Item 1. FINANCIAL STATEMENTS

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Item 1. FINANCIAL STATEMENTS

WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)		Three Months Ended
	March 31
(in millions, except per share amounts)			2023		2022
Operating revenues			$	2,888.1	$	2,908.1

Operating expenses
Cost of sales			1,309.7		1,383.4
Other operation and maintenance			534.0		454.4
Depreciation and amortization			305.5		278.1
Property and revenue taxes			69.6		60.8
Total operating expenses			2,218.8		2,176.7

Operating income			669.3		731.4

Equity in earnings of transmission affiliates			43.8		41.7
Other income, net			40.8		39.6
Interest expense			172.2		117.6
Other expense			(87.6)		(36.3)

Income before income taxes			581.7		695.1
Income tax expense			74.1		127.1
Net income			507.6		568.0

Preferred stock dividends of subsidiary			0.3		0.3
Net loss (income) attributed to noncontrolling interests			0.2		(1.8)
Net income attributed to common shareholders			$	507.5	$	565.9

Earnings per share
Basic			$	1.61	$	1.79
Diluted			$	1.61	$	1.79

Weighted average common shares outstanding
Basic			315.4		315.4
Diluted			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
	March 31
(in millions)			2023		2022
Net income			$	507.6	$	568.0

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)		(0.1)

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)		—

Comprehensive income			507.5		568.0

Preferred stock dividends of subsidiary			0.3		0.3
Comprehensive loss (income) attributed to noncontrolling interests			0.2		(1.8)
Comprehensive income attributed to common shareholders			$	507.4	$	565.9

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


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WEC ENERGY GROUP, INC.


CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2023		December 31, 2022
Assets
Current assets
Cash and cash equivalents	$	35.7	$	28.9
Accounts receivable and unbilled revenues, net of reserves of $213.8 and $199.3, respectively	1,780.6		1,818.4
Materials, supplies, and inventories	523.5		807.1
Prepaid taxes	153.0		201.8
Other prepayments	64.9		69.8
Collateral on deposit	214.2		122.4
Other	66.6		139.3
Current assets	2,838.5		3,187.7

Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $10,532.3 and $10,383.8, respectively	30,379.4		29,113.8
Regulatory assets (March 31, 2023 and December 31, 2022 include $90.9 and $92.4, respectively, related to WEPCo Environmental Trust)	3,313.1		3,264.6
Equity investment in transmission affiliates	1,921.7		1,909.2
Goodwill	3,052.8		3,052.8
Pension and OPEB assets	933.4		916.7
Other	357.0		427.3
Long-term assets	39,957.4		38,684.4
Total assets	$	42,795.9	$	41,872.1

Liabilities and Equity
Current liabilities
Short-term debt	$	1,261.2	$	1,647.1
Current portion of long-term debt (March 31, 2023 and December 31, 2022 each include $8.9 related to WEPCo Environmental Trust)	808.2		881.2
Accounts payable	680.0		1,198.1
Other	1,016.4		884.6
Current liabilities	3,765.8		4,611.0

Long-term liabilities
Long-term debt (March 31, 2023 and December 31, 2022 each include $94.1 related to WEPCo Environmental Trust)	15,827.3		14,766.2
Deferred income taxes	4,703.2		4,625.6
Deferred revenue, net	367.0		370.7
Regulatory liabilities	3,689.8		3,735.5
Environmental remediation liabilities	491.7		499.6
Pension and OPEB obligations	168.5		171.6
Other	1,794.9		1,475.3
Long-term liabilities	27,042.4		25,644.5

Commitments and contingencies (Note 20)

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	4,113.6		4,115.2
Retained earnings	7,526.7		7,265.3
Accumulated other comprehensive loss	(6.9)		(6.8)
Common shareholders' equity	11,636.6		11,376.9

Preferred stock of subsidiary	30.4		30.4
Noncontrolling interests	320.7		209.3
Total liabilities and equity	$	42,795.9	$	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)	Three Months Ended
	March 31
(in millions)	2023		2022
Operating activities
Net income	$	507.6	$	568.0
Reconciliation to cash provided by operating activities
Depreciation and amortization	305.5		278.1
Deferred income taxes and ITCs, net	56.5		103.8
Contributions and payments related to pension and OPEB plans	(5.5)		(3.6)
Equity income in transmission affiliates, net of distributions	(6.4)		(7.7)
Change in –
Accounts receivable and unbilled revenues, net	60.7		(174.3)
Materials, supplies, and inventories	293.6		267.0
Prepaid taxes	48.8		62.5
Collateral on deposit	(91.8)		0.2
Other current assets	40.6		21.3
Accounts payable	(424.7)		(293.8)
Temporary LIFO liquidation credit	43.8		130.7
Collateral received	—		132.5
Other current liabilities	19.9		26.3
Other, net	(52.5)		(34.2)
Net cash provided by operating activities	796.1		1,076.8

Investing activities
Capital expenditures	(499.4)		(383.5)
Acquisition of Whitewater	(76.0)		—
Acquisition of Sapphire Sky, net of cash acquired of $0.3	(442.6)		—
Acquisition of Samson I, net of cash acquired of $5.2	(249.4)		—
Capital contributions to transmission affiliates	(6.1)		(21.1)
Proceeds from the sale of assets	4.6		9.7
Proceeds from the sale of investments held in rabbi trust	10.4		15.4
Insurance proceeds received for property damage	—		41.0
Other, net	(9.4)		0.3
Net cash used in investing activities	(1,267.9)		(338.2)

Financing activities
Exercise of stock options	0.9		11.8
Purchase of common stock	(6.9)		(23.4)
Dividends paid on common stock	(246.1)		(229.6)
Issuance of long-term debt	1,100.0		—
Retirement of long-term debt	(35.2)		(15.4)
Change in commercial paper	(385.4)		(447.9)
Payments for debt issuance costs	(7.0)		(0.8)
Other, net	(2.7)		(1.2)
Net cash provided by (used in) financing activities	417.6		(706.5)

Net change in cash, cash equivalents, and restricted cash	(54.2)		32.1
Cash, cash equivalents, and restricted cash at beginning of period	182.2		87.5
Cash, cash equivalents, and restricted cash at end of period	$	128.0	$	119.6

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




	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

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


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WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 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 17, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 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 months ended March 31, 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 an asset acquisition. The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs. See Note 16, Goodwill and Intangibles, for more information.

Acquisitions of Electric Generation Facilities in Wisconsin

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 approximately $160 million. Red Barn qualifies for PTCs.

In February 2023, WPS, along with an unaffiliated entity, received approval from the PSCW to acquire 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises. WPS also received approval to transfer its ownership interest to WE. The transaction is expected to close during the second quarter of 2023, and WE's investment is expected to be approximately $102 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin.

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.


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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 approximately $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.

Acquisitions of Electric Generation Facilities 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 approximately $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 in early 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.

Acquisition of Wind Generation Facility in Nebraska

In September 2022, WECI completed the acquisition of a 90% ownership interest in Thunderhead, a commercially operational 300 MW wind generating facility in Antelope and Wheeler counties in Nebraska. The purchase price was $382.0 million, which includes transaction costs and is net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years. Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment.

NOTE 3—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 March 31, 2023
Electric	$	1,203.8	$	—	$	—	$	1,203.8	$	—	$	—	$	—		$	1,203.8
Natural gas	784.4		577.7		245.0		1,607.1		21.3		—		(21.1)			1,607.3
Total regulated revenues	1,988.2		577.7		245.0		2,810.9		21.3		—		(21.1)			2,811.1
Other non-utility revenues	—		—		5.2		5.2		43.5		—		(1.6)			47.1
Total revenues from contracts with customers	1,988.2		577.7		250.2		2,816.1		64.8		—		(22.7)			2,858.2
Other operating revenues	8.1		22.0		(0.2)		29.9		101.4		—		(101.4)		(1)	29.9
Total operating revenues	$	1,996.3	$	599.7	$	250.0	$	2,846.0	$	166.2	$	—	$	(124.1)		$	2,888.1


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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
Three Months Ended March 31, 2022
Electric	$	1,187.5	$	—	$	—	$	1,187.5	$	—	$	—	$	—		$	1,187.5
Natural gas	746.8		679.9		238.2		1,664.9		15.3		—		(14.8)			1,665.4
Total regulated revenues	1,934.3		679.9		238.2		2,852.4		15.3		—		(14.8)			2,852.9
Other non-utility revenues	—		—		4.6		4.6		43.7		—		(1.6)			46.7
Total revenues from contracts with customers	1,934.3		679.9		242.8		2,857.0		59.0		—		(16.4)			2,899.6
Other operating revenues	8.0		2.2		(1.9)		8.3		100.5		0.2		(100.5)		(1)	8.5
Total operating revenues	$	1,942.3	$	682.1	$	240.9	$	2,865.3	$	159.5	$	0.2	$	(116.9)		$	2,908.1

(1)Amounts eliminated represent lease revenues related to certain plants that We Power leases to WE to supply electricity to its customers. Lease payments are billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW and the FERC. WE operates the plants and is authorized by the PSCW and Wisconsin state law to fully recover prudently incurred operating and maintenance costs in electric rates.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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


	Three Months Ended March 31
(in millions)	2023		2022
Residential	$	486.5	$	463.1
Small commercial and industrial	393.6		370.1
Large commercial and industrial	229.8		229.2
Other	8.0		7.8
Total retail revenues	1,117.9		1,070.2
Wholesale	34.2		42.4
Resale	40.6		56.8
Steam	11.0		12.1
Other utility revenues	0.1		6.0
Total electric utility operating revenues	$	1,203.8	$	1,187.5

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 March 31, 2023
Residential	$	554.8	$	368.9	$	164.5	$	1,088.2
Commercial and industrial	295.2		117.9		91.5		504.6
Total retail revenues	850.0		486.8		256.0		1,592.8
Transportation	28.9		76.6		10.9		116.4
Other utility revenues (1) (2)	(94.5)		14.3		(21.9)		(102.1)
Total natural gas utility operating revenues	$	784.4	$	577.7	$	245.0	$	1,607.1


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(in millions)	Wisconsin		Illinois		Other States		Total Natural Gas Utility Operating Revenues
Three Months Ended March 31, 2022
Residential	$	502.5	$	465.5	$	161.3	$	1,129.3
Commercial and industrial	272.5		158.3		86.8		517.6
Total retail revenues	775.0		623.8		248.1		1,646.9
Transportation	25.5		80.9		13.9		120.3
Other utility revenues (1) (3)	(53.7)		(24.8)		(23.8)		(102.3)
Total natural gas utility operating revenues	$	746.8	$	679.9	$	238.2	$	1,664.9

(1)Includes the revenues subject to the purchased gas recovery mechanisms of our utilities.

(2)During the first quarter of 2023, we over-collected natural gas costs at our Wisconsin segment due to these costs being lower than what was anticipated in rates. We also continued to recover higher natural gas costs we under-collected from customers in prior periods at our Other States segments. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues. The positive amount at our Illinois segment reflects a decrease in natural gas costs during the first quarter of 2023, compared to what was anticipated in rates.

(3)During the first quarter of 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2021. As these amounts are billed to our customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.

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 March 31
(in millions)	2023		2022
Wind generation revenues	$	36.0	$	36.2
We Power revenues (1)	5.9		5.9
Appliance service revenues	5.2		4.6


Total other non-utility operating revenues	$	47.1	$	46.7

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

Other Operating Revenues

Other operating revenues consist primarily of the following:


	Three Months Ended March 31
(in millions)	2023		2022
Late payment charges	$	17.2	$	13.6
Alternative revenues (1)	11.8		(6.0)
Other	0.9		0.9
Total other operating revenues	$	29.9	$	8.5


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(1)Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges.

NOTE 4—CREDIT LOSSES

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

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

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

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

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at March 31, 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
March 31, 2023
Accounts receivable and unbilled revenues	$	1,232.2		$	561.0		$	143.5		$	1,936.7		$	50.0		$	7.7		$	1,994.4
Allowance for credit losses	90.9			116.5			6.4			213.8			—			—			213.8
Accounts receivable and unbilled revenues, net (1)	$	1,141.3		$	444.5		$	137.1		$	1,722.9		$	50.0		$	7.7		$	1,780.6

Total accounts receivable, net – past due greater than 90 days (1)	$	67.9		$	61.6		$	1.7		$	131.2		$	—		$	—		$	131.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)	97.5		%	100.0		%	—		%	97.4		%	—		%	—		%	97.4		%


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(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 March 31, 2023, $1,119.8 million, or 62.9%, 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:


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

On a consolidated basis, there was a $14.5 million increase in the allowance for credit losses at March 31, 2023, compared to January 1, 2023, driven by an increase in past due accounts receivable balances at our Wisconsin and Illinois reportable segments. An increase in past due balances is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15, and in Illinois the winter moratorium begins on December 1 and ends on March 31.


(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	11.8		11.3		0.2		23.3
Provision for credit losses deferred for future recovery or refund	8.8		12.1		—		20.9
Write-offs charged against the allowance	(28.8)		(27.3)		(1.4)		(57.5)
Recoveries of amounts previously written off	9.9		5.4		0.3		15.6
Balance at March 31, 2022	$	85.7	$	107.0	$	7.9	$	200.6

On a consolidated basis, there was a $2.3 million increase in the allowance for credit losses at March 31, 2022, compared to January 1, 2022, driven by an increase in past due accounts receivable balances at our Wisconsin and Illinois reportable segments. We believe that the higher year-over-year energy costs that customers were seeing, which were driven by high natural gas prices, contributed to the higher past due accounts receivable balances. As discussed above, an increase in past due balances is also a trend we generally see over the winter moratorium months.


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NOTE 5—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 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)	March 31, 2023		December 31, 2022
Regulatory assets
Pension and OPEB costs	$	701.9	$	714.3
Plant retirement related items	677.9		688.6
Environmental remediation costs	590.6		610.7
Income tax related items	457.5		461.9
Derivatives	196.5		133.8
Asset retirement obligations	171.1		169.7
System support resource	120.9		123.5
Uncollectible expense	95.9		69.3
Securitization	90.9		92.4
Bluewater (1)	31.4		20.9
Energy efficiency programs	30.0		33.9
MERC extraordinary natural gas costs	21.2		35.1
Other, net	139.5		152.8
Total regulatory assets	$	3,325.3	$	3,306.9

Balance sheet presentation
Other current assets	$	12.2	$	42.3
Regulatory assets	3,313.1		3,264.6
Total regulatory assets	$	3,325.3	$	3,306.9

(1)Primarily related to costs associated with the long-term service agreement 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)	March 31, 2023		December 31, 2022
Regulatory liabilities
Income tax related items	$	1,945.4	$	1,956.6
Removal costs	1,279.3		1,260.9
Pension and OPEB benefits	335.3		340.5
Energy costs refundable through rate adjustments (1)	138.5		53.4
Derivatives	21.6		76.7
Decoupling	21.1		20.2
Uncollectible expense	20.1		24.0
Energy efficiency programs	18.5		10.4
Other, net	55.0		49.2
Total regulatory liabilities	$	3,834.8	$	3,791.9

Balance sheet presentation
Other current liabilities	$	145.0	$	56.4
Regulatory liabilities	3,689.8		3,735.5
Total regulatory liabilities	$	3,834.8	$	3,791.9

(1)The increase in these regulatory liabilities was primarily due to lower natural gas costs incurred during the first quarter of 2023, compared to what was anticipated in rates.


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NOTE 6—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 5 – 8

As a result of a PSCW approval for the construction of a solar and battery project received in December 2022, retirement of the OCPP generating units 5 – 8 became probable. In early 2023, we received additional approvals for electric generation facilities, including West Riverside and the Koshkonong Solar-Battery Park. OCPP units 5 and 6 are expected to be retired by May 2024, while units 7 and 8 are expected to be retired by late 2025. The total net book value of WE's ownership share of units 5 – 8 was $812.9 million at March 31, 2023, which does not include deferred taxes. These amounts were 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 generating units 1 and 2 became probable. Columbia generating units 1 and 2 are expected to be retired by June 2026. The total net book value of WPS's ownership share of units 1 and 2 was $268.7 million at March 31, 2023, which does not include deferred taxes. These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheets. These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

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. In the first quarter of 2023, we recognized an impairment of $21.4 million related to damage from this storm, which was substantially offset by a $20.7 million receivable for future insurance recoveries. In the first quarter of 2023, the net impact of these amounts, or $0.7 million, was recorded in other operation and maintenance expense. A full damage assessment is still underway, but based on current damage and repair estimates, we do not currently expect a significant impact to our future results of operations. Although we may experience differences between periods in the timing of cash flows, we also do not currently expect a significant impact to our long-term cash flows from this event.

NOTE 7—COMMON EQUITY

Stock-Based Compensation

During the three months ended March 31, 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


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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 April 20, 2023, our Board of Directors declared a quarterly cash dividend of $0.78 per share, payable on June 1, 2023, to shareholders of record on May 12, 2023.

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

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


(in millions, except percentages)	March 31, 2023			December 31, 2022
Commercial paper
Amount outstanding	$	1,258.1		$	1,643.5
Weighted-average interest rate on amounts outstanding	5.16		%	4.64		%
Operating expense loans
Amount outstanding (1)	$	3.1		$	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 three months ended March 31, 2023 was $992.4 million with a weighted-average interest rate during the period of 4.84%.

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


(in millions)	Maturity	March 31, 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		1,258.1
Available capacity under existing agreements		$	1,839.6

NOTE 9—LONG-TERM DEBT

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.


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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.

NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:


(in millions)	March 31, 2023		December 31, 2022
Materials and supplies	$	276.6	$	257.0
Natural gas in storage	137.0		446.3
Fossil fuel	109.9		103.8
Total	$	523.5	$	807.1

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At March 31, 2023, we had a temporary LIFO liquidation credit of $43.8 million recorded within other current liabilities on our balance sheet. Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end.

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

NOTE 11—INCOME TAXES

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


























	Three Months Ended March 31, 2023				Three Months Ended March 31, 2022
(in millions)	Amount		Effective Tax Rate		Amount		Effective Tax Rate
Statutory federal income tax	$	122.1	21.0	%	$	145.5	21.0	%
State income taxes net of federal tax benefit	35.8		6.2	%	43.6		6.3	%
PTCs	(66.2)		(11.4)	%	(44.8)		(6.5)	%
Federal excess deferred tax amortization	(13.1)		(2.3)	%	(15.8)		(2.3)	%



Other, net	(4.5)		(0.8)	%	(1.4)		(0.2)	%
Total income tax expense	$	74.1	12.7	%	$	127.1	18.3	%

The effective tax rates of 12.7% and 18.3% for the three months ended March 31, 2023, and 2022, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to PTCs generated from ownership interests in renewable generation facilities in our non-utility energy infrastructure and Wisconsin segments and the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. These items were partially offset by state income taxes.

The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above).

See Note 26, Regulatory Environment, in our 2022 Annual Report on Form 10-K for more information about the impact of the Tax Legislation.


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NOTE 12—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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


	March 31, 2023
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	2.5	$	—	$	3.0
FTRs	—		—		3.0		3.0
Coal contracts	—		1.7		—		1.7
Total derivative assets	$	0.5	$	4.2	$	3.0	$	7.7

Investments held in rabbi trust	$	44.0	$	—	$	—	$	44.0

Derivative liabilities
Natural gas contracts	$	153.5	$	1.6	$	—	$	155.1
Coal contracts	—		14.7		—		14.7
Total derivative liabilities	$	153.5	$	16.3	$	—	$	169.8


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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, 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. During the first quarter of 2023, we also held TCRs, which were used at certain of our non-utility wind parks to manage electric transmission congestion costs in the SPP Integrated Marketplace, but these TCRs settled prior to March 31, 2023.

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. For the three months ended March 31, 2023, we recorded $2.8 million of net unrealized gains in earnings related to the investments held at the end of the period, compared with $3.3 million of net unrealized losses recorded during the same quarter in 2022.

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


	Three Months Ended March 31
(in millions)	2023		2022
Balance at the beginning of the period	$	7.8	$	2.4
Purchases	0.3		—
Realized and unrealized net losses included in earnings (1)	(0.3)		—
Settlements	(4.8)		(1.4)
Balance at the end of the period	$	3.0	$	1.0
Unrealized net losses included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)	$	(0.1)	$	—

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

Fair Value of Financial Instruments

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


	March 31, 2023				December 31, 2022
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock of subsidiary	$	30.4	$	23.1	$	30.4	$	22.7
Long-term debt, including current portion (1)	16,524.7		15,349.3		15,464.2		13,921.3

(1)The carrying amount of long-term debt excludes finance lease obligations of $110.8 million and $183.2 million at March 31, 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 13—DERIVATIVE INSTRUMENTS

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

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

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


	March 31, 2023				December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Current
Natural gas contracts	$	2.7	$	147.3	$	32.5	$	88.2
FTRs	3.0		—		7.8		—
Coal contracts	1.3		9.2		18.9		—
Total current	7.0		156.5		59.2		88.2

Long-term
Natural gas contracts	0.3		7.8		—		8.4
Coal contracts	0.4		5.5		15.6		—
Total long-term	0.7		13.3		15.6		8.4
Total	$	7.7	$	169.8	$	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 March 31, 2023			Three Months Ended March 31, 2022
(in millions)	Volumes	Gains (Losses)		Volumes	Gains
Natural gas contracts	58.7 Dth	$	(75.3)	59.5 Dth	$	31.6
FTRs and TCRs	7.3 MWh	0.4		7.0 MWh	1.0
Total		$	(74.9)		$	32.6

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2023 and December 31, 2022, we had posted cash collateral of $214.2 million and $122.4 million, respectively. These amounts were recorded on our balance sheets in 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:


	March 31, 2023					December 31, 2022
(in millions)	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Gross amount recognized on the balance sheet	$	7.7	$	169.8		$	74.8	$	96.6
Gross amount not offset on the balance sheet	(0.7)		(153.7)		(1)	(17.5)		(82.5)		(2)
Net amount	$	7.0	$	16.1		$	57.3	$	14.1

(1)Includes cash collateral posted of $153.0 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 months ended March 31, 2023 and 2022 were not significant. At March 31, 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 14—GUARANTEES

The following table shows our outstanding guarantees:


	Total Amounts Committed at March 31, 2023			Expiration

(in millions)			Less Than 1 Year			1 to 3 Years			Over 3 Years
Standby letters of credit (1)	$	116.3		$	9.5		$	0.2		$	106.6
Surety bonds (2)	33.8			33.7			0.1			—
Other guarantees (3)	9.7			—			—			9.7
Total guarantees	$	159.8		$	43.2		$	0.3		$	116.3

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

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

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

NOTE 15—EMPLOYEE BENEFITS

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


	Pension Benefits
	Three Months Ended March 31
(in millions)	2023		2022
Service cost	$	6.6	$	12.4
Interest cost	30.8		22.8
Expected return on plan assets	(47.4)		(52.7)

Amortization of prior service cost	0.1		0.4
Amortization of net actuarial loss	7.4		19.1
Net periodic benefit cost (credit)	$	(2.5)	$	2.0


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	OPEB Benefits
	Three Months Ended March 31
(in millions)	2023		2022
Service cost	$	2.5	$	3.8
Interest cost	5.4		3.9
Expected return on plan assets	(13.3)		(17.2)

Amortization of prior service credit	(3.7)		(4.0)
Amortization of net actuarial gain	(3.2)		(6.0)
Net periodic benefit credit	$	(12.3)	$	(19.5)

During the three months ended March 31, 2023, we made contributions and payments of $4.9 million related to our pension plans and $0.6 million related to our OPEB plans. We expect to make contributions and payments of $9.6 million related to our pension plans and $1.5 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 March 31, 2023, we recorded a $2.1 million regulatory asset for pension costs and a $3.7 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

NOTE 16—GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at March 31, 2023. We had no changes to the carrying amount of goodwill during the three months ended March 31, 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 March 31, 2023.

Intangible Assets

At March 31, 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 first quarter of 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 and are classified as other long-term liabilities on our balance sheets.


	March 31, 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	$	(27.1)	$	626.8	$	343.9	$	(16.9)	$	327.0
Proxy revenue swap (2)	7.2		(2.9)		4.3		7.2		(2.8)		4.4
Interconnection agreements (3)	4.7		(0.8)		3.9		4.7		(0.7)		4.0
Total intangible liabilities	$	665.8	$	(30.8)	$	635.0	$	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.


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(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 six 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 18 years.

Amortization related to these intangible liabilities for the three months ended March 31, 2023, and 2022, was $10.4 million and $2.2 million, respectively. Amortization for the next five years, including amounts recorded through March 31, 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

NOTE 17—INVESTMENT IN TRANSMISSION AFFILIATES

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






















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

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

	Three Months Ended March 31, 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	41.0		0.7		41.7
Add: Capital contributions	21.1		—		21.1
Less: Distributions	34.0		—		34.0


Balance at end of period	$	1,795.0	$	23.2	$	1,818.2

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 March 31
(in millions)		2023		2022
Charges to ATC for services and construction		$	3.8	$	6.2
Charges from ATC for network transmission services		94.5		91.1


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


(in millions)	March 31, 2023		December 31, 2022
Accounts receivable for services provided to ATC	$	1.5	$	1.2

Accounts payable for services received from ATC	31.5		30.4
Amounts due from ATC for transmission infrastructure upgrades (1)	29.3		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 March 31
(in millions)		2023		2022
Income statement data
Operating revenues		$	200.4	$	191.0
Operating expenses		99.1		95.5
Other expense, net		32.5		28.0
Net income		$	68.8	$	67.5


(in millions)	March 31, 2023		December 31, 2022
Balance sheet data
Current assets	$	100.2	$	89.6
Noncurrent assets	6,070.8		5,997.8
Total assets	$	6,171.0	$	6,087.4

Current liabilities	$	459.7	$	511.9
Long-term debt	2,712.5		2,613.0
Other noncurrent liabilities	502.5		485.8
Members' equity	2,496.3		2,476.7
Total liabilities and members' equity	$	6,171.0	$	6,087.4

NOTE 18—SEGMENT INFORMATION

We use net income attributed to common shareholders to measure segment profitability and to allocate resources to our businesses. At March 31, 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 months ended March 31, 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 March 31, 2023
External revenues	$	1,996.3	$	599.7	$	250.0	$	2,846.0	$	—	$	42.1	$	—	$	—	$	2,888.1
Intersegment revenues	—		—		—		—		—		124.1		—		(124.1)		—
Other operation and maintenance	380.8		113.7		24.7		519.2		—		17.8		(1.4)		(1.6)		534.0
Depreciation and amortization	207.3		58.5		10.4		276.2		—		42.7		5.1		(18.5)		305.5
Equity in earnings of transmission affiliates	—		—		—		—		43.8		—		—		—		43.8
Interest expense	150.6		21.6		4.2		176.4		4.8		19.9		55.6		(84.5)		172.2
Income tax expense (benefit)	65.9		42.0		11.2		119.1		9.7		(17.8)		(36.9)		—		74.1
Net income (loss)	257.5		113.1		33.2		403.8		29.3		88.3		(13.8)		—		507.6
Net income (loss) attributed to common shareholders	257.2		113.1		33.2		403.5		29.3		88.5		(13.8)		—		507.5


	Utility Operations
(in millions)	Wisconsin		Illinois		Other States		Total Utility Operations		Electric Transmission		Non-Utility Energy Infrastructure		Corporate and Other		Reconciling Eliminations		WEC Energy Group Consolidated
Three Months Ended March 31, 2022
External revenues	$	1,942.3	$	682.1	$	240.9	$	2,865.3	$	—	$	42.6	$	0.2	$	—	$	2,908.1
Intersegment revenues	—		—		—		—		—		116.9		—		(116.9)		—
Other operation and maintenance	312.6		113.6		24.6		450.8		—		10.9		(5.7)		(1.6)		454.4
Depreciation and amortization	187.1		56.8		10.0		253.9		—		34.0		6.5		(16.3)		278.1
Equity in earnings of transmission affiliates	—		—		—		—		41.7		—		—		—		41.7
Interest expense	136.3		17.7		3.3		157.3		4.9		17.2		22.6		(84.4)		117.6
Income tax expense (benefit)	95.4		42.1		10.4		147.9		8.9		(4.9)		(24.8)		—		127.1
Net income	288.4		113.4		31.5		433.3		27.8		93.3		13.6		—		568.0
Net income attributed to common shareholders	288.1		113.4		31.5		433.0		27.8		91.5		13.6		—		565.9


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NOTE 19—VARIABLE INTEREST ENTITIES

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

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

WEPCo Environmental Trust Finance I, LLC

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

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

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

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

The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet.


(in millions)	March 31, 2023		December 31, 2022
Assets
Other current assets (restricted cash)	$	5.1	$	3.0
Regulatory assets	90.9		92.4
Other long-term assets (restricted cash)	0.6		0.6

Liabilities
Current portion of long-term debt	8.9		8.9
Accounts payable	0.1		—
Other current liabilities (accrued interest)	0.5		0.1
Long-term debt	94.1		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 March 31, 2023 and December 31, 2022, our


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equity investment in ATC was $1,896.2 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 March 31, 2023 and December 31, 2022, our equity investment in ATC Holdco was $25.5 million and $24.6 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 17, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

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 20—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

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

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

Our minimum future commitments related to these purchase obligations as of March 31, 2023, including those of our subsidiaries, were approximately $10.4 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.


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Air Quality

Cross State Air Pollution Rule – Good Neighbor Plan

In March 2023, the EPA issued its final Good Neighbor Plan, which requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. The rule took effect for the 2023 ozone season. 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 planned RICE units in 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 may be subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule but included new language defining an LDC that we are still evaluating.

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, which could have an adverse effect on our utilities. The EPA is also seeking comments on an even lower limit of 0.006 lb/MMBtu. We are still evaluating the proposed rule revisions to understand the impacts, if any, to our operations.

National Ambient Air Quality Standards

Ozone

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting a previously issued EPA staff-written Integrated Science Assessment for ozone which supported the reconsideration of the 2015 standard. The EPA staff issued a draft Policy Assessment in March 2023 in support of revisiting the 2020 decision to retain the 2015 ozone standards with no changes and indicated that they intend to publish their reconsideration in early 2024, with an anticipated final rule by early 2025.

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 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 was required to submit a SIP revision to the EPA to address the moderate nonattainment status, which it did in December 2022.

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 is also taking comments on the full range (between 8 and 11 µg/m3) included in the CASAC's


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latest report. The EPA has announced it plans to issue a final decision on the reconsideration in summer 2023. All counties within our service territories are in attainment with the current 2012 standards. If the EPA lowers the annual standard to 10 or 11 µg/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.

Climate Change

The ACE rule, which replaced the Clean Power Plan, was vacated by the D.C. Circuit Court of Appeals in January 2021. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling and in June 2022, the Supreme Court issued its decision. The Supreme Court found that the EPA may regulate GHGs under section 111 of the CAA but cannot rely on generation shifting to lower carbon emitting sources to do so. A new GHG replacement rule for existing sources is under review by the OMB.

In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants; however, it was vacated by the D.C. Circuit Court of Appeals in April 2021. A new GHG replacement rule for new, modified, and reconstructed sources is under review by the OMB. We continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, in June 2022. The proposed revisions could impact the reporting required of our local natural gas distribution companies and underground natural gas storage facilities. The EPA intends to issue a new supplemental notice of proposed rulemaking in the second quarter of 2023 with an anticipated final rule to be issued in the fourth quarter of 2023 for all subparts of this rule.

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 coal-fired 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 1-2. See Note 6, 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.

We are also required to report CO2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. We reported aggregated CO2 equivalent emissions of 29.3 million metric tonnes to the EPA for 2022.

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 PWGS, OCPP Units 5-8, and Weston Units 3 and 4. We believe that existing technology installed at the OCPP facility meets the BTA requirements;


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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 in 2023.

We are engaged in discussions with the WDNR regarding the current status of the BTA determination at PWGS. There is uncertainty about whether existing technology meets all of the WDNR's BTA requirements. We will not be in a position to determine what, if any, modifications may be needed at PWGS until the WDNR issues the WPDES permit renewal for PWGS, expected during the second quarter of 2023.

As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to continue to meet this regulation.

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 facilities and created new requirements for several types of power plant wastewaters. The two new requirements that affect us 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 $110 million in capital investment. A $10 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 $90 million ERGS FGD wastewater treatment system modification. The BATW modifications, including $10 million of modifications at Weston Unit 3, do not require PSCW approval prior to construction. All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023.

In 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 (March 29, 2023). 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 we are currently completing a $90 million biological treatment system at ERGS, which we expect to be complete later this year, the expected timing of the project's completion would not comply with the deadline imposed by the EPA to qualify for early adopter status. In addition, we do not believe that, upon its completion, the biological treatment system would be compliant with FGD wastewater treatment requirements as proposed. We are assessing the potential impact, as well as working with the Edison Electric Institute to submit comments to the EPA, regarding this proposed rule revision.

If the supplemental ELG rule is finalized as proposed, we anticipate that our coal fueled facilities either meet, or will meet, the proposed rule provisions that apply to BATW. Once the Weston 3 BATW project is complete, currently expected by the end of 2023, we anticipate that ERGS, Weston 3, and OCPP Units 5 and 6 will have compliant dry bottom ash transport systems. At this time, we do not anticipate significant costs related to complying with the proposed rule as it relates to CCR leachate and legacy wastewater.

Waters of the United States

In January 2023, the EPA and the United States Army Corps of Engineers together released a final rule revising the definition of WOTUS. This rule became effective on March 20, 2023. The final rule states that it is based on the pre-2015 definition of "waters of the United States." The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

The recent rulemaking could be affected by a significant pending Supreme Court case involving WOTUS determination. In October 2022, the Supreme Court heard oral arguments in a case, Sackett v. Environmental Protection Agency, to evaluate the proper test for determining whether wetlands are WOTUS. A decision by the Supreme Court is expected during the second quarter of 2023.


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At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts. The Sackett case, once decided, should provide some clarity regarding the definition of WOTUS. We will continue to monitor this litigation and any subsequent agency action.

Land Quality

Manufactured Gas Plant Remediation

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

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

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

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


(in millions)	March 31, 2023		December 31, 2022
Regulatory assets	$	590.6	$	610.7
Reserves for future environmental remediation	491.7		499.6

Coal Combustion Residuals Rule

In January 2023, the EPA released a notice regarding their intent to revise the CCR rule. The EPA is drafting regulations for CCR storage at inactive generating units or "legacy units." The EPA is also considering proposing corrective action requirements for all CCR contamination at any regulated facility, regardless of how or when the CCR was placed at such site. Our legacy units are currently regulated by the states in which they are located. The proposed rule is expected in summer 2023.

In February 2023, the EPA published notice in the Federal Register of a proposed consent decree to resolve a citizen suit related to conducting a review of Resource Conservation and Recovery Act regulations pertaining to the CCR rule. We are still evaluating the proposed language to understand the impact, if any, to our operations.

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


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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.

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 to close out this Consent Decree in early 2023.

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions


	Three Months Ended March 31
(in millions)	2023		2022
Cash paid for interest, net of amount capitalized	$	107.5	$	68.3
Cash paid for income taxes, net	1.0		0.7
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs	123.0		118.7

Increase in receivable related to insurance proceeds	20.7		0.3

Restricted Cash

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


(in millions)	March 31, 2023		December 31, 2022
Cash and cash equivalents	$	35.7	$	28.9
Restricted cash included in other current assets	39.2		25.6
Restricted cash included in other long-term assets	53.1		127.7
Cash, cash equivalents, and restricted cash	$	128.0	$	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 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 22—REGULATORY ENVIRONMENT

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

2023 Rate Case

On January 6, 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 March 31, 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.

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 is 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.

In April 2023, MERC reached a settlement with certain intervenors. The settlement 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 agreed upon settlement, 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. The settlement is pending MPUC approval, and we expect a decision in the fourth quarter of 2023.

Michigan Gas Utilities Corporation

2023 Rate Case

On March 3, 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates by $19.1 million (9.1%). MGU's request reflects a 10.4% ROE and a common equity component average of 51.4%. The proposed natural gas rate increase is 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 proposed rate increase.


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As part of MGU's rate application, it also requested changes to its Main Replacement Program rider. The changes include updates for projects that are expected to be placed in service during 2023 and 2024 and included in MGU's base rates, updates to remaining project costs to address inflation, and an extension of the rider for an additional two years (new expiration of 2029).

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

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to provide relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. Under ASU No. 2020-04, this relief was effective for all entities beginning 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, which extends the relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform to December 31, 2024. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.


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