43.0 Interest expense 135.6 18.0 3.2 156.8 4.8 17.4 24.6 (83.8) 119.8 Income tax expense (benefit) 49.3 21.2 0.9 71.4 9.3 (7.3) (10.0) — 63.4 Net income (loss) 148.7 56.4 2.7 207.8 29.0 80.3 (29.3) — 287.8 Net income (loss) attributed to common shareholders 148.4 56.4 2.7 207.5 29.0 80.3 (29.3) — 287.5 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, 2021 External revenues $ 1,307.5 $ 275.5 $ 72.1 $ 1,655.1 $ — $ 21.0 $ 0.1 $ — $ 1,676.2 Intersegment revenues — — — — — 112.5 — (112.5) — Other operation and maintenance 346.1 90.8 21.2 458.1 — 12.4 (2.8) (3.9) 463.8 Depreciation and amortization 179.8 54.0 9.4 243.2 — 31.3 6.4 (14.7) 266.2 Equity in earnings of transmission affiliates — — — — 41.3 — — — 41.3 Interest expense 139.8 16.6 1.5 157.9 4.8 17.9 24.6 (85.2) 120.0 Income tax expense 23.1 16.0 0.8 39.9 9.4 0.7 4.1 — 54.1 Net income (loss) 146.8 43.6 2.5 192.9 27.0 68.2 (12.4) — 275.7 Net income (loss) attributed to common shareholders 146.5 43.6 2.5 192.6 27.0 68.8 (12.4) — 276.0 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, 2022 External revenues $ 3,499.7 $ 1,124.5 $ 340.8 $ 4,965.0 $ — $ 70.7 $ 0.3 $ — $ 5,036.0 Intersegment revenues — — — — — 232.4 — (232.4) — Other operation and maintenance 650.5 192.7 47.5 890.7 — 24.8 (6.6) (5.5) 903.4 Depreciation and amortization 374.8 114.2 20.2 509.2 — 68.3 13.3 (33.1) 557.7 Equity in earnings of transmission affiliates — — — — 84.7 — — — 84.7 Interest expense 271.9 35.7 6.5 314.1 9.7 34.6 47.2 (168.2) 237.4 Income tax expense (benefit) 144.7 63.3 11.3 219.3 18.2 (12.2) (34.8) — 190.5 Net income (loss) 437.1 169.8 34.2 641.1 56.8 173.6 (15.7) — 855.8 Net income (loss) attributed to common shareholders 436.5 169.8 34.2 640.5 56.8 171.8 (15.7) — 853.4 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, 2021 External revenues $ 3,039.2 $ 978.9 $ 305.4 $ 4,323.5 $ — $ 43.9 $ 0.2 $ — $ 4,367.6 Intersegment revenues — — — — — 227.2 — (227.2) — Other operation and maintenance 688.0 200.1 44.4 932.5 — 21.3 (4.6) (5.5) 943.7 Depreciation and amortization 356.0 106.7 18.6 481.3 — 62.3 13.0 (29.0) 527.6 Equity in earnings of transmission affiliates — — — — 83.9 — — — 83.9 Interest expense 279.9 33.1 3.0 316.0 9.7 35.9 48.8 (170.9) 239.5 Income tax expense (benefit) 71.2 57.4 9.2 137.8 19.2 0.8 (28.8) — 129.0 Net income 403.4 155.7 27.2 586.3 55.0 139.5 5.2 — 786.0 Net income attributed to common shareholders 402.8 155.7 27.2 585.7 55.0 140.2 5.2 — 786.1

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	6 Months Ended
	Jun. 30, 2022
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 sheet. (in millions) June 30, 2022 December 31, 2021 Assets Other current assets (restricted cash) $ 3.1 $ 2.4 Regulatory assets 96.1 100.7 Other long-term assets (restricted cash) 0.6 0.6 Liabilities Current portion of long-term debt 8.8 8.8 Other current liabilities (accrued interest) 0.1 0.1 Long-term debt 98.4 102.7

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	6 Months Ended
	Jun. 30, 2022
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, 2022 December 31, 2021 Regulatory assets $ 621.6 $ 630.9 Reserves for future environmental remediation 504.3 532.6

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2022
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Six Months Ended June 30 (in millions) 2022 2021 Cash paid for interest, net of amount capitalized $ 234.9 $ 239.9 Cash paid for income taxes, net 37.3 28.2 Significant non-cash investing and financing transactions: Accounts payable related to construction costs 210.2 127.9 Increase in receivable related to insurance proceeds — 39.6 Liabilities accrued for software licensing agreement 7.4 —
Reconciliation of cash and 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, 2022 December 31, 2021 Cash and cash equivalents $ 30.3 $ 16.3 Restricted cash included in other current assets 21.9 19.6 Restricted cash included in other long term assets 52.7 51.6 Cash, cash equivalents, and restricted cash $ 104.9 $ 87.5

REGULATORY ENVIRONMENT (Tables)

REGULATORY ENVIRONMENT (Tables)	6 Months Ended
	Jun. 30, 2022
Regulated Operations [Abstract]
Schedule of regulatory proposals	The updated rate request proposals include aggregate increases of approximately $30 million for WE, $6 million for WPS, and $2 million for WG from the original proposals and are reflected in the following table: WE WPS WG Proposed 2023 rate increase Electric $ 285.6 million / 9.2% $ 79.4 million / 6.6% N/A Gas $ 55.4 million / 11.7% $ 30.9 million / 8.4% $ 61.9 million / 8.6% Steam $ 3.6 million / 16.5% N/A N/A Proposed ROE (1) 10.0% 10.0% 10.2% Proposed common equity component average on a financial basis (1) 53.0% 53.0% 53.0%

GENERAL INFORMATION - GENERAL (

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Jun. 30, 2022 customer
Electric
Product information [Line Items]
Number Of Customers	1.6
Natural gas
Product information [Line Items]
Number Of Customers	3

GENERAL INFORMATION - INVESTMEN

GENERAL INFORMATION - INVESTMENTS (Details)	Jun. 30, 2022
ATC
Schedule of Investments [Line Items]
Equity method investment, ownership interest (as a percent)	60%

ACQUISITIONS - WHITEWATER (Deta

ACQUISITIONS - WHITEWATER (Details) - Whitewater cogeneration facility - WE and WPS [Member] $ in Millions	1 Months Ended
	Nov. 30, 2021 USD ($) MW
Asset Acquisition [Line Items]
Capacity of generation unit | MW	236.5
Acquisition purchase price, expected | $	$ 72.7

ACQUISITIONS - SAPPHIRE SKY (De

ACQUISITIONS - SAPPHIRE SKY (Details) - Sapphire Sky - WECI $ in Millions	1 Months Ended
	Jun. 30, 2021 USD ($) MW
Asset Acquisition [Line Items]
Ownership interest of wind generating facility acquired	90%
Capacity of generation unit | MW	250
Acquisition purchase price, expected | $	$ 412
Duration of offtake agreement for the sale of energy produced	12 years

ACQUISITIONS - JAYHAWK (Details

ACQUISITIONS - JAYHAWK (Details) - Jayhawk - WECI $ in Millions	1 Months Ended
	Dec. 31, 2021	Feb. 28, 2021 USD ($) MW	Jun. 30, 2022 USD ($)
Asset Acquisition [Line Items]
Ownership interest of wind generating facility acquired		90%
Capacity of generation unit | MW		190
Acquisition purchase price		$ 119.9
Additional capital expenditures			$ 153.6
Current project investment			$ 273.5
Duration of offtake agreement for the sale of energy produced	10 years
Percentage of tax benefits entitled to	99%
Duration of receiving tax benefits	10 years

ACQUISITIONS - THUNDERHEAD (Det

ACQUISITIONS - THUNDERHEAD (Details) - Thunderhead - WECI $ in Millions	1 Months Ended		6 Months Ended
	Feb. 29, 2020 USD ($)	Aug. 31, 2019 USD ($) MW	Jun. 30, 2022
Asset Acquisition [Line Items]
Ownership interest of wind generating facility acquired		80%
Capacity of generation unit | MW		300
Acquisition purchase price, expected | $	$ 43	$ 338
Additional ownership interest acquired	10%
Duration of offtake agreement for the sale of energy produced			12 years

DISPOSITION (Details)

DISPOSITION (Details) $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) a	Jun. 30, 2021 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the sale of assets	$ 65	$ 20.8
PGL
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
NumberofAcresSold | a	11
Proceeds from the sale of assets	$ 55.1
PGL | Other operation and maintenance
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pre-tax gain on sale	$ 54.5

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Operating Revenues
Total operating revenues	$ 2,127.9	$ 1,676.2	$ 5,036	$ 4,367.6
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,121.2	1,654.3	5,020.8	4,323.3
Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	6.7	21.9	15.2	44.3
Total regulated revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,089.6	1,629.6	4,942.5	4,272.3
Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,221.1	1,083.2	2,408.6	2,178.2
Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	868.5	546.4	2,533.9	2,094.1
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	31.6	24.7	78.3	51
Reconciling Eliminations
Disaggregation of Operating Revenues
Total operating revenues	(115.5)	(112.5)	(232.4)	(227.2)
Reconciling Eliminations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(15)	(12.6)	(31.4)	(27.5)
Reconciling Eliminations | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	(100.5)	(99.9)	(201)	(199.7)
Reconciling Eliminations | Total regulated revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(11)	(8.7)	(25.8)	(22)
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	(11)	(8.7)	(25.8)	(22)
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(4)	(3.9)	(5.6)	(5.5)
Total Utility Operations
Disaggregation of Operating Revenues
Total operating revenues	2,099.7	1,655.1	4,965	4,323.5
Total Utility Operations | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	6.6	21.8	14.9	44.1
Total Utility Operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,093.1	1,633.3	4,950.1	4,279.4
Total Utility Operations | Total regulated revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,088.6	1,628.9	4,941	4,270.3
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,221.1	1,083.2	2,408.6	2,178.2
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	867.5	545.7	2,532.4	2,092.1
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.5	4.4	9.1	9.1
Wisconsin
Disaggregation of Operating Revenues
Total operating revenues	1,557.4	1,307.5	3,499.7	3,039.2
Wisconsin | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	6.8	11.6	14.8	21
Wisconsin | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,550.6	1,295.9	3,484.9	3,018.2
Wisconsin | Total regulated revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,550.6	1,295.9	3,484.9	3,018.2
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,221.1	1,083.2	2,408.6	2,178.2
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	329.5	212.7	1,076.3	840
Wisconsin | 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
Disaggregation of Operating Revenues
Total operating revenues	442.4	275.5	1,124.5	978.9
Illinois | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	0.2	9.4	2.4	19.3
Illinois | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	442.2	266.1	1,122.1	959.6
Illinois | Total regulated revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	442.2	266.1	1,122.1	959.6
Illinois | Electric | 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	442.2	266.1	1,122.1	959.6
Illinois | 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
Disaggregation of Operating Revenues
Total operating revenues	99.9	72.1	340.8	305.4
Other States | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	(0.4)	0.8	(2.3)	3.8
Other States | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	100.3	71.3	343.1	301.6
Other States | Total regulated revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	95.8	66.9	334	292.5
Other States | Electric | 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	95.8	66.9	334	292.5
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.5	4.4	9.1	9.1
Non-Utility Energy Infrastructure
Disaggregation of Operating Revenues
Total operating revenues	143.6	133.5	303.1	271.1
Non-Utility Energy Infrastructure | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	43.1	33.6	102.1	71.4
Non-Utility Energy Infrastructure | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	100.5	99.9	201	199.7
Non-Utility Energy Infrastructure | Total regulated revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	12	9.4	27.3	24
Non-Utility Energy Infrastructure | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0		0
Non-Utility Energy Infrastructure | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	12	9.4	27.3	24
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	31.1	24.2	74.8	47.4
Corporate and Other
Disaggregation of Operating Revenues
Total operating revenues	0.1	0.1	0.3	0.2
Corporate and Other | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	0.1	0.1	0.3	0.2
Corporate and Other | Total regulated revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0	0	0	0
Corporate and Other | 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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,121.2	$ 1,654.3	$ 5,020.8	$ 4,323.3
Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,221.1	1,083.2	2,408.6	2,178.2
Wisconsin | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,550.6	1,295.9	3,484.9	3,018.2
Wisconsin | Electric | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,221.1	1,083.2	2,408.6	2,178.2
Wisconsin | Electric | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,103.4	997	2,173.6	1,969.4
Wisconsin | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	449.7	419	912.8	842.7
Wisconsin | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	378.4	346.6	748.5	678
Wisconsin | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	268.1	224.5	497.3	434
Wisconsin | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.2	6.9	15	14.7
Wisconsin | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	40.8	38.6	83.2	78.3
Wisconsin | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	60.7	37.4	117.5	100.1
Wisconsin | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.7	4.2	16.8	19
Wisconsin | Electric | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 11.5	$ 6	$ 17.5	$ 11.4

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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,121.2	$ 1,654.3	$ 5,020.8	$ 4,323.3
Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	868.5	546.4	2,533.9	2,094.1
Total Utility Operations | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	2,093.1	1,633.3	4,950.1	4,279.4
Total Utility Operations | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	867.5	545.7	2,532.4	2,092.1
Total Utility Operations | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	747.5	584.6	2,394.4	1,677
Total Utility Operations | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	530.6	425.6	1,659.9	1,195
Total Utility Operations | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	216.9	159	734.5	482
Total Utility Operations | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	78.5	73.2	198.8	182.8
Total Utility Operations | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	41.5	(112.1)	(60.8)	232.3
Wisconsin | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,550.6	1,295.9	3,484.9	3,018.2
Wisconsin | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	329.5	212.7	1,076.3	840
Wisconsin | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	300.6	278.8	1,075.6	802.8
Wisconsin | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	198.5	188.6	701	536.2
Wisconsin | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	102.1	90.2	374.6	266.6
Wisconsin | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	18	17.8	43.5	42.2
Wisconsin | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	10.9	(83.9)	(42.8)	(5)
Illinois | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	442.2	266.1	1,122.1	959.6
Illinois | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	442.2	266.1	1,122.1	959.6
Illinois | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	346.8	250.6	970.6	687.2
Illinois | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	268.6	199.1	734.1	533
Illinois | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	78.2	51.5	236.5	154.2
Illinois | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	54.5	48.8	135.4	123
Illinois | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	40.9	(33.3)	16.1	149.4
Other States | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	100.3	71.3	343.1	301.6
Other States | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	95.8	66.9	334	292.5
Other States | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	100.1	55.2	348.2	187
Other States | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	63.5	37.9	224.8	125.8
Other States | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	36.6	17.3	123.4	61.2
Other States | Natural gas | Transferred over time | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	6	6.6	19.9	17.6
Other States | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ (10.3)	$ 5.1	$ (34.1)	$ 87.9

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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2,121.2	$ 1,654.3	$ 5,020.8	$ 4,323.3
Other non-utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	31.6	24.7	78.3	51
Other non-utility revenues | We Power revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	5.8	5.8	11.7	11.6
Transferred over time | Other non-utility revenues | Wind generation revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	21.3	14.5	57.5	30.3
Transferred over time | Other non-utility revenues | Appliance service repairs
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 4.5	$ 4.4	$ 9.1	$ 9.1

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Other operating revenues - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Operating Revenues
Other operating revenues	$ 6.7	$ 21.9	$ 15.2	$ 44.3
Late payment charges
Disaggregation of Operating Revenues
Other operating revenues	16.3	17.3	29.9	32.3
Alternative revenues
Disaggregation of Operating Revenues
Other operating revenues	(11.3)	2.9	(17.3)	9.1
Other
Disaggregation of Operating Revenues
Other operating revenues	$ 1.7	$ 1.7	$ 2.6	$ 2.9

CREDIT LOSSES - GROSS RECEIVABL

CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,623.5		$ 1,704
Allowance for credit losses	175.8	$ 200.6	198.3	$ 231.7	$ 259.1	$ 220.1
Accounts receivable and unbilled revenues, net	1,447.7		1,505.7
Total accounts receivable, net - past due greater than 90 days	$ 145.8		$ 86.5
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	93.60%		94.80%
Amount of net accounts receivable with regulatory protections	$ 782.2
Percent of net accounts receivable with regulatory protections	54%
Utility Operations
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,594.2		$ 1,681.9
Allowance for credit losses	175.8		198.3
Accounts receivable and unbilled revenues, net	1,418.4		1,483.6
Total accounts receivable, net - past due greater than 90 days	$ 145.8		$ 86.5
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	93.60%		94.80%
Wisconsin | Utility Operations
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 1,029.1		$ 1,053.1
Allowance for credit losses	78	85.7	84	114.4	129.5	102.1
Accounts receivable and unbilled revenues, net	951.1		969.1
Total accounts receivable, net - past due greater than 90 days	$ 71.6		$ 46.5
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	97.20%		97.60%
Illinois | Utility Operations
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 485.2		$ 523.1
Allowance for credit losses	91	107	105.5	109	122	111.6
Accounts receivable and unbilled revenues, net	394.2		417.6
Total accounts receivable, net - past due greater than 90 days	$ 66.8		$ 36.6
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	100%		100%
Other States | Utility Operations
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 79.9		$ 105.7
Allowance for credit losses	6.8	$ 7.9	8.8	$ 8.3	$ 7.6	$ 6.4
Accounts receivable and unbilled revenues, net	73.1		96.9
Total accounts receivable, net - past due greater than 90 days	$ 7.4		$ 3.4
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	$ 23.7		$ 17
Allowance for credit losses	0		0
Accounts receivable and unbilled revenues, net	23.7		17
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	$ 5.6		$ 5.1
Allowance for credit losses	0		0
Accounts receivable and unbilled revenues, net	5.6		5.1
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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	$ 200.6	$ 259.1	$ 198.3	$ 220.1
Provision for credit losses	18.8	15.6	42.1	37.7
Provision for credit losses deferred for future recovery or refund	(16.6)	(31.1)	4.3	(5.7)
Write-offs charged against the allowance	(41.2)	(21.1)	(98.7)	(42.9)
Recovery of amounts previously written off	14.2	9.2	29.8	22.5
Balance at end of period	175.8	231.7	175.8	231.7
Change in allowance for credit losses			22.5
Utility Operations
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period			198.3
Balance at end of period	175.8		175.8
Wisconsin | Utility Operations
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	85.7	129.5	84	102.1
Provision for credit losses	11.8	9.4	23.6	23.1
Write-offs charged against the allowance	(22.1)	(16.5)	(50.9)	(35)
Recovery of amounts previously written off	8	4.2	17.9	14.1
Balance at end of period	78	114.4	78	114.4
Wisconsin | Utility Operations | Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	(5.4)	(12.2)	3.4	10.1
Illinois | Utility Operations
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	107	122	105.5	111.6
Provision for credit losses	7.1	5.2	18.4	12.3
Write-offs charged against the allowance	(17.9)	(4)	(45.2)	(6.8)
Recovery of amounts previously written off	6	4.7	11.4	7.7
Balance at end of period	91	109	91	109
Illinois | Utility Operations | Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	(11.2)	(18.9)	0.9	(15.8)
Other States | Utility Operations
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	7.9	7.6	8.8	6.4
Provision for credit losses	(0.1)	1	0.1	2.3
Write-offs charged against the allowance	(1.2)	(0.6)	(2.6)	(1.1)
Recovery of amounts previously written off	0.2	0.3	0.5	0.7
Balance at end of period	6.8	8.3	6.8	8.3
Other States | Utility Operations | 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, 2022	Dec. 31, 2021
Regulatory assets
Amounts recoverable from customers	$ 134.2	$ 102.3
Regulatory assets	3,144.7	3,264.8
Total regulatory assets	3,278.9	3,367.1
Pension and OPEB costs
Regulatory assets
Total regulatory assets	762.6	802.3
Plant retirement related items
Regulatory assets
Total regulatory assets	705.9	722.3
Environmental remediation costs
Regulatory assets
Total regulatory assets	621.6	630.9
Income tax related items
Regulatory assets
Total regulatory assets	457	458.8
Asset retirement obligations
Regulatory assets
Total regulatory assets	180.6	194.2
System support resource
Regulatory assets
Total regulatory assets	126.7	129.5
Energy costs recoverable through rate adjustments
Regulatory assets
Total regulatory assets	120	85.4
Securitization
Regulatory assets
Total regulatory assets	96.1	100.7
MERC extraordinary natural gas costs
Regulatory assets
Total regulatory assets	47.1	59.7
Derivatives
Regulatory assets
Total regulatory assets	38.5	33.1
Uncollectible expense
Regulatory assets
Total regulatory assets	30	42.6
Energy efficiency programs
Regulatory assets
Total regulatory assets	23.9	22
Other, net
Regulatory assets
Total regulatory assets	$ 68.9	$ 85.6

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Regulatory liabilities
Other current liabilities	$ 83.9	$ 14.3
Regulatory liabilities	4,000.1	3,946
Total regulatory liabilities	4,084	3,960.3
Income tax related items
Regulatory liabilities
Total regulatory liabilities	1,970.3	1,998.5
Removal costs
Regulatory liabilities
Total regulatory liabilities	1,252.2	1,248
Pension and OPEB benefits
Regulatory liabilities
Total regulatory liabilities	388.3	397.3
Derivatives
Regulatory liabilities
Total regulatory liabilities	247.7	124.1
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	78.3	13.7
Electric transmission costs
Regulatory liabilities
Total regulatory liabilities	42.9	84.2
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	33.4	37.1
Earnings sharing mechanisms
Regulatory liabilities
Total regulatory liabilities	17.1	28.4
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 53.8	$ 29

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT - PLANT TO BE RETIRED (Details) - WPS $ in Millions	Jun. 30, 2022 USD ($)
Columbia Energy Center Unit 1
Property, plant, and equipment
Net book value of plant to be retired	$ 86.6
Columbia Energy Center Unit 2
Property, plant, and equipment
Net book value of plant to be retired	$ 185.6

PROPERTY, PLANT, AND EQUIPMEN_2

PROPERTY, PLANT, AND EQUIPMENT - PUBLIC SERVICE BUILDING AND STEAM TUNNEL ASSETS (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		12 Months Ended
	Mar. 31, 2022	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2020
Property, plant, and equipment
Insurance proceeds received for property damage		$ 41.3	$ 0
WE | Public Service Building and Steam Tunnel Assets
Property, plant, and equipment
Costs incurred for repairs and restorations		95.3
Insurance proceeds received for property damage	$ 41			$ 20
Costs included in other operation and maintenance				$ 12.5
Repairs and restorations to be recovered through rates		$ 21.8

COMMON EQUITY - STOCK-BASED COM

COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details)	6 Months Ended
	Jun. 30, 2022 $ / shares shares
Stock options
Stock-based compensation
Stock options granted | shares	437,269
Stock options granted, weighted average exercise price | $ / shares	$ 96.04
Stock options granted, weighted-average grant date fair value | $ / shares	$ 14.71
Restricted shares
Stock-based compensation
Awards granted | shares	72,211
Restricted shares granted, weighted-average grant date fair value | $ / shares	$ 96.04
Performance units
Stock-based compensation
Awards granted | shares	171,492

COMMON EQUITY - COMMON STOCK DI

COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares	3 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021
Dividends payable
Common stock dividend declared (in dollars per share)		$ 0.7275	$ 0.7275	$ 0.6775	$ 0.6775
Subsequent event
Dividends payable
Common stock dividend declared (in dollars per share)	$ 0.7275

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, 2022	Dec. 31, 2021
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 1,626.8	$ 1,896.1
Weighted average interest rate on amounts outstanding	1.90%	0.26%
Average amount of commercial paper outstanding during the period	$ 1,421.5
Weighted-average interest rate on amounts outstanding during the period	0.68%
Operating expense loans
Short-term borrowings
Operating expense loan outstanding	$ 2.3	$ 0.9

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Revolving credit facilities
Short-term credit capacity	$ 3,100
Available capacity under existing credit facility	1,470.9
Letter of credit
Revolving credit facilities
Letters of credit issued inside credit facilities	2.3
Commercial paper
Revolving credit facilities
Commercial paper outstanding	1,626.8	$ 1,896.1
WE | Credit facility maturing in September 2026
Revolving credit facilities
Short-term credit capacity	500
WPS | Credit facility maturing in September 2026
Revolving credit facilities
Short-term credit capacity	400
WG | Credit facility maturing in September 2026
Revolving credit facilities
Short-term credit capacity	350
PGL | Credit facility maturing in September 2026
Revolving credit facilities
Short-term credit capacity	350
WEC Energy Group | Credit facility maturing in September 2026
Revolving credit facilities
Short-term credit capacity	$ 1,500

LEASES - PARIS SOLAR (Details)

LEASES - PARIS SOLAR (Details) - Paris Solar $ in Millions	Jun. 30, 2022 USD ($) MW
Lessee, Lease, Description [Line Items]
Lease initial term	25 years
Renewal term	25 years
Finance lease obligations	$ 52.5
Finance lease obligation at end of life of solar land contract	0
ROU asset under finance lease	$ 52.5
Weighted average discount rate - finance leases	5.28%
Paris Solar-Battery Park | WE
Lessee, Lease, Description [Line Items]
Joint plant ownership percentage	75%
Paris Solar-Battery Park | WPS
Lessee, Lease, Description [Line Items]
Joint plant ownership percentage	15%
Paris Solar-Battery Park | WE and WPS
Lessee, Lease, Description [Line Items]
Jointly owned utility plant, proportionate ownership share of solar capacity | MW	180
Jointly owned utility plant, proportionate ownership share of battery storage | MW	99

LEASES - FUTURE MINIMUM LEASE P

LEASES - FUTURE MINIMUM LEASE PAYMENTS (Details) - Paris Solar $ in Millions	Jun. 30, 2022 USD ($)
Finance leases
Six months ended December 31, 2022	$ 0.7
2023	2.2
2024	2.3
2025	2.3
2026	2.4
2027	2.4
Thereafter	176
Total minimum lease payments	188.3
Less: interest	(135.8)
Present value of minimum lease payments	52.5
Less: short-term lease liabilities	0
Long-term lease liabilities	$ 52.5

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Energy Related Inventory
Natural gas in storage	$ 244.4	$ 326
Materials and supplies	242.7	225.3
Fossil fuel	85.1	84.5
Total	572.2	$ 635.8
LIFO Method Related Items
LIFO liquidation balance	$ 107.6

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount	$ 73.7	$ 69.1	$ 219.2	$ 191.9
State income taxes net of federal tax benefit, amount	22.2	20.8	65.8	57.7
PTCs, amount	(22.9)	(13.5)	(67.7)	(47.5)
Federal excess deferred tax amortization, amount	(8.4)	(7.9)	(24.2)	(22.5)
Federal excess deferred tax amortization - Wisconsin unprotected, amount	(0.2)	(16.3)	(0.5)	(46.6)
Other, amount	(1)	1.9	(2.1)	(4)
Total income tax expense, amount	$ 63.4	$ 54.1	$ 190.5	$ 129
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage	21%	21%	21%	21%
State income taxes net of federal tax benefit, percentage	6.30%	6.30%	6.30%	6.30%
PTCs, percentage	(6.50%)	(4.10%)	(6.50%)	(5.20%)
Federal excess deferred tax amortization, percentage	(2.40%)	(2.40%)	(2.30%)	(2.50%)
Federal excess deferred tax amortization - Wisconsin unprotected, percentage	0%	(5.00%)	(0.10%)	(5.10%)
Other, percentage	(0.30%)	0.60%	(0.20%)	(0.40%)
Total income tax expense, percent	18.10%	16.40%	18.20%	14.10%

INCOME TAXES - WI 2020 and 2021

INCOME TAXES - WI 2020 and 2021 RATES (Details) - Tax Cuts and Jobs Act of 2017 - Public Service Commission of Wisconsin (PSCW) - 2020 and 2021 rates	1 Months Ended
	Dec. 31, 2019
Electric rates
Income Taxes [Line Items]
Amortization period	2 years
Natural gas rates
Income Taxes [Line Items]
Amortization period	4 years

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Assets
Derivative assets	$ 220	$ 120
Liabilities
Derivative liabilities	35.4	15.1
Fair value measurements on a recurring basis
Assets
Derivative assets	220	120
Investments held in rabbi trust	49.7	79.6
Fair value measurements on a recurring basis | Level 1
Assets
Derivative assets	108	46.4
Investments held in rabbi trust	49.7	79.6
Fair value measurements on a recurring basis | Level 2
Assets
Derivative assets	92.1	71.2
Investments held in rabbi trust	0	0
Fair value measurements on a recurring basis | Level 3
Assets
Derivative assets	19.9	2.4
Investments held in rabbi trust	0	0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative assets	125.3	64.6
Liabilities
Derivative liabilities	35.4	15.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative assets	108	46.4
Liabilities
Derivative liabilities	25.8	8.4
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative assets	17.3	18.2
Liabilities
Derivative liabilities	9.6	6.7
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	19.9	2.4
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	19.9	2.4
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative assets	74.8	53
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative assets	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative assets	74.8	53
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative assets	$ 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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Fair Value Disclosures [Abstract]
Net unrealized losses included in earnings related to investments held at end of period	$ 10.1		$ 13.4
Net unrealized gains included in earnings related to investments held at end of period		$ 5.8		$ 9.8

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Level 3 rollforward
Balance at the beginning of the period	$ 1	$ 0.9	$ 2.4	$ 2.4
Purchases	21.9	6	21.9	6.1
Realized and unrealized gains included in earnings	1.8	0	1.8	0
Settlements	(4.8)	(1.5)	(6.2)	(3.1)
Balance at the end of the period	19.9	5.4	19.9	5.4
Gains included in earnings attributable to the change in unrealized gains of level 3 derivatives held at the end of the reporting period	$ 0.9	$ 0	$ 0.9	$ 0

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
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	13,518.7	13,563.4
Finance lease obligations	179.1	129.7
Fair value
Financial instruments
Preferred stock of subsidiary	26.4	30.3
Long-term debt, including current portion	$ 12,530.8	$ 14,819.4

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) $ in Millions	Jun. 30, 2022 USD ($) Instruments	Dec. 31, 2021 USD ($) Instruments
Derivative assets
Current derivative assets	$ 189.8	$ 107
Long-term derivative assets	30.2	13
Total derivative assets	220	120
Derivative liabilities
Current derivative liabilities	30	14
Long-term derivative liabilities	5.4	1.1
Total derivative liabilities	35.4	15.1
Natural gas contracts
Derivative assets
Current derivative assets	116.4	60.6
Long-term derivative assets	8.9	4
Derivative liabilities
Current derivative liabilities	30	14
Long-term derivative liabilities	5.4	1.1
FTRs and TCRs
Derivative assets
Current derivative assets	19.9	2.4
Derivative liabilities
Current derivative liabilities	0	0
Coal contracts
Derivative assets
Current derivative assets	53.5	44
Long-term derivative assets	21.3	9
Derivative liabilities
Current derivative liabilities	0	0
Long-term derivative liabilities	$ 0	$ 0
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, 2022 USD ($) MMBTU MWh	Jun. 30, 2021 USD ($) MMBTU MWh	Jun. 30, 2022 USD ($) MWh MMBTU	Jun. 30, 2021 USD ($) MMBTU MWh
Realized gains (losses)
Gains (losses)	$ 113.2	$ 15	$ 145.8	$ 9.6
Natural gas contracts
Notional sales volumes
Notional sales volumes | MMBTU	41.1	47.9	100.6	107.7
Realized gains (losses)
Gains (losses)	$ 108.9	$ 4.8	$ 140.5	$ (2.7)
FTRs and TCRs
Notional sales volumes
Notional sales volumes | MWh	7	7.4	14	15.8
Realized gains (losses)
Gains (losses)	$ 4.3	$ 10.2	$ 5.3	$ 12.3

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Cash collateral
Cash collateral posted	$ 14.1	$ 13.9
Cash collateral received	98.5	13.2
Offsetting derivative assets
Gross amount recognized on the balance sheet	220	120
Gross amount not offset on the balance sheet	(110.1)	(15.2)
Net amount	109.9	104.8
Collateral received	84.2	6.4
Offsetting derivative liabilities
Gross amount recognized on the balance sheet	35.4	15.1
Gross amount not offset on the balance sheet	(27.8)	(9.2)
Net amount	7.6	5.9
Collateral posted	$ 1.9	$ 0.4

DERIVATIVE INSTRUMENTS - CASH F

DERIVATIVE INSTRUMENTS - CASH FLOW HEDGES (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Nov. 15, 2021 USD ($) number_of_interest_rate_swaps
Derivative instruments
Interest expense	$ 119.8	$ 120	$ 237.4	$ 239.5
WEC Energy Group | WEC Energy Group's junior subordinated notes due in 2067
Derivative instruments
Long-term debt outstanding					$ 500
WEC Energy Group | Interest rate swaps
Derivative instruments
Number of interest rate swaps | number_of_interest_rate_swaps					2
Interest rate swap notional value					$ 250
Interest rate swap fixed interest rate					4.9765%
Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense	0.1	$ (1.3)	0.2	$ (2.7)
Amount to be reclassified from accumulated other comprehensive loss to interest expense	$ 0.4		$ 0.4

GUARANTEES (Details)

GUARANTEES (Details) $ in Millions	Jun. 30, 2022 USD ($)
Guarantees
Total guarantees	$ 106.2
Guarantees expiring in less than 1 year	23.4
Guarantees expiring within 1 to 3 years	0.2
Guarantees with expiration over 3 years	82.6
Standby letters of credit
Guarantees
Total guarantees	83.8
Guarantees expiring in less than 1 year	10.5
Guarantees expiring within 1 to 3 years	0.2
Guarantees with expiration over 3 years	73.1
Surety bonds
Guarantees
Total guarantees	12.9
Guarantees expiring in less than 1 year	12.9
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Other guarantees
Guarantees
Total guarantees	9.5
Guarantees expiring in less than 1 year	0
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	$ 9.5

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Components of net periodic benefit cost (credit)
Contributions and payments related to pension and OPEB plans			$ 8.6	$ 7.6
Pension Benefits
Components of net periodic benefit cost (credit)
Service cost	$ 14.2	$ 13.6	26.6	27.5
Interest cost	22.4	21.7	45.2	43.6
Expected return on plan assets	(52.5)	(50.1)	(105.2)	(100.7)
Loss on plan settlement	2.2	1.9	2.2	2
Amortization of prior service (credit) cost	0.4	0.4	0.8	0.8
Amortization of net actuarial (gain) loss	19.1	28.2	38.2	55.6
Net periodic benefit (credit) cost	5.8	15.7	7.8	28.8
Contributions and payments related to pension and OPEB plans			5.7
Estimated future employer contributions for the remainder of the year	5.5		5.5
Other Postretirement Benefits
Components of net periodic benefit cost (credit)
Service cost	3.3	3.6	7.1	7.8
Interest cost	3.8	3.6	7.7	7.2
Expected return on plan assets	(17.3)	(16.6)	(34.5)	(33)
Amortization of prior service (credit) cost	(3.9)	(3.9)	(7.9)	(7.9)
Amortization of net actuarial (gain) loss	(6.3)	(6.5)	(12.3)	(12.2)
Net periodic benefit (credit) cost	$ (20.4)	$ (19.8)	(39.9)	$ (38.1)
Contributions and payments related to pension and OPEB plans			$ 2.9

GOODWILL AND INTANGIBLES - GOOD

GOODWILL AND INTANGIBLES - GOODWILL (Details) $ in Millions	6 Months Ended
	Jun. 30, 2022 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	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Indefinite-lived Intangible Assets
Changes to the carrying amount of indefinite-lived intangible asset	$ 0
MGU | Trade name
Indefinite-lived Intangible Assets
Indefinite-lived intangible asset	$ 5.7	$ 5.7

GOODWILL AND INTANGIBLES - INTA

GOODWILL AND INTANGIBLES - INTANGIBLE LIABILITIES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Finite-Lived Intangible Liabilities
Amortization	$ 2.1	$ 1.9	$ 4.3	$ 3.7
Period of amortization			5 years
Amortization to be recorded in operating revenues
Amortization to be recorded in the next five years
2022	8.5		$ 8.5
2023	8.4		8.4
2024	8.4		8.4
2025	8.4		8.4
2026	8.4		8.4
Amortization to be recorded in other operation and maintenance
Amortization to be recorded in the next five years
2022	0.2		0.2
2023	0.2		0.2
2024	0.2		0.2
2025	0.2		0.2
2026	0.2		0.2
WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	99.8		99.8		$ 99.8
Accumulated amortization	(13.4)		(13.4)		(9.1)
Net carrying amount	86.4		86.4		90.7
PPAs | WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	87.9		87.9		87.9
Accumulated amortization	(10.4)		(10.4)		(6.5)
Net carrying amount	77.5		$ 77.5		81.4
PPAs | Blooming Grove , Tatanka Ridge, and Jayhawk
Finite-Lived Intangible Liabilities
Weighted average life			10 years
Proxy revenue swap | WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	7.2		$ 7.2		7.2
Accumulated amortization	(2.4)		(2.4)		(2.1)
Net carrying amount	4.8		$ 4.8		5.1
Proxy revenue swap | Upstream
Finite-Lived Intangible Liabilities
Weighted average life			7 years
Length of proxy revenue contract, in years			10 years
Interconnection agreements | WECI
Finite-Lived Intangible Liabilities
Gross carrying amount	4.7		$ 4.7		4.7
Accumulated amortization	(0.6)		(0.6)		(0.5)
Net carrying amount	$ 4.1		$ 4.1		$ 4.2
Interconnection agreements | Tatanka Ridge and Bishop Hill III
Finite-Lived Intangible Liabilities
Weighted average life			18 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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Changes to investments in transmission affiliates
Add: Earnings from equity method investment	$ 43	$ 41.3	$ 84.7	$ 83.9
Add: Capital contributions			30.3	0
Transmission Affiliates
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	1,818.2	1,773.6
Add: Earnings from equity method investment	43	41.3
Add: Capital contributions	9.2
Less: Distributions	33.2	32.8
Investment in transmission affiliates, balance at end of period	1,837.2	1,782	1,837.2	1,782
Transmission Affiliates
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period			1,789.4	1,764.3
Add: Earnings from equity method investment			84.7	83.9
Add: Capital contributions			30.3
Less: Distributions			67.2	66.2
Add: Other		(0.1)
Investment in transmission affiliates, balance at end of period	$ 1,837.2	1,782	$ 1,837.2	1,782
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	$ 1,795	1,741.9	$ 1,766.9	1,733.5
Add: Earnings from equity method investment	42.6	40.7	83.6	82.4
Add: Capital contributions	9.2		30.3
Less: Distributions	33.2	32.8	67.2	66.2
Add: Other		(0.1)
Investment in transmission affiliates, balance at end of period	$ 1,813.6	1,749.7	$ 1,813.6	1,749.7
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	$ 23.2	31.7	$ 22.5	30.8
Add: Earnings from equity method investment	0.4	0.6	1.1	1.5
Add: Capital contributions	0		0
Less: Distributions	0	0	0	0
Add: Other		0
Investment in transmission affiliates, balance at end of period	$ 23.6	$ 32.3	$ 23.6	$ 32.3

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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Investment in transmission affiliates
Charges to ATC for services and construction	$ 4.7	$ 5.7	$ 10.9	$ 11.7
Charges from ATC for network transmission services	$ 90.8	$ 89.1	$ 181.9	$ 181.7

INVESTMENT IN TRANSMISSION AF_5

INVESTMENT IN TRANSMISSION AFFILIATES - RECEIVABLES AND PAYABLES (Details) - ATC - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Investment in transmission affiliates
Accounts receivable for services provided to ATC	$ 1.4	$ 2
Accounts payable for services received from ATC	30.6	30.2
Amounts due from ATC for transmission infrastructure upgrades	$ 14.9	$ 13

INVESTMENT IN TRANSMISSION AF_6

INVESTMENT IN TRANSMISSION AFFILIATES - SUMMARIZED FINANCIAL DATA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Summarized financial data
Operating revenues	$ 2,127.9	$ 1,676.2	$ 5,036	$ 4,367.6
Operating expenses	1,719.7	1,307.4	3,896.4	3,369.5
Other expense, net	57	39	93.3	83.1
Current assets	2,642.5		2,642.5		$ 2,656.7
Noncurrent assets	36,964.6		36,964.6		36,331.8
Total assets	39,607.1		39,607.1		38,988.5
Current liabilities	3,817.8		3,817.8		3,753
Other noncurrent liabilities	1,176.9		1,176.9		1,203.2
Total liabilities and members' equity	39,607.1		39,607.1		38,988.5
ATC
Summarized financial data
Operating revenues	191.6	185.9	382.6	374.6
Operating expenses	95.2	92.4	190.7	187.5
Other expense, net	28.8	28.1	56.8	56.6
Net income	67.6	$ 65.4	135.1	$ 130.5
Current assets	106		106		89.8
Noncurrent assets	5,801.8		5,801.8		5,628.1
Total assets	5,907.8		5,907.8		5,717.9
Current liabilities	482.7		482.7		436.9
Long-term debt	2,562.4		2,562.4		2,513
Other noncurrent liabilities	438.5		438.5		422
Members' equity	2,424.2		2,424.2		2,346
Total liabilities and members' equity	$ 5,907.8		$ 5,907.8		$ 5,717.9

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)	Jun. 30, 2022 USD ($) segment	Jun. 30, 2021 USD ($)
Segment information
Number of reportable segments | segment					6
Total operating revenues	$ 2,127.9		$ 1,676.2		$ 5,036	$ 4,367.6
Other operation and maintenance	449		463.8		903.4	943.7
Depreciation and amortization	279.6		266.2		557.7	527.6
Equity in earnings of transmission affiliates	43		41.3		84.7	83.9
Interest expense	119.8		120		237.4	239.5
Income tax expense (benefit)	63.4		54.1		190.5	129
Net income (loss)	287.8		275.7		855.8	786
Net income (loss) attributed to common shareholders	287.5	$ 565.9	276	$ 510.1	853.4	786.1
External Revenues
Segment information
Total operating revenues	2,127.9		1,676.2		5,036	4,367.6
Intersegment Revenues
Segment information
Total operating revenues	0		0		0	0
Utility Operations
Segment information
Other operation and maintenance	439.9		458.1		890.7	932.5
Depreciation and amortization	255.3		243.2		509.2	481.3
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	156.8		157.9		314.1	316
Income tax expense (benefit)	71.4		39.9		219.3	137.8
Net income (loss)	207.8		192.9		641.1	586.3
Net income (loss) attributed to common shareholders	207.5		192.6		640.5	585.7
Utility Operations | External Revenues
Segment information
Total operating revenues	2,099.7		1,655.1		4,965	4,323.5
Utility Operations | Intersegment Revenues
Segment information
Total operating revenues	0		0		0	0
Reconciling Eliminations
Segment information
Other operation and maintenance	(3.9)		(3.9)		(5.5)	(5.5)
Depreciation and amortization	(16.8)		(14.7)		(33.1)	(29)
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	(83.8)		(85.2)		(168.2)	(170.9)
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
Total operating revenues	0		0		0	0
Reconciling Eliminations | Intersegment Revenues
Segment information
Total operating revenues	$ (115.5)		(112.5)		$ (232.4)	(227.2)
ATC Holdco
Segment information
Equity method investment, ownership interest (as a percent)	75%				75%
Equity in earnings of transmission affiliates	$ 0.4		0.6		$ 1.1	1.5
Wisconsin
Segment information
Total operating revenues	1,557.4		1,307.5		3,499.7	3,039.2
Wisconsin | Utility Operations
Segment information
Other operation and maintenance	337.9		346.1		650.5	688
Depreciation and amortization	187.7		179.8		374.8	356
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	135.6		139.8		271.9	279.9
Income tax expense (benefit)	49.3		23.1		144.7	71.2
Net income (loss)	148.7		146.8		437.1	403.4
Net income (loss) attributed to common shareholders	148.4		146.5		436.5	402.8
Wisconsin | Utility Operations | External Revenues
Segment information
Total operating revenues	1,557.4		1,307.5		3,499.7	3,039.2
Wisconsin | Utility Operations | Intersegment Revenues
Segment information
Total operating revenues	0		0		0	0
Illinois
Segment information
Total operating revenues	442.4		275.5		1,124.5	978.9
Illinois | Utility Operations
Segment information
Other operation and maintenance	79.1		90.8		192.7	200.1
Depreciation and amortization	57.4		54		114.2	106.7
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	18		16.6		35.7	33.1
Income tax expense (benefit)	21.2		16		63.3	57.4
Net income (loss)	56.4		43.6		169.8	155.7
Net income (loss) attributed to common shareholders	56.4		43.6		169.8	155.7
Illinois | Utility Operations | External Revenues
Segment information
Total operating revenues	442.4		275.5		1,124.5	978.9
Illinois | Utility Operations | Intersegment Revenues
Segment information
Total operating revenues	0		0		0	0
Other States
Segment information
Total operating revenues	99.9		72.1		340.8	305.4
Other States | Utility Operations
Segment information
Other operation and maintenance	22.9		21.2		47.5	44.4
Depreciation and amortization	10.2		9.4		20.2	18.6
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	3.2		1.5		6.5	3
Income tax expense (benefit)	0.9		0.8		11.3	9.2
Net income (loss)	2.7		2.5		34.2	27.2
Net income (loss) attributed to common shareholders	2.7		2.5		34.2	27.2
Other States | Utility Operations | External Revenues
Segment information
Total operating revenues	99.9		72.1		340.8	305.4
Other States | Utility Operations | Intersegment Revenues
Segment information
Total operating revenues	0		0		0	0
Electric Transmission
Segment information
Other operation and maintenance	0		0		0	0
Depreciation and amortization	0		0		0	0
Equity in earnings of transmission affiliates	43		41.3		84.7	83.9
Interest expense	4.8		4.8		9.7	9.7
Income tax expense (benefit)	9.3		9.4		18.2	19.2
Net income (loss)	29		27		56.8	55
Net income (loss) attributed to common shareholders	29		27		56.8	55
Electric Transmission | External Revenues
Segment information
Total operating revenues	0		0		0	0
Electric Transmission | Intersegment Revenues
Segment information
Total operating revenues	$ 0		0		$ 0	0
Electric Transmission | ATC
Segment information
Equity method investment, ownership interest (as a percent)	60%				60%
Electric Transmission | ATC Holdco
Segment information
Equity method investment, ownership interest (as a percent)	75%				75%
Non-Utility Energy Infrastructure
Segment information
Natural gas storage needs provided to Wisconsin utilities					33%
Total operating revenues	$ 143.6		133.5		$ 303.1	271.1
Other operation and maintenance	13.9		12.4		24.8	21.3
Depreciation and amortization	34.3		31.3		68.3	62.3
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	17.4		17.9		34.6	35.9
Income tax expense (benefit)	(7.3)		0.7		(12.2)	0.8
Net income (loss)	80.3		68.2		173.6	139.5
Net income (loss) attributed to common shareholders	80.3		68.8		171.8	140.2
Non-Utility Energy Infrastructure | External Revenues
Segment information
Total operating revenues	28.1		21		70.7	43.9
Non-Utility Energy Infrastructure | Intersegment Revenues
Segment information
Total operating revenues	$ 115.5		112.5		$ 232.4	227.2
Non-Utility Energy Infrastructure | Bishop Hill III
Segment information
WEC's ownership interest	90%				90%
Non-Utility Energy Infrastructure | Coyote Ridge
Segment information
WEC's ownership interest	80%				80%
Non-Utility Energy Infrastructure | Upstream
Segment information
WEC's ownership interest	90%				90%
Non-Utility Energy Infrastructure | Blooming Grove
Segment information
WEC's ownership interest	90%				90%
Non-Utility Energy Infrastructure | Tatanka Ridge
Segment information
WEC's ownership interest	85%				85%
Non-Utility Energy Infrastructure | Jayhawk
Segment information
WEC's ownership interest	90%				90%
Corporate and Other
Segment information
Total operating revenues	$ 0.1		0.1		$ 0.3	0.2
Other operation and maintenance	(0.9)		(2.8)		(6.6)	(4.6)
Depreciation and amortization	6.8		6.4		13.3	13
Equity in earnings of transmission affiliates	0		0		0	0
Interest expense	24.6		24.6		47.2	48.8
Income tax expense (benefit)	(10)		4.1		(34.8)	(28.8)
Net income (loss)	(29.3)		(12.4)		(15.7)	5.2
Net income (loss) attributed to common shareholders	(29.3)		(12.4)		(15.7)	5.2
Corporate and Other | External Revenues
Segment information
Total operating revenues	0.1		0.1		0.3	0.2
Corporate and Other | Intersegment Revenues
Segment information
Total 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, 2022	Dec. 31, 2021
Assets
Other current assets (restricted cash)		$ 21.9	$ 19.6
Regulatory assets		3,144.7	3,264.8
Other long-term assets (restricted cash)		52.7	51.6
WEPCo Environmental Trust
Variable interest entities
Securitization of environmental control costs related to Pleasant Prairie power plant	$ 100
Assets
Other current assets (restricted cash)		3.1	2.4
Regulatory assets		96.1	100.7
Other long-term assets (restricted cash)		0.6	0.6
Liabilities
Current portion of long-term debt		8.8	8.8
Other current liabilities (accrued interest)		0.1	0.1
Long-term debt		$ 98.4	$ 102.7

VARIABLE INTEREST ENTITIES - TR

VARIABLE INTEREST ENTITIES - TRANSMISSION AFFILIATES (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
ATC
Variable interest entities
Ownership interest (as a percent)	60%
Equity investment	$ 1,813.6	$ 1,766.9
ATC Holdco
Variable interest entities
Ownership interest (as a percent)	75%
Equity investment	$ 23.6	$ 22.5

VARIABLE INTEREST ENTITIES - PO

VARIABLE INTEREST ENTITIES - POWER PURCHASE COMMITMENT (Details) - Power purchase commitment $ in Millions	1 Months Ended
	Nov. 30, 2021 USD ($)	Jun. 30, 2022 USD ($)	May 31, 2022 MW
Variable interest entities
Firm capacity from power purchase commitment (in megawatts) | MW			236.5
Residual guarantee associated with power purchase commitment		$ 0
Maximum exposure to loss from power purchase commitment		$ 1.9
Whitewater cogeneration facility
Variable interest entities
Expected purchase price for facility	$ 72.7

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions	Jun. 30, 2022 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 10.5

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended					6 Months Ended	12 Months Ended	15 Months Ended
	May 31, 2022 micrograms	Mar. 31, 2022 micrograms	Jun. 30, 2021 area	Dec. 31, 2020 USD ($) micrograms performance_obligations	Jun. 30, 2020 generating_units	Jun. 30, 2022 USD ($) States MW	Dec. 31, 2020 USD ($) performance_obligations	Mar. 31, 2019 MW	Dec. 31, 2021 USD ($)	Oct. 31, 2021 performance_obligations
Manufactured gas plant remediation
Regulatory assets | $						$ 3,278.9			$ 3,367.1
Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets | $						$ 621.6			630.9
Cross State Air Pollution Rule - Good Neighbor Plan | Electric
Air quality
Number of states the EPA is proposing to update and expand cross state air pollution rules to regulate NOx emissions in | States						26
Cross State Air Pollution Rule - Good Neighbor Plan | Electric | Maximum
Air quality
RICE unit megawatts | MW						25
National Ambient Air Quality Standards | Electric
Air quality
Number of changes to the 2015 ozone standards | performance_obligations										0
Number of counties to have boundaries revised | area			13
Number of nonattainment areas as designated by the EPA | area			6
Number of revisions necessary to meet the 2012 standard for particulate matter | performance_obligations				0
Current number of micrograms per cubic meter that particulate matter needs to be below				12
24-hour standard for fine particulate matter				35
Lowest limit that will cause non-attainment		10
National Ambient Air Quality Standards | Electric | Maximum
Air quality
Majority of CASAC members support this range in the peer review they completed		10
Minority of CASAC members support this range in the peer review they completed		11
Upper range of the annual standard the EPA staff supported	12
Lower range of the annual standard the EPA staff supported	10
National Ambient Air Quality Standards | Electric | Minimum
Air quality
Majority of CASAC members support this range in the peer review they completed		8
Minority of CASAC members support this range in the peer review they completed		10
Upper range of the annual standard the EPA staff supported	10
Lower range of the annual standard the EPA staff supported	8
Climate Change | Electric
Air quality
Capacity of coal-fired generation retired, in megawatts | MW								1,800
Capacity of fossil-fueled generation to be retired by the end of 2026, in megawatts | MW						1,600
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%
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of generating units that may be retired | generating_units					4
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Number of new ELG rule requirements that affect our electric utilities | performance_obligations							2
Capital investment to achieve required discharge limits | $				$ 100			$ 100
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Reserves for future environmental remediation | $						$ 504.3			532.6
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets | $						$ 621.6			$ 630.9

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Supplemental cash flow information
Cash paid for interest, net of amount capitalized	$ 234.9	$ 239.9
Cash paid for income taxes, net	37.3	28.2
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	210.2	127.9
Increase in receivable related to insurance proceeds	0	39.6
Liabilities accrued for software licensing agreement	$ 7.4	$ 0

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 30.3	$ 16.3
Restricted cash included in other current assets	21.9	19.6
Restricted cash included in other long term assets	52.7	51.6
Cash, cash equivalents, and restricted cash	$ 104.9	$ 87.5	$ 99.7	$ 72.6

REGULATORY ENVIRONMENT - RECOVE

REGULATORY ENVIRONMENT - RECOVERY OF NATURAL GAS COSTS (Details) $ in Millions	1 Months Ended
	Aug. 31, 2021 USD ($) utility	Mar. 31, 2021 USD ($)	Feb. 28, 2021 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers				$ 134.2	$ 102.3
Total regulatory assets				3,278.9	3,367.1
Regulatory assets				3,144.7	3,264.8
Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Total regulatory assets				120	85.4
MERC extraordinary natural gas costs
Public Utilities, General Disclosures [Line Items]
Total regulatory assets				$ 47.1	$ 59.7
WE | Public Service Commission of Wisconsin (PSCW) | Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers		$ 54
Recovery period of regulatory asset		3 months
WG | Public Service Commission of Wisconsin (PSCW) | Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers		$ 24
Recovery period of regulatory asset		3 months
WPS | Public Service Commission of Wisconsin (PSCW) | Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers		$ 28
Recovery period of regulatory asset		3 months
PGL | Illinois Commerce Commission (ICC) | Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers			$ 131
Recovery period of regulatory asset			12 months
NSG | Illinois Commerce Commission (ICC) | Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers			$ 10
Recovery period of regulatory asset			12 months
MERC | Minnesota Public Utilities Commission (MPUC)
Public Utilities, General Disclosures [Line Items]
Number of utilities filing a joint proposal | utility	4
MERC | Minnesota Public Utilities Commission (MPUC) | Energy costs recoverable through rate adjustments
Public Utilities, General Disclosures [Line Items]
Amounts recoverable from customers	$ 10
Recovery period of regulatory asset	12 months
Total regulatory assets			$ 75
MERC | Minnesota Public Utilities Commission (MPUC) | MERC extraordinary natural gas costs
Public Utilities, General Disclosures [Line Items]
Recovery period of regulatory asset	27 months
Regulatory assets	$ 65

REGULATORY ENVIRONMENT - WI 202

REGULATORY ENVIRONMENT - WI 2023 AND 2024 RATES (Details) - Public Service Commission of Wisconsin (PSCW) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	Jul. 31, 2022	Apr. 30, 2022	Jun. 30, 2022
Public Utilities, Rate Matters, Requested
Percentage of first 25 basis points of additional earnings retained by the utility		100%
Return on equity in excess of authorized amount (as a percent)		0.25%
Percentage of additional earnings between 25 and 75 basis points refunded to customers		50%
Return on equity in excess of first 25 basis points above authorized amount (as a percent)		0.50%
Percentage of earnings in excess of 75 basis points refunded to customers		100%
WE
Public Utilities, Rate Matters, Requested
Requested return on equity (as a percent)		10%
Requested common equity component average (as a percent)		53%
Public Utilities, Rate Matters, Approved
Approved common equity component average (as a percent)			52.50%
WE | Subsequent event
Public Utilities, Rate Matters, Requested
Aggregate increase from original request	$ 30
WE | Electric rates | Subsequent event
Public Utilities, Rate Matters, Requested
Requested rate increase	$ 285.6
Requested rate increase (as a percent)	9.20%
WE | Natural gas rates | Subsequent event
Public Utilities, Rate Matters, Requested
Requested rate increase	$ 55.4
Requested rate increase (as a percent)	11.70%
WE | Steam rates | Subsequent event
Public Utilities, Rate Matters, Requested
Requested rate increase	$ 3.6
Requested rate increase (as a percent)	16.50%
WE | OCPP Units 5 and 6 | Subsequent event
Public Utilities, Rate Matters, Requested
Delay in plant retirements	1 year
WE | OCPP Units 7 and 8 | Subsequent event
Public Utilities, Rate Matters, Requested
Delay in plant retirements	18 months
WPS
Public Utilities, Rate Matters, Requested
Requested return on equity (as a percent)		10%
Requested common equity component average (as a percent)		53%
Public Utilities, Rate Matters, Approved
Approved common equity component average (as a percent)			52.50%
WPS | Subsequent event
Public Utilities, Rate Matters, Requested
Aggregate increase from original request	$ 6
WPS | Electric rates | Subsequent event
Public Utilities, Rate Matters, Requested
Requested rate increase	$ 79.4
Requested rate increase (as a percent)	6.60%
WPS | Natural gas rates | Subsequent event
Public Utilities, Rate Matters, Requested
Requested rate increase	$ 30.9
Requested rate increase (as a percent)	8.40%
WPS | Columbia Energy Center Units 1 and 2
Public Utilities, Rate Matters, Requested
Joint plant ownership percentage			27.50%
WG
Public Utilities, Rate Matters, Requested
Requested return on equity (as a percent)		10.20%
Requested common equity component average (as a percent)		53%
Public Utilities, Rate Matters, Approved
Approved common equity component average (as a percent)			52.50%
WG | Subsequent event
Public Utilities, Rate Matters, Requested
Aggregate increase from original request	$ 2
WG | Natural gas rates | Subsequent event
Public Utilities, Rate Matters, Requested
Requested rate increase	$ 61.9
Requested rate increase (as a percent)	8.60%

REGULATORY ENVIRONMENT - PGL QI

REGULATORY ENVIRONMENT - PGL QIP Rider (Details)	Jun. 30, 2022 Assurance
Illinois Commerce Commission (ICC) | PGL
Public Utilities, General Disclosures [Line Items]
Amount of assurance that PGL's QIP rider costs will be recoverable	0