Item 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)						Three Months Ended												Nine Months Ended
			September 30												September 30
(in millions, except per share amounts)						2023						2022						2023						2022
Operating revenues						$	1,957.4					$	2,003.0					$	6,675.5					$	7,039.0
Operating expenses
Cost of sales						587.4						805.1						2,430.1						3,123.5
Other operation and maintenance						516.6						454.3						1,546.6						1,357.7
Depreciation and amortization						320.3						280.3						939.7						838.0
Property and revenue taxes						61.1						59.1						192.5						176.0
Total operating expenses						1,485.4						1,598.8						5,108.9						5,495.2
Operating income						472.0						404.2						1,566.6						1,543.8
Equity in earnings of transmission affiliates						44.7						63.7						132.1						148.4
Other income, net						41.8						34.7						130.9						94.1
Interest expense						182.5						127.5						533.4						364.9
Other expense						(96.0)						(29.1)						(270.4)						(122.4)
Income before income taxes						376.0						375.1						1,296.2						1,421.4
Income tax expense						60.4						73.4						183.0						263.9
Net income						315.6						301.7						1,113.2						1,157.5
Preferred stock dividends of subsidiary						0.3						0.3						0.9						0.9
Net loss (income) attributed to noncontrolling interests						0.7						0.6						0.9						(1.2)
Net income attributed to common shareholders						$	316.0					$	302.0					$	1,113.2					$	1,155.4
Earnings per share
Basic						$	1.00					$	0.96					$	3.53					$	3.66
Diluted						$	1.00					$	0.96					$	3.52					$	3.65
Weighted average common shares outstanding
Basic						315.4						315.4						315.4						315.4
Diluted						315.8						316.2						315.9						316.2

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)						Three Months Ended												Nine Months Ended
			September 30												September 30
(in millions)						2023						2022						2023						2022
Net income						$	315.6					$	301.7					$	1,113.2					$	1,157.5
Other comprehensive income (loss), net of tax
Derivatives accounted for as cash flow hedges
Reclassification of realized derivative gains to net income, net of tax						(0.1)						—						(0.2)						(0.1)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax						—						—						—						0.1
Other comprehensive loss, net of tax						(0.1)						—						(0.2)						—
Comprehensive income						315.5						301.7						1,113.0						1,157.5
Preferred stock dividends of subsidiary						0.3						0.3						0.9						0.9
Comprehensive loss (income) attributed to noncontrolling interests						0.7						0.6						0.9						(1.2)
Comprehensive income attributed to common shareholders						$	315.9					$	302.0					$	1,113.0					$	1,155.4

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)						September 30, 2023						December 31, 2022
Assets
Current assets
Cash and cash equivalents						$	45.9					$	28.9
Accounts receivable and unbilled revenues, net of reserves of $176.8 and $199.3, respectively						1,243.2						1,818.4
Materials, supplies, and inventories						749.9						807.1
Prepaid taxes						157.8						201.8
Other prepayments						40.6						69.8
Collateral on deposit						118.4						122.4
Other						87.8						139.3
Current assets						2,443.6						3,187.7
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,914.6 and $10,383.8, respectively						31,467.5						29,113.8
Regulatory assets (September 30, 2023 and December 31, 2022 include $87.5 and $92.4, respectively, related to WEPCo Environmental Trust)						3,197.1						3,264.6
Equity investment in transmission affiliates						1,983.8						1,909.2
Goodwill						3,052.8						3,052.8
Pension and OPEB assets						918.7						916.7
Other						378.2						427.3
Long-term assets						40,998.1						38,684.4
Total assets						$	43,441.7					$	41,872.1
Liabilities and Equity
Current liabilities
Short-term debt						$	1,549.3					$	1,647.1
Current portion of long-term debt (September 30, 2023 and December 31, 2022 include $9.0 and $8.9, respectively, related to WEPCo Environmental Trust)						712.9						881.2
Accounts payable						867.7						1,198.1
Other						943.8						884.6
Current liabilities						4,073.7						4,611.0
Long-term liabilities
Long-term debt (September 30, 2023 and December 31, 2022 include $89.8 and $94.1, respectively, related to WEPCo Environmental Trust)						15,956.5						14,766.2
Deferred income taxes						4,832.2						4,625.6
Deferred revenue, net						360.4						370.7
Regulatory liabilities						3,720.0						3,735.5
Intangible liabilities						608.2						335.4
Asset retirement obligations						505.5						479.3
Environmental remediation liabilities						456.6						499.6
Other						828.3						832.2
Long-term liabilities						27,267.7						25,644.5
Commitments and contingencies (Note 23)
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						4,116.4						4,115.2
Retained earnings						7,640.4						7,265.3
Accumulated other comprehensive loss						(7.0)						(6.8)
Common shareholders' equity						11,753.0						11,376.9
Preferred stock of subsidiary						30.4						30.4
Noncontrolling interests						316.9						209.3
Total liabilities and equity						$	43,441.7					$	41,872.1

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)						Nine Months Ended
						September 30
(in millions)						2023						2022
Operating activities
Net income						$	1,113.2					$	1,157.5
Reconciliation to cash provided by operating activities
Depreciation and amortization						939.7						838.0
Deferred income taxes and ITCs, net						155.9						187.8
Contributions and payments related to pension and OPEB plans						(13.0)						(11.6)
Equity income in transmission affiliates, net of distributions						(23.1)						(47.1)
Change in –
Accounts receivable and unbilled revenues, net						600.7						150.9
Materials, supplies, and inventories						67.2						(288.8)
Prepaid taxes						43.6						57.8
Other current assets						64.7						45.4
Accounts payable						(350.6)						82.2
Other current liabilities						52.3						68.5
Other, net						(112.2)						(181.1)
Net cash provided by operating activities						2,538.4						2,059.5
Investing activities
Capital expenditures						(1,729.5)						(1,700.7)
Acquisition of Whitewater						(76.0)						—
Acquisition of Sapphire Sky, net of cash acquired of $0.3						(442.6)						—
Acquisition of Samson I, net of cash acquired of $5.2						(249.4)						—
Acquisition of Red Barn						(143.8)						—
Acquisition of West Riverside						(95.3)						—
Acquisition of Thunderhead, net of cash acquired of $0.5						—						(362.9)
Capital contributions to transmission affiliates						(51.5)						(39.4)
Proceeds from the sale of assets						30.4						69.0
Proceeds from the sale of investments held in rabbi trust						10.4						15.4
Payments for ATC's construction costs that will be reimbursed						(19.5)						(20.6)
Insurance proceeds received for property damage						0.5						41.6
Other, net						(5.4)						11.7
Net cash used in investing activities						(2,771.7)						(1,985.9)
Financing activities
Exercise of stock options						3.0						33.1
Purchase of common stock						(10.7)						(68.3)
Dividends paid on common stock						(738.1)						(688.5)
Issuance of long-term debt						2,050.0						1,400.0
Retirement of long-term debt						(996.0)						(64.9)
Change in commercial paper						(98.2)						(640.2)
Payments for debt issuance costs						(13.0)						(9.1)
Other, net						(4.5)						(7.2)
Net cash provided by (used in) financing activities						192.5						(45.1)
Net change in cash, cash equivalents, and restricted cash						(40.8)						28.5
Cash, cash equivalents, and restricted cash at beginning of period						182.2						87.5
Cash, cash equivalents, and restricted cash at end of period						$	141.4					$	116.0

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

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WEC ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)
						WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)						Common Stock						Additional Paid In Capital						Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Shareholders' Equity						Preferred Stock of Subsidiary						Non-controlling Interests						Total Equity
Balance at December 31, 2022						$	3.2					$	4,115.2					$	7,265.3					$	(6.8)					$	11,376.9					$	30.4					$	209.3					$	11,616.6
Net income attributed to common shareholders						—						—						507.5						—						507.5						—						—						507.5
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(0.2)						(0.2)
Other comprehensive loss						—						—						—						(0.1)						(0.1)						—						—						(0.1)
Common stock dividends of $0.7800 per share						—						—						(246.1)						—						(246.1)						—						—						(246.1)
Exercise of stock options						—						0.9						—						—						0.9						—						—						0.9
Purchase of common stock						—						(6.9)						—						—						(6.9)						—						—						(6.9)
Acquisition of noncontrolling interests						—						—						—						—						—						—						112.9						112.9
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.3)						(1.3)
Stock-based compensation and other						—						4.4						—						—						4.4						—						—						4.4
Balance at March 31, 2023						$	3.2					$	4,113.6					$	7,526.7					$	(6.9)					$	11,636.6					$	30.4					$	320.7					$	11,987.7
Net income attributed to common shareholders						—						—						289.7						—						289.7						—						—						289.7
Common stock dividends of $0.7800 per share						—						—						(246.0)						—						(246.0)						—						—						(246.0)
Exercise of stock options						—						1.4						—						—						1.4						—						—						1.4
Purchase of common stock						—						(2.6)						—						—						(2.6)						—						—						(2.6)
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.0)						(1.0)
Stock-based compensation and other						—						2.3						—						—						2.3						—						(0.1)						2.2
Balance at June 30, 2023						$	3.2					$	4,114.7					$	7,570.4					$	(6.9)					$	11,681.4					$	30.4					$	319.6					$	12,031.4
Net income attributed to common shareholders						—						—						316.0						—						316.0						—						—						316.0
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(0.7)						(0.7)
Other comprehensive loss						—						—						—						(0.1)						(0.1)						—						—						(0.1)
Common stock dividends of $0.7800 per share						—						—						(246.0)						—						(246.0)						—						—						(246.0)
Exercise of stock options						—						0.7						—						—						0.7						—						—						0.7
Purchase of common stock						—						(1.2)						—						—						(1.2)						—						—						(1.2)
Distributions to noncontrolling interests						—						—						—						—						—						—						(2.0)						(2.0)
Stock-based compensation and other						—						2.2						—						—						2.2						—						—						2.2
Balance at September 30, 2023						$	3.2					$	4,116.4					$	7,640.4					$	(7.0)					$	11,753.0					$	30.4					$	316.9					$	12,100.3

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						WEC Energy Group Common Shareholders' Equity
(in millions, except per share amounts)						Common Stock						Additional Paid In Capital						Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Shareholders' Equity						Preferred Stock of Subsidiary						Non-controlling Interests						Total Equity
Balance at December 31, 2021						$	3.2					$	4,138.1					$	6,775.1					$	(3.2)					$	10,913.2					$	30.4					$	169.7					$	11,113.3
Net income attributed to common shareholders						—						—						565.9						—						565.9						—						—						565.9
Net income attributed to noncontrolling interests						—						—						—						—						—						—						1.8						1.8
Common stock dividends of $0.7275 per share						—						—						(229.6)						—						(229.6)						—						—						(229.6)
Exercise of stock options						—						11.8						—						—						11.8						—						—						11.8
Purchase of common stock						—						(23.4)						—						—						(23.4)						—						—						(23.4)
Capital contributions from noncontrolling interest						—						—						—						—						—						—						0.4						0.4
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.0)						(1.0)
Stock-based compensation and other						—						5.3						—						—						5.3						—						—						5.3
Balance at March 31, 2022						$	3.2					$	4,131.8					$	7,111.4					$	(3.2)					$	11,243.2					$	30.4					$	170.9					$	11,444.5
Net income attributed to common shareholders						—						—						287.5						—						287.5						—						—						287.5
Common stock dividends of $0.7275 per share						—						—						(229.4)						—						(229.4)						—						—						(229.4)
Exercise of stock options						—						11.2						—						—						11.2						—						—						11.2
Purchase of common stock						—						(25.0)						—						—						(25.0)						—						—						(25.0)
Capital contributions from noncontrolling interest						—						—						—						—						—						—						0.1						0.1
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.2)						(1.2)
Stock-based compensation and other						—						3.1						—						—						3.1						—						(0.2)						2.9
Balance at June 30, 2022						$	3.2					$	4,121.1					$	7,169.5					$	(3.2)					$	11,290.6					$	30.4					$	169.6					$	11,490.6
Net income attributed to common shareholders						—						—						302.0						—						302.0						—						—						302.0
Net loss attributed to noncontrolling interests						—						—						—						—						—						—						(0.6)						(0.6)
Common stock dividends of $0.7275 per share						—						—						(229.5)						—						(229.5)						—						—						(229.5)
Exercise of stock options						—						10.1						—						—						10.1						—						—						10.1
Purchase of common stock						—						(19.9)						—						—						(19.9)						—						—						(19.9)
Acquisition of a noncontrolling interest						—						—						—						—						—						—						42.5						42.5
Distributions to noncontrolling interests						—						—						—						—						—						—						(1.3)						(1.3)
Stock-based compensation and other						—						2.2						—						—						2.2						—						—						2.2
Balance at September 30, 2022						$	3.2					$	4,113.5					$	7,242.0					$	(3.2)					$	11,355.5					$	30.4					$	210.2					$	11,596.1

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

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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2023

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.7 million electric customers and 3.0 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable generating facilities as part of its non-utility energy infrastructure segment.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.

On our financial statements, we consolidate our majority-owned subsidiaries, which we control, and VIEs, of which we are the primary beneficiary. We reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheets related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 20, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2022. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2023, are not necessarily indicative of expected results for 2023 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 19, Goodwill and Intangibles, for more information.

Acquisitions of Electric Generation Facilities in Wisconsin

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

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

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

Acquisition of a Solar Generation Facility in Texas

In February 2023, WECI completed the acquisition of an 80% ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar County, Texas, for $249.4 million, which includes transaction costs and is net of cash acquired. The allocation of purchase price to the assets acquired and liabilities assumed was primarily to property, plant, and equipment and an intangible liability related to the PPA. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment.

Acquisition of Electric Generation Facility in Illinois

In February 2023, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of $442.6 million, which includes transaction costs and is net of cash acquired. The allocation of purchase price to the assets acquired and liabilities assumed was primarily to property, plant, and equipment and an intangible liability related to the PPA. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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

NOTE 3—DISPOSITIONS

Sale of Certain Real Estate by Wisconsin Electric Power Company

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

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, which is net of closing costs. 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.

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NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2022 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations has different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.

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

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2022
Electric						$	1,436.9					$	—					$	—					$	1,436.9					$	—					$	—					$	—					$	1,436.9
Natural gas						234.9						224.0						63.9						522.8						12.1						—						(11.3)						523.6
Total regulated revenues						1,671.8						224.0						63.9						1,959.7						12.1						—						(11.3)						1,960.5
Other non-utility revenues						—						—						4.8						4.8						27.3						—						(1.5)						30.6
Total revenues from contracts with customers						1,671.8						224.0						68.7						1,964.5						39.4						—						(12.8)						1,991.1
Other operating revenues						5.0						6.3						0.5						11.8						100.5						0.1						(100.5)			(1)			11.9
Total operating revenues						$	1,676.8					$	230.3					$	69.2					$	1,976.3					$	139.9					$	0.1					$	(113.3)					$	2,003.0

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

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(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2022
Electric						$	3,845.5					$	—					$	—					$	3,845.5					$	—					$	—					$	—					$	3,845.5
Natural gas						1,311.2						1,346.1						397.9						3,055.2						39.4						—						(37.1)						3,057.5
Total regulated revenues						5,156.7						1,346.1						397.9						6,900.7						39.4						—						(37.1)						6,903.0
Other non-utility revenues						—						—						13.9						13.9						102.1						—						(7.1)						108.9
Total revenues from contracts with customers						5,156.7						1,346.1						411.8						6,914.6						141.5						—						(44.2)						7,011.9
Other operating revenues						19.8						8.7						(1.8)						26.7						301.5						0.4						(301.5)			(1)			27.1
Total operating revenues						$	5,176.5					$	1,354.8					$	410.0					$	6,941.3					$	443.0					$	0.4					$	(345.7)					$	7,039.0

(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 by customer class:

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Residential						$	584.9					$	529.7					$	1,530.5					$	1,442.5
Small commercial and industrial						462.2						424.8						1,257.3						1,173.3
Large commercial and industrial						289.9						316.8						759.6						814.1
Other						7.2						7.1						22.4						22.1
Total retail revenues						1,344.2						1,278.4						3,569.8						3,452.0
Wholesale						31.9						39.7						96.5						122.9
Resale						75.3						102.7						147.8						220.2
Steam						2.6						3.0						18.2						19.8
Other utility revenues						3.8						13.1						7.8						30.6
Total electric utility operating revenues						$	1,457.8					$	1,436.9					$	3,840.1					$	3,845.5

Natural Gas Utility Operating Revenues

The following tables disaggregate natural gas utility operating revenues by customer class:

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

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(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Three Months Ended September 30, 2022
Residential						$	122.1					$	177.0					$	31.5					$	330.6
Commercial and industrial						75.5						52.6						21.5						149.6
Total retail revenues						197.6						229.6						53.0						480.2
Transportation						15.9						46.1						5.3						67.3
Other utility revenues (1)						21.4						(51.7)						5.6						(24.7)
Total natural gas utility operating revenues						$	234.9					$	224.0					$	63.9					$	522.8

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

(in millions)						Wisconsin						Illinois						Other States						Total Natural Gas Utility Operating Revenues
Nine Months Ended September 30, 2022
Residential						$	823.1					$	911.1					$	256.3					$	1,990.5
Commercial and industrial						450.1						289.1						144.9						884.1
Total retail revenues						1,273.2						1,200.2						401.2						2,874.6
Transportation						59.4						181.5						25.2						266.1
Other utility revenues (1)						(21.4)						(35.6)						(28.5)						(85.5)
Total natural gas utility operating revenues						$	1,311.2					$	1,346.1					$	397.9					$	3,055.2

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

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, 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 September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Wind generation revenues						$	38.2					$	20.0					$	117.8					$	77.5
We Power revenues (1)						5.7						5.8						17.5						17.5
Appliance service revenues						4.9						4.8						14.8						13.9
Total other non-utility operating revenues						$	48.8					$	30.6					$	150.1					$	108.9

(1)As part of the construction of the We Power electric utility generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction.

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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 September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Late payment charges						$	12.4					$	13.6					$	45.8					$	43.5
Alternative revenues (1)						—						(2.4)						13.9						(19.7)
Other						1.0						0.7						3.6						3.3
Total other operating revenues						$	13.4					$	11.9					$	63.3					$	27.1

(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, and conservation improvement rider true-ups.

NOTE 5—CREDIT LOSSES

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

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

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

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

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We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2023 and December 31, 2022, by reportable segment.

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
September 30, 2023
Accounts receivable and unbilled revenues						$	956.7					$	355.8					$	60.6					$	1,373.1					$	40.2					$	6.7					$	1,420.0
Allowance for credit losses						72.0						100.0						4.8						176.8						—						—						176.8
Accounts receivable and unbilled revenues, net (1)						$	884.7					$	255.8					$	55.8					$	1,196.3					$	40.2					$	6.7					$	1,243.2
Total accounts receivable, net – past due greater than 90 days (1)						$	54.0					$	69.7					$	4.2					$	127.9					$	—					$	—					$	127.9
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						94.0		%				100.0		%				—		%				94.2		%				—		%				—		%				94.2		%

(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Non-Utility Energy Infrastructure						Corporate and Other						WEC Energy Group Consolidated
December 31, 2022
Accounts receivable and unbilled revenues						$	1,199.4					$	624.2					$	164.4					$	1,988.0					$	25.4					$	4.3					$	2,017.7
Allowance for credit losses						82.0						111.0						6.3						199.3						—						—						199.3
Accounts receivable and unbilled revenues, net (1)						$	1,117.4					$	513.2					$	158.1					$	1,788.7					$	25.4					$	4.3					$	1,818.4
Total accounts receivable, net – past due greater than 90 days (1)						$	51.9					$	52.9					$	1.9					$	106.7					$	—					$	—					$	106.7
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						97.0		%				100.0		%				—		%				96.8		%				—		%				—		%				96.8		%

(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 September 30, 2023, $634.7 million, or 51.1%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

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

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

Nine Months Ended September 30, 2023 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2023						$	82.0					$	111.0					$	6.3					$	199.3
Provision for credit losses						28.1						17.3						1.5						46.9
Provision for credit losses deferred for future recovery or refund						26.3						13.8						—						40.1
Write-offs charged against the allowance						(89.8)						(58.7)						(4.2)						(152.7)
Recoveries of amounts previously written off						25.4						16.6						1.2						43.2
Balance at September 30, 2023						$	72.0					$	100.0					$	4.8					$	176.8

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On a consolidated basis, there was a $22.5 million decrease in the allowance for credit losses at September 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the end of the winter moratorium. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. In addition, lower energy costs driven by lower natural gas prices contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

Three Months Ended September 30, 2022 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at July 1, 2022						$	78.0					$	91.0					$	6.8					$	175.8
Provision for credit losses						10.0						5.2						0.6						15.8
Provision for credit losses deferred for future recovery or refund						10.2						2.6						—						12.8
Write-offs charged against the allowance						(34.6)						(13.5)						(1.3)						(49.4)
Recoveries of amounts previously written off						8.8						4.4						0.3						13.5
Balance at September 30, 2022						$	72.4					$	89.7					$	6.4					$	168.5

Nine Months Ended September 30, 2022 (in millions)						Wisconsin						Illinois						Other States						WEC Energy Group Consolidated
Balance at January 1, 2022						$	84.0					$	105.5					$	8.8					$	198.3
Provision for credit losses						33.6						23.6						0.7						57.9
Provision for credit losses deferred for future recovery or refund						13.6						3.5						—						17.1
Write-offs charged against the allowance						(85.5)						(58.7)						(3.9)						(148.1)
Recoveries of amounts previously written off						26.7						15.8						0.8						43.3
Balance at September 30, 2022						$	72.4					$	89.7					$	6.4					$	168.5

On a consolidated basis, there was a $29.8 million decrease in the allowance for credit losses at September 30, 2022, compared to January 1, 2022. 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. Partially offsetting the decrease in the allowance for credit losses, we believe that the high energy costs that customers experienced during this time, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.

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NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2023 and December 31, 2022. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2022 Annual Report on Form 10-K.

(in millions)						September 30, 2023						December 31, 2022
Regulatory assets
Pension and OPEB costs						$	691.2					$	714.3
Plant retirement related items						657.0						688.6
Environmental remediation costs						577.7						610.7
Income tax related items						450.4						461.9
Asset retirement obligations						170.1						169.7
Derivatives						126.2						133.8
System support resource						115.9						123.5
Uncollectible expense						95.5						69.3
Securitization						87.5						92.4
Bluewater (1)						39.9						20.9
Energy costs recoverable through rate adjustments						35.5						26.9
Energy efficiency programs						25.3						33.9
MERC extraordinary natural gas costs						9.3						35.1
Other, net						131.4						125.9
Total regulatory assets						$	3,212.9					$	3,306.9
Balance sheet presentation
Other current assets						$	15.8					$	42.3
Regulatory assets						3,197.1						3,264.6
Total regulatory assets						$	3,212.9					$	3,306.9

(1)Primarily related to costs associated with the long-term service agreements our Wisconsin utilities have with Bluewater for natural gas storage services. The PSCW has approved escrow accounting for these costs. As a result, our Wisconsin utilities defer as a regulatory asset or liability the difference between actual storage costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(in millions)						September 30, 2023						December 31, 2022
Regulatory liabilities
Income tax related items						$	1,916.8					$	1,956.6
Removal costs						1,308.2						1,260.9
Pension and OPEB benefits						327.2						340.5
Energy costs refundable through rate adjustments						84.3						53.4
Derivatives						33.9						76.7
Uncollectible expense						26.9						24.0
Electric transmission costs						21.0						0.4
Decoupling						14.9						20.2
Energy efficiency programs						8.1						10.4
Other, net						48.3						48.8
Total regulatory liabilities						$	3,789.6					$	3,791.9
Balance sheet presentation
Other current liabilities						$	69.6					$	56.4
Regulatory liabilities						3,720.0						3,735.5
Total regulatory liabilities						$	3,789.6					$	3,791.9

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NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 5-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 5-8 became probable. In early 2023, we received additional approvals for electric generation facilities, including Koshkonong and 100 MWs of West Riverside. See Note 2, Acquisitions, for more information on the acquisition of West Riverside, which was completed in June 2023. OCPP Units 5 and 6 are expected to be retired by May 2024, while OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of OCPP Units 5-8 was $798.9 million at September 30, 2023, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. Columbia Units 1 and 2 are expected to be retired by June 2026. The total net book value of WPS's ownership share of Columbia Units 1 and 2 was $261.8 million at September 30, 2023, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson I Solar Energy Center LLC – Storm Damage

During a wind storm in March 2023, certain sections across approximately 40% of our Samson I solar facility incurred some amount of damage. As of September 30, 2023, we recognized an impairment of $1.6 million related to damage from this storm, which was offset by a $1.6 million receivable for future insurance recoveries. Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from this event.

NOTE 8—JOINTLY OWNED UTILITY FACILITIES

We hold joint ownership interests in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We pay our ownership share of additional construction costs and have supplied our own financing for all jointly owned projects. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. In addition, our proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. WPS owns 90%, or 82 MWs, of Red Barn.

In June 2023, WE completed the acquisition of a 13.8% ownership interest, or 100 MWs, of West Riverside, a commercially operational dual fueled combined cycle generation facility.

See Note 2, Acquisitions, for more information.

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NOTE 9—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2023, 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)						257,780
Restricted shares (2)						75,453
Performance units						157,035

(1)Stock options awarded had a weighted-average exercise price of $93.69 and a weighted-average grant date fair value of $19.58 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $93.69 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 2022 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 October 19, 2023, our Board of Directors declared a quarterly cash dividend of $0.78 per share, payable on December 1, 2023, to shareholders of record on November 14, 2023.

NOTE 10—SHORT-TERM DEBT AND LINES OF CREDIT

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

(in millions, except percentages)						September 30, 2023						December 31, 2022
Commercial paper
Amount outstanding						$	1,545.3					$	1,643.5
Weighted-average interest rate on amounts outstanding						5.46		%				4.64		%
Operating expense loans
Amount outstanding (1)						$	4.0					$	3.6

(1)Coyote Ridge Wind, LLC, Tatanka Ridge, and Jayhawk entered into operating expense loans. In accordance with their limited liability company operating agreements, they received loans from the holders of their noncontrolling interests in proportion to their ownership interests.

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2023 was $1,053.3 million with a weighted-average interest rate during the period of 5.17%.

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The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities:

(in millions)						Maturity						September 30, 2023
WEC Energy Group						September 2026						$	1,500.0
WE						September 2026						500.0
WPS						September 2026						400.0
WG						September 2026						350.0
PGL						September 2026						350.0
Total short-term credit capacity												$	3,100.0
Less:
Letters of credit issued inside credit facilities												$	2.3
Commercial paper outstanding												1,545.3
Available capacity under existing agreements												$	1,552.4

In October 2023, WEC Energy Group entered into a new $200.0 million credit facility that expires October 2024.

NOTE 11—LONG-TERM DEBT

In March 2022, President Biden signed into law the Adjustable Interest Rate (LIBOR) Act. This Act established a uniform process, on a nationwide basis, for replacing LIBOR in certain contracts that did not provide a clearly defined or practicable replacement benchmark rate. Under the LIBOR Act, the Federal Reserve Board was required to determine an appropriate benchmark replacement based on SOFR, with applicable credit spread adjustments. In December 2022, the Federal Reserve Board adopted the final rule to implement the LIBOR Act and established the SOFR-based benchmark replacements. No contract modifications were required for qualifying contracts under the LIBOR Act as the benchmark replacement automatically overrode the existing contract language and became the applicable benchmark after June 30, 2023.

For our $500.0 million of 2007 Junior Notes, starting August 15, 2023, the benchmark replacement rate is the applicable tenor of three-month CME Term SOFR, as administered by the CME Group Benchmark Administration, and includes a credit spread adjustment of 0.26161% per annum. In accordance with the LIBOR Act, no contract modifications were required for our 2007 Junior Notes as the references to LIBOR were replaced by operation of law.

WEC Energy Group, Inc.

In January 2023, we issued $650.0 million of 4.75% Senior Notes due January 9, 2026, and $450.0 million of 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other corporate purposes.

In April 2023, we issued an additional $350.0 million of our 4.75% Senior Notes due January 9, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes.

In September 2023, we issued $600.0 million of 5.60% Senior Notes due September 12, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes. Subsequently, we repaid the outstanding principal and accrued interest on our $700.0 million of 0.55% Senior Notes that matured on September 15, 2023.

Integrys Holding, Inc.

In March 2023, Integrys repurchased $18.9 million of the $221.4 million outstanding of its 6.00% 2013 Junior Notes, prior to maturity for $18.6 million. Integrys recognized an insignificant gain on the early extinguishment of debt due to the debt being repurchased at a discount.

On August 1, 2023, Integrys redeemed the remaining $202.5 million outstanding of its 6.00% 2013 Junior Notes, prior to maturity at par value.

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NOTE 12—LEASES

Obligations Under Finance Leases

Land Leases – Utility Solar Generation

WE and WPS partnered with an unaffiliated utility to acquire and construct Darien, a utility-scale solar-powered electric generating facility in Rock and Walworth counties, Wisconsin. WE and WPS own 75% and 15%, respectively, of Darien. Commercial operation of the project is targeted in 2024. Related to their investment in Darien, WE and WPS, along with their unaffiliated utility partner, entered into several land leases that commenced in the second quarter of 2023. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. Once Darien achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased. The lease payments will be recovered through rates.

Our total obligation under the land-related finance leases for Darien was $40.3 million at September 30, 2023, and was included in long-term debt on our balance sheet. Our finance lease right of use asset related to Darien was $39.2 million as of September 30, 2023, and was included in property, plant, and equipment on our balance sheet.

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the expense recognition pattern associated with the Darien leases resembles that of an operating lease. 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 on our balance sheet in accordance with Subtopic 980-842.

At September 30, 2023, our weighted-average discount rate for the Darien finance leases was 5.96%. 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 Darien as of September 30, 2023, were as follows:

(in millions)
Three Months Ended December 31, 2023						$	—
2024						0.7
2025						1.9
2026						2.0
2027						2.0
2028						2.1
Thereafter						157.7
Total minimum lease payments						166.4
Less: Interest						(126.1)
Present value of minimum lease payments						40.3
Less: Short-term lease liabilities						—
Long-term lease liabilities						$	40.3

NOTE 13—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:

(in millions)						September 30, 2023						December 31, 2022
Natural gas in storage						$	353.2					$	446.3
Materials and supplies						301.7						257.0
Fossil fuel						95.0						103.8
Total						$	749.9					$	807.1

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PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2023, all LIFO layers were replenished, and the LIFO liquidation balance was zero.

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

NOTE 14—INCOME TAXES

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

						Three Months Ended September 30, 2023												Three Months Ended September 30, 2022
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	79.0					21.0		%				$	78.9					21.0		%
State income taxes net of federal tax benefit						23.2						6.2		%				23.5						6.3		%
PTCs, net						(30.2)						(8.0)		%				(18.6)						(5.0)		%
Federal excess deferred tax amortization						(8.5)						(2.3)		%				(8.1)						(2.2)		%
Other, net						(3.1)						(0.8)		%				(2.3)						(0.5)		%
Total income tax expense						$	60.4					16.1		%				$	73.4					19.6		%
						Nine Months Ended September 30, 2023												Nine Months Ended September 30, 2022
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	272.2					21.0		%				$	298.1					21.0		%
State income taxes net of federal tax benefit						80.0						6.2		%				89.3						6.3		%
PTCs, net						(130.3)						(10.1)		%				(86.3)						(6.1)		%
Federal excess deferred tax amortization						(28.9)						(2.2)		%				(32.3)						(2.3)		%
Other, net						(10.0)						(0.8)		%				(4.9)						(0.3)		%
Total income tax expense						$	183.0					14.1		%				$	263.9					18.6		%

The effective tax rates for the three and nine months ended September 30, 2023, and 2022, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in renewable generation facilities in our non-utility energy infrastructure and Wisconsin segments and the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. These items were partially offset by state income taxes.

The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization lines above). See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information about the impact of the Tax Legislation.

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

NOTE 15—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

						September 30, 2023
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	2.4					$	10.3					$	—					$	12.7
FTRs and TCRs						—						—						11.3						11.3
Coal contracts						—						0.8						—						0.8
Total derivative assets						$	2.4					$	11.1					$	11.3					$	24.8
Investments held in rabbi trust						$	46.2					$	—					$	—					$	46.2
Derivative liabilities
Natural gas contracts						$	70.7					$	12.7					$	—					$	83.4
Coal contracts						—						25.1						—						25.1
Total derivative liabilities						$	70.7					$	37.8					$	—					$	108.5

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						December 31, 2022
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	16.3					$	16.2					$	—					$	32.5
FTRs						—						—						7.8						7.8
Coal contracts						—						34.5						—						34.5
Total derivative assets						$	16.3					$	50.7					$	7.8					$	74.8
Investments held in rabbi trust						$	50.9					$	—					$	—					$	50.9
Derivative liabilities
Natural gas contracts						$	81.4					$	15.2					$	—					$	96.6

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets and the 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 September 30, 2023 and 2022, the net unrealized losses included in earnings related to the investments held at the end of the period were $1.7 million and $2.5 million, respectively. For the nine months ended September 30, 2023, we recorded $4.7 million of net unrealized gains in earnings related to the investments held at the end of the period, compared with $15.9 million of net unrealized losses recorded during the same period in 2022.

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Balance at the beginning of the period						$	16.8					$	19.9					$	7.8					$	2.4
Purchases						0.4						0.2						19.9						22.1
Realized and unrealized net gains (losses) included in earnings (1)						0.1						(0.3)						(0.4)						1.5
Settlements						(6.0)						(7.8)						(16.0)						(14.0)
Balance at the end of the period						$	11.3					$	12.0					$	11.3					$	12.0
Unrealized net gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)						$	0.1					$	(0.2)					$	0.1					$	0.1

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

Fair Value of Financial Instruments

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

						September 30, 2023												December 31, 2022
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock of subsidiary						$	30.4					$	21.5					$	30.4					$	22.7
Long-term debt, including current portion (1)						16,517.2						14,645.0						15,464.2						13,921.3

(1)The carrying amount of long-term debt excludes finance lease obligations of $152.2 million and $183.2 million at September 30, 2023 and December 31, 2022, respectively.

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

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NOTE 16—DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.

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

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

						September 30, 2023												December 31, 2022
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	12.5					$	81.1					$	32.5					$	88.2
FTRs and TCRs						11.3						—						7.8						—
Coal contracts						0.6						13.8						18.9						—
Total current						24.4						94.9						59.2						88.2
Long-term
Natural gas contracts						0.2						2.3						—						8.4
Coal contracts						0.2						11.3						15.6						—
Total long-term						0.4						13.6						15.6						8.4
Total						$	24.8					$	108.5					$	74.8					$	96.6

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

						Three Months Ended September 30, 2023												Three Months Ended September 30, 2022
(in millions)						Volumes						Gains (Losses)						Volumes						Gains
Natural gas contracts						37.8 Dth						$	(56.3)					32.7 Dth						$	119.1
FTRs and TCRs						8.1 MWh						21.9						7.0 MWh						7.4
Total												$	(34.4)											$	126.5
						Nine Months Ended September 30, 2023												Nine Months Ended September 30, 2022
(in millions)						Volumes						Gains (Losses)						Volumes						Gains
Natural gas contracts						144.2 Dth						$	(200.7)					133.3 Dth						$	259.6
FTRs and TCRs						22.9 MWh						26.4						21.0 MWh						12.7
Total												$	(174.3)											$	272.3

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2023 and December 31, 2022, we had posted cash collateral of $118.4 million and $122.4 million, respectively. These amounts were recorded on our balance sheets as collateral on deposit.

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

						September 30, 2023												December 31, 2022
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Gross amount recognized on the balance sheet						$	24.8					$	108.5					$	74.8					$	96.6
Gross amount not offset on the balance sheet						(3.4)						(71.7)			(1)			(17.5)						(82.5)			(2)
Net amount						$	21.4					$	36.8					$	57.3					$	14.1

(1)Includes cash collateral posted of $68.3 million.

(2)Includes cash collateral posted of $65.0 million.

Cash Flow Hedges

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the three and nine months ended September 30, 2023 and 2022 were not significant. At September 30, 2023, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 17—GUARANTEES

The following table shows our outstanding guarantees:

						Total Amounts Committed at September 30, 2023						Expiration
(in millions)									Less Than 1 Year						1 to 3 Years						Over 3 Years
Standby letters of credit (1)						$	124.4					$	26.5					$	0.2					$	97.7
Surety bonds (2)						33.6						33.6						—						—
Other guarantees (3)						11.1						—						—						11.1
Total guarantees						$	169.1					$	60.1					$	0.2					$	108.8

(1)At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.

(2)Primarily for environmental remediation, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

(3)Related to workers compensation coverage for which a liability was recorded on our balance sheets.

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NOTE 18—EMPLOYEE BENEFITS

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

						Pension Benefits
						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Service cost						$	6.0					$	12.3					$	18.0					$	38.9
Interest cost						30.5						23.2						91.7						68.4
Expected return on plan assets						(46.8)						(51.6)						(140.6)						(156.8)
Loss on plan settlement						—						1.1						—						3.3
Amortization of prior service cost						—						0.4						0.1						1.2
Amortization of net actuarial loss						8.1						19.0						24.8						57.2
Net periodic benefit cost (credit)						$	(2.2)					$	4.4					$	(6.0)					$	12.2

						OPEB Benefits
						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Service cost						$	2.4					$	3.6					$	7.3					$	10.7
Interest cost						5.4						3.8						16.2						11.5
Expected return on plan assets						(13.3)						(17.2)						(39.8)						(51.7)
Amortization of prior service credit						(3.7)						(4.0)						(11.1)						(11.9)
Amortization of net actuarial gain						(3.0)						(6.2)						(9.2)						(18.5)
Net periodic benefit credit						$	(12.2)					$	(20.0)					$	(36.6)					$	(59.9)

During the nine months ended September 30, 2023, we made contributions and payments of $11.4 million related to our pension plans and $1.6 million related to our OPEB plans. We expect to make contributions and payments of $3.2 million related to our pension plans and $0.3 million related to our OPEB plans during the remainder of 2023, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of September 30, 2023, we recorded an $8.0 million regulatory asset for pension costs and an $11.1 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

NOTE 19—GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at September 30, 2023. We had no changes to the carrying amount of goodwill during the nine months ended September 30, 2023.

(in millions)						Wisconsin						Illinois						Other States						Non-Utility Energy Infrastructure						Total
Goodwill balance (1)						$	2,104.3					$	758.7					$	183.2					$	6.6					$	3,052.8

(1)We had no accumulated impairment losses related to our goodwill as of September 30, 2023.

During the third quarter of 2023, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2023. No impairments resulted from these tests.

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Intangible Assets

At September 30, 2023 and December 31, 2022, we had $29.3 million and $24.9 million, respectively, of indefinite-lived intangible assets, largely consisting of spectrum frequencies. During the nine months ended September 30, 2023, we purchased additional spectrum frequencies for $4.4 million. The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition. These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

Intangible Liabilities

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

						September 30, 2023																		December 31, 2022
(in millions)						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount
PPAs (1)						$	653.9					$	(53.4)					$	600.5					$	343.9					$	(16.9)					$	327.0
Proxy revenue swap (2)						7.2						(3.3)						3.9						7.2						(2.8)						4.4
Interconnection agreements (3)						4.7						(0.9)						3.8						4.7						(0.7)						4.0
Total intangible liabilities						$	665.8					$	(57.6)					$	608.2					$	355.8					$	(20.4)					$	335.4

(1) Represents PPAs related to the acquisition of Blooming Grove Wind Energy Center LLC , Tatanka Ridge, Jayhawk, Thunderhead, Samson I, and Sapphire Sky expiring between 2030 and 2037. The weighted-average remaining useful life of the PPAs is 12 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 five years.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 17 years.

Amortization related to these intangible liabilities for the three and nine months ended September 30, 2023, was $13.4 million and $37.2 million, respectively. Amortization for the three and nine months ended September 30, 2022, was $2.2 million and $6.5 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 2023, is estimated to be:

						For the Years Ending December 31
(in millions)						2023						2024						2025						2026						2027
Amortization to be recorded as an increase to operating revenues						$	50.4					$	53.4					$	53.4					$	53.4					$	53.4
Amortization to be recorded as a decrease to other operation and maintenance						0.2						0.2						0.2						0.2						0.2

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NOTE 20—INVESTMENT IN TRANSMISSION AFFILIATES

We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:

						Three Months Ended September 30, 2023
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,931.8					$	24.1					$	1,955.9
Add: Earnings from equity method investment						44.2						0.5						44.7
Add: Capital contributions						18.2						—						18.2
Less: Distributions						35.0						—						35.0
Balance at end of period						$	1,959.2					$	24.6					$	1,983.8
						Three Months Ended September 30, 2022
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,813.6					$	23.6					$	1,837.2
Add: Earnings from equity method investment						63.2						0.5						63.7
Add: Capital contributions						9.1						—						9.1
Less: Distributions						34.1						—						34.1
Balance at end of period						$	1,851.8					$	24.1					$	1,875.9
						Nine Months Ended September 30, 2023
(in millions)						ATC						ATC Holdco						Total
Balance at beginning of period						$	1,884.6					$	24.6					$	1,909.2
Add: Earnings from equity method investment						130.2						1.9						132.1
Add: Capital contributions						51.5						—						51.5
Less: Distributions						107.1						1.9						109.0
Balance at end of period						$	1,959.2					$	24.6					$	1,983.8
						Nine Months Ended September 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						146.8						1.6						148.4
Add: Capital contributions						39.4						—						39.4
Less: Distributions						101.3						—						101.3
Balance at end of period						$	1,851.8					$	24.1					$	1,875.9

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

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Charges to ATC for services and construction						$	4.5					$	3.9					$	12.3					$	14.8
Charges from ATC for network transmission services						94.3						90.9						283.1						272.8

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

(in millions)						September 30, 2023						December 31, 2022
Accounts receivable for services provided to ATC						$	1.8					$	1.2
Accounts payable for services received from ATC						31.6						30.4
Amounts due from ATC for transmission infrastructure upgrades (1)						46.1						26.6

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

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

						Three Months Ended September 30												Nine Months Ended September 30
(in millions)						2023						2022						2023						2022
Income statement data
Operating revenues						$	206.2					$	169.8					$	610.4					$	552.4
Operating expenses						102.8						97.7						303.4						288.4
Other expense, net						32.9						34.5						98.3						91.3
Net income						$	70.5					$	37.6					$	208.7					$	172.7

(in millions)						September 30, 2023						December 31, 2022
Balance sheet data
Current assets						$	98.7					$	89.6
Noncurrent assets						6,234.6						5,997.8
Total assets						$	6,333.3					$	6,087.4
Current liabilities						$	333.0					$	511.9
Long-term debt						2,810.7						2,613.0
Other noncurrent liabilities						589.1						485.8
Members' equity						2,600.5						2,476.7
Total liabilities and members' equity						$	6,333.3					$	6,087.4

NOTE 21—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At September 30, 2023, 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 majority interests in multiple renewable generating facilities.

See Note 2, Acquisitions, for more information on recent WECI acquisitions.

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• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark, Wisvest LLC, Wisconsin Energy Capital Corporation, and 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 nine months ended September 30, 2023 and 2022:

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

						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Three Months Ended September 30, 2022
External revenues						$	1,676.8					$	230.3					$	69.2					$	1,976.3					$	—					$	26.6					$	0.1					$	—					$	2,003.0
Intersegment revenues						—						—						—						—						—						113.3						—						(113.3)						—
Other operation and maintenance						329.1						100.2						21.0						450.3						—						12.1						(6.5)						(1.6)						454.3
Depreciation and amortization						189.2						57.9						10.3						257.4						—						34.0						6.2						(17.3)						280.3
Equity in earnings of transmission affiliates						—						—						—						—						63.7						—						—						—						63.7
Interest expense						137.2						18.1						3.3						158.6						4.9						17.0						30.9						(83.9)						127.5
Income tax expense (benefit)						63.7						5.8						(1.9)						67.6						14.3						1.7						(10.2)						—						73.4
Net income (loss)						195.2						14.9						(6.1)						204.0						44.5						70.4						(17.2)						—						301.7
Net income (loss) attributed to common shareholders						194.9						14.9						(6.1)						203.7						44.5						71.0						(17.2)						—						302.0

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

						Utility Operations
(in millions)						Wisconsin						Illinois						Other States						Total Utility Operations						Electric Transmission						Non-Utility Energy Infrastructure						Corporate and Other						Reconciling Eliminations						WEC Energy Group Consolidated
Nine Months Ended September 30, 2022
External revenues						$	5,176.5					$	1,354.8					$	410.0					$	6,941.3					$	—					$	97.3					$	0.4					$	—					$	7,039.0
Intersegment revenues						—						—						—						—						—						345.7						—						(345.7)						—
Other operation and maintenance						979.6						292.9						68.5						1,341.0						—						36.9						(13.1)						(7.1)						1,357.7
Depreciation and amortization						564.0						172.1						30.5						766.6						—						102.3						19.5						(50.4)						838.0
Equity in earnings of transmission affiliates						—						—						—						—						148.4						—						—						—						148.4
Interest expense						409.1						53.8						9.8						472.7						14.6						51.6						78.1						(252.1)						364.9
Income tax expense (benefit)						208.4						69.1						9.4						286.9						32.5						(10.5)						(45.0)						—						263.9
Net income (loss)						632.3						184.7						28.1						845.1						101.3						244.0						(32.9)						—						1,157.5
Net income (loss) attributed to common shareholders						631.4						184.7						28.1						844.2						101.3						242.8						(32.9)						—						1,155.4

NOTE 22—VARIABLE INTEREST ENTITIES

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

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

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WEPCo Environmental Trust Finance I, LLC

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

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders have no recourse to WE or any of WE's affiliates.

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

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

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

(in millions)						September 30, 2023						December 31, 2022
Assets
Other current assets (restricted cash)						$	3.9					$	3.0
Regulatory assets						87.5						92.4
Other long-term assets (restricted cash)						0.6						0.6
Liabilities
Current portion of long-term debt						9.0						8.9
Other current liabilities (accrued interest)						0.5						0.1
Long-term debt						89.8						94.1

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At September 30, 2023 and December 31, 2022, our equity investment in ATC was $1,959.2 million and $1,884.6 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 both September 30, 2023 and December 31, 2022, our equity investment in ATC Holdco was $24.6 million, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 20, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

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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. This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023. See Note 2, Acquisitions, for more information on the acquisition of this facility. The tolling agreement represented a variable interest until the facility was acquired since its terms were substantially similar to the terms of the PPA. Based on the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, we were not the primary beneficiary of the entity. We did not hold an equity or debt interest in the entity, and there was no residual guarantee associated with the tolling agreement. Similar to the PPA, we accounted for the tolling agreement as a finance lease.

NOTE 23—COMMITMENTS AND CONTINGENCIES

We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

The renewable generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. In order to support these sales obligations, these companies enter into easements and other service agreements associated with the generating facilities.

Our minimum future commitments related to these purchase obligations as of September 30, 2023, including those of our subsidiaries, were approximately $9.9 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

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

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

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Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu. Adoption of either of these lower limits could have an adverse effect on our utilities.

National Ambient Air Quality Standards

Ozone

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

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

In April 2022, the EPA proposed to find that the Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and should be adjusted to "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

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 PM and determined that no revisions were necessary to the current annual standard of 12 µg/m3 or the 24-hour standard of 35 µg/m3. 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 PM NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard. In January 2023, the EPA announced its proposed decision to revise the primary (health-based) annual PM2.5 standard from its current level of 12 µg/m3 to within the range of 9 to 10 µg/m3. The EPA also proposed not to change the current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards. The EPA did, however, take comments on the full range (between 8 and 11 µg/m3) included in the CASAC's latest report. 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/m3, our generating facilities within our service territories should remain in attainment. If the EPA lowers it to below 10 µg/m3, there could be some nonattainment areas that may affect permitting of some smaller ancillary equipment located at our facilities. After finalization of the rule, the WDNR will need to draft and submit a SIP for the EPA's approval. A final rule is anticipated in late 2023 or early 2024.

Climate Change

In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which replaced the Clean Power Plan. For coal plants, there are no applicable standards until 2032, and after 2032 the applicable standard is dependent on the unit's retirement date. For combined cycle natural gas plants above a 50% capacity factor, the rule is highly dependent on hydrogen as an alternative fuel, or carbon capture. For simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our RICE units in Michigan and the new Weston RICE project are not affected under the rule because each RICE unit is less than 25 MWs. We are evaluating the proposed rule to understand the impacts to our operations.

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In May 2023, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units. New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load. Our RICE units are not affected by this rule since each unit is below 25 MWs. Our ESG Progress Plan is heavily focused on reducing GHG emissions. The EPA has indicated that it anticipates a final rule in the second quarter of 2024.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, in June 2022. In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The proposed revisions could impact the reporting required for our electric generation facilities, local natural gas distribution companies, and underground natural gas storage facilities. In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024. We are currently evaluating the potential impact of the proposed rule, if any, on our operations.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018. Through our ESG Progress Plan, we expect to retire approximately 1,500 MWs 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 and 2. See Note 7, Property, Plant, and Equipment, 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 CO2 emissions by 2050.

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

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

We have received a final BTA determination for Valley power plant. We have received interim BTA determinations for OCPP Units 5-8 and Weston Units 3 and 4. We 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 at the OCPP 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 expected in January 2024.

The WDNR reissued the WPDES permit for PWGS effective October 2023. This reissued permit includes a conditional BTA determination with conditions for the existing PWGS porous dike (rock breakwater) cooling water intake structure. We do not anticipate compliance with these conditions will result in a material impact on our financial condition or results of operations.

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Steam Electric Effluent Limitation Guidelines

The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater. Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications are necessary to meet the ELG rule requirements. Through 2023, we expect that compliance costs associated with the ELG rule will require $105 million in capital investment. An $8 million BATW modification to OC 7 and OC 8 was completed and placed in-service in mid-2021, and in December 2021, the PSCW issued a Certificate of Authority approving the $89 million ERGS FGD wastewater treatment system modification. The BATW modifications, including $8 million of modifications at Weston Unit 3 completed in June 2023, did 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 deadlines in December 2023.

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

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule. Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032. Although the $89 million biological treatment system at ERGS is 99% complete and on track for completion before year-end to meet the WPDES permit deadline, the timing of the project's completion would not comply with the deadline proposed by the EPA to qualify for the early adopter status. In addition, we do not believe that, upon its completion, the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed. In May 2023, we submitted written comments to the EPA articulating these concerns, including the cost impact to our customers. The EPA has indicated that it is anticipating the rule to be final in the second quarter of 2024.

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

The EPA also proposed requirements for legacy wastewaters and landfill leachate. We are reviewing those proposed requirements to determine potential costs and actions required for our facilities.

Waters of the United States

In January 2023, the EPA and the Army Corps (the agencies) together released a final rule effective in March 2023, that based the definition of WOTUS on its pre-2015 definition. The pre-2015 approach involved applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

In May 2023, in Sackett v. EPA, the Supreme Court issued a decision significantly narrowing federal jurisdiction over wetlands to "traditional navigable waters" and wetlands or other waters that have a "continuous surface connection" with a traditional navigable water.

In August 2023, the agencies revised the final rule to conform the definition of WOTUS to the Supreme Court's May 2023 Sackett decision. The conforming rule became effective upon publication in the Federal Register on September 8, 2023.

We anticipate this final rule revision caused by the Sackett decision will cause a decrease in the number of projects that require Army Corps federal wetland permits. This decision also may affect the administration of some state programs. At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts.

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Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves for manufactured gas plant sites:

(in millions)						September 30, 2023						December 31, 2022
Regulatory assets						$	577.7					$	610.7
Reserves for future environmental remediation						456.6						499.6

Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to all landfills, historic fill sites, and projects where CCR was placed. As proposed, the rule would regulate previously exempt closed landfills and would include sites we own as well as several third party owned properties.

We are actively engaged with the Utility Solid Waste Activities Group and the EEI and provided them information to include in their comments to the EPA. The EPA has indicated that it is anticipating the rule to be final in the second quarter of 2024. The proposed rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs.

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 begin later in 2023.

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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 started the process in early 2023 to close out this Consent Decree.

NOTE 24—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions

						Nine Months Ended September 30
(in millions)						2023						2022
Cash paid for interest, net of amount capitalized						$	432.9					$	311.4
Cash paid for income taxes, net						15.8						52.3
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						236.5						170.9
Accounts payable related to Thunderhead acquisition milestone payments						—						19.0
Increase in receivables related to insurance proceeds						6.2						—
Liabilities accrued for software licensing agreement						—						7.4

Restricted Cash

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

(in millions)						September 30, 2023						December 31, 2022
Cash and cash equivalents						$	45.9					$	28.9
Restricted cash included in other current assets						43.6						25.6
Restricted cash included in other long-term assets						51.9						127.7
Cash, cash equivalents, and restricted cash						$	141.4					$	182.2

Our restricted cash consisted of the following:

• Cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments.

• Cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEC Infrastructure Wind Holding I LLC, WECI Wind Holding II, and WEPCo Environmental Trust.

• Cash we received when WECI acquired ownership interests in certain renewable generation projects. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the renewable generation facilities.

• Cash used by WE and WPS during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin. This cash was included in other long-term assets at December 31, 2022. See Note 2, Acquisitions, for more information on the purchase of this facility.

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NOTE 25—REGULATORY ENVIRONMENT

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

2024 Limited Rate Case Re-Opener

In accordance with their rate orders approved by the PSCW in December 2022, WE, WPS, and WG filed requests for limited electric and natural gas rate case re-openers, as applicable, with the PSCW in May 2023. The limited electric rate case re-openers filed by WE and WPS include updated revenue requirements for the generation projects that were previously approved by the PSCW and are expected to be placed into service in 2023 and 2024. WE's limited electric re-opener also includes the projected savings from the retirement of the OCPP Units 5 and 6, which are expected to be retired in May 2024. WE and WG also filed a request for a limited natural gas rate case re-opener to reflect the additional revenue requirements associated with their previously approved LNG projects that are expected to be placed into service in 2023 and 2024, respectively.

The requested increases in 2024 base rates are as follows:

						WE												WPS												WG
Requested 2024 base rate increases
Electric						$	45.0	million	/			1.3%						$	8.6	million	/			0.5%						N/A
Gas						$	23.9	million	/			4.5%						N/A												$	22.2	million	/			2.9%

The utilities' ROE and common equity component averages will not be addressed in the limited rate case re-openers. A PSCW decision is expected in the fourth quarter of 2023, with new rates expected to be effective January 1, 2024.

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

2023 Rate Case

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas rates. They are requesting incremental rate increases of $194.7 million (13.0%) and $18.7 million (7.8%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL is also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service.

Both companies are requesting an ROE of 9.90% and a common equity component average of 54.0%. PGL is not seeking an extension of the QIP rider. Instead, PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements. See the Qualifying Infrastructure Plant Rider section below for more information on the QIP rider.

An ICC decision is anticipated in the fourth quarter of 2023, with any rate adjustments expected to be effective January 1, 2024.

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 will not seek an extension of the rider beyond 2023.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending.

As of September 30, 2023, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2022, will be deemed recoverable by the ICC.

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Minnesota Energy Resources Corporation

2023 Rate Case

In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates by $40.3 million (9.9%). MERC's request reflected a 10.3% ROE and a common equity component average of 53.0%. The proposed retail natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs. In December 2022, the MPUC approved MERC's request for interim rates totaling $37.0 million, subject to refund. The interim rates went into effect on January 1, 2023.

On October 26, 2023, the MPUC verbally approved a settlement agreement MERC reached with certain intervenors. The settlement agreement reflects a natural gas base rate increase of $28.8 million (7.1%), along with a 9.65% ROE and a common equity component average of 53.0%. Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers. A final written order is expected by the end of 2023, with final rates expected to be implemented in the first quarter of 2024. MERC’s customers will be entitled to a refund to the extent the interim rate increase exceeds the final approved rate increase. These refunds are also expected to occur during the first quarter of 2024.

Michigan Gas Utilities Corporation

2023 Rate Order

In March 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates. On August 30, 2023, the MPSC issued a written order approving a comprehensive settlement that resolved all issues in MGU's rate case. The key terms of the settlement agreement include:

• a natural gas base rate increase of $9.9 million (4.7%);

• an ROE of 9.8%;

• a common equity component average of 51%; and,

• a continuation of the existing MRP rider, effective January 1, 2025 through 2027, including forecasted increased costs for those projects. MRP costs will be recovered in base rates in 2024.

The rate increase was primarily driven by capital investments made to strengthen the safety and reliability of MGU's natural gas distribution system and to provide service to additional customers. Inflationary pressure on operating costs also contributed to the rate increase. The new rates will be effective January 1, 2024.

NOTE 26—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 and in January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other interbank offered rates to alternative reference rates. These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic. Our $500.0 million 2007 Junior Notes, which were previously subject to a variable rate based on U.S. dollar LIBOR, became subject to a variable rate based on SOFR beginning July 1, 2023. No contract modifications were required as the references to LIBOR were replaced by operation of law. See Note 11, Long-Term Debt, for more information. We do not anticipate this guidance having a significant impact on our financial statements and related disclosures.

09/30/2023 Form 10-Q			42			WEC Energy Group, Inc.

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