WELPP Wisconsin Electric Power Company (QB)

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Wisconsin Electric Power Company serves approximately 1.2 million electric customers and 0.5 million natural gas customers.

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, 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 Wisconsin Electric Power Company and its subsidiary.

On our financial statements, we consolidate VIEs of which we are the primary beneficiary.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2023. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2024, are not necessarily indicative of expected results for 2024 due to seasonal variations and other factors.

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

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions.

Acquisitions of Electric Generation Facilities in Wisconsin

In May 2024, we completed the acquisition of 100 MWs of West Riverside's nameplate capacity for $98.2 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to the acquisition, WPS received approval to transfer its ownership interest rights to us. Including this acquisition, we own 200 MWs, or 27.5%, of West Riverside at a total cost of $193.5 million.

In January 2023, we, along with 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. Our share of the cost of this facility was $38.0 million for 50% of the capacity.

Sale of Real Estate

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

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For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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.

						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Wisconsin Electric Power Company
Electric utility						$	831.4					$	824.9					$	1,677.6					$	1,668.8
Natural gas utility						66.5						70.7						254.4						314.3
Total revenues from contracts with customers						897.9						895.6						1,932.0						1,983.1
Other operating revenues						4.1						4.7						8.8						9.1
Total operating revenues						$	902.0					$	900.3					$	1,940.8					$	1,992.2

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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

						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Residential						$	347.9					$	338.3					$	707.9					$	695.7
Small commercial and industrial						282.2						287.5						569.7						572.1
Large commercial and industrial						144.9						151.6						279.4						290.7
Other						4.9						4.8						10.5						10.5
Total retail revenues						779.9						782.2						1,567.5						1,569.0
Wholesale						13.7						10.3						24.7						22.0
Resale						32.3						26.6						68.8						60.0
Steam						4.7						4.7						14.8						15.7
Other utility revenues						0.8						1.1						1.8						2.1
Total electric utility operating revenues						$	831.4					$	824.9					$	1,677.6					$	1,668.8

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class:

						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Residential						$	38.0					$	35.1					$	173.9					$	214.3
Commercial and industrial						13.9						13.0						75.0						100.9
Total retail revenues						51.9						48.1						248.9						315.2
Transportation						5.2						4.6						12.7						11.4
Other utility revenues (1)						9.4						18.0						(7.2)						(12.3)
Total natural gas utility operating revenues						$	66.5					$	70.7					$	254.4					$	314.3

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

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Other Operating Revenues

Other operating revenues consist primarily of the following:

						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Late payment charges						$	2.9					$	3.3					$	6.4					$	7.0
Rental revenues						1.8						1.3						2.1						1.7
Alternative revenues (1)						(0.6)						0.1						0.3						0.4
Total other operating revenues						$	4.1					$	4.7					$	8.8					$	9.1

Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at June 30, 2024 and December 31, 2023.

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 the PSCW, 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 a table below that shows our gross third-party receivable balances and related allowance for credit losses.

(in millions)						June 30, 2024						December 31, 2023
Accounts receivable and unbilled revenues						$	600.8					$	617.5
Allowance for credit losses						42.0						44.5
Accounts receivable and unbilled revenues, net (1)						$	558.8					$	573.0
Total accounts receivable, net – past due greater than 90 days (1)						$	39.2					$	37.2
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)						94.4		%				94.1		%

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at June 30, 2024, $311.8 million, or 55.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

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A rollforward of the allowance for credit losses is included below:

						Three Months Ended June 30
(in millions)						2024						2023
Balance at April 1						$	48.9					$	53.7
Provision for credit losses						7.1						4.7
Provision for credit losses deferred for future recovery or refund						6.5						1.7
Write-offs charged against the allowance						(26.5)						(21.3)
Recoveries of amounts previously written off						6.0						6.3
Balance at June 30						$	42.0					$	45.1

						Six Months Ended June 30
(in millions)						2024						2023
Balance at January 1						$	44.5					$	49.7
Provision for credit losses						15.2						11.3
Provision for credit losses deferred for future recovery or refund						20.7						15.5
Write-offs charged against the allowance						(51.5)						(41.6)
Recoveries of amounts previously written off						13.1						10.2
Balance at June 30						$	42.0					$	45.1

There was a $2.5 million decrease in the allowance for credit losses at June 30, 2024, compared to January 1, 2024, largely driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. The winter moratorium begins on November 1 and ends on April 15. Also contributing to the decrease in the allowance for credit losses, we have seen lower required reserve percentages as a result of an improvement in loss rates. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

There was a $4.6 million decrease in the allowance for credit losses at June 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. Also contributing to the decrease in the allowance for credit losses, we believe that the lower energy costs that customers were seeing, which were driven by lower natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

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The following regulatory assets and liabilities were reflected on our balance sheets at June 30, 2024 and December 31, 2023. For more information on our regulatory assets and liabilities, see Note 7, Regulatory Assets and Liabilities, in our 2023 Annual Report on Form 10-K.

(in millions)						June 30, 2024						December 31, 2023
Regulatory assets
We Power finance leases						$	1,125.6					$	1,109.7
Plant retirement related items (1)						675.3						595.5
Income tax related items						367.8						373.1
Pension and OPEB costs						352.1						348.9
System support resource						108.0						113.2
Uncollectible expense						82.8						62.1
Securitization						82.3						85.9
Asset retirement obligations						50.3						41.2
Derivatives						22.2						45.2
Energy efficiency programs						19.8						23.3
Bluewater Natural Gas Holding, LLC						19.8						17.2
Environmental remediation costs						11.2						12.2
Other, net						37.7						33.2
Total regulatory assets						$	2,954.9					$	2,860.7

(1)    Included in plant retirement related items at June 30, 2024, are $19.5 million of capitalized retirement costs related to the new EPA CCR Rule that was enacted in April 2024. See Note 21, Commitments and Contingencies, for more information.

(in millions)						June 30, 2024						December 31, 2023
Regulatory liabilities
Removal costs						$	788.9					$	758.9
Income tax related items						668.6						683.5
Pension and OPEB benefits						125.3						124.0
Energy costs refundable through rate adjustments						49.0						5.5
Electric transmission costs						25.2						23.9
Paris (1)						17.7						—
Other, net						46.2						40.9
Total regulatory liabilities						$	1,720.9					$	1,636.7
Balance sheet presentation
Other current liabilities						$	12.7					$	5.3
Regulatory liabilities						1,708.2						1,631.4
Total regulatory liabilities						$	1,720.9					$	1,636.7

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

Oak Creek Power Plant Units 5-6

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Plant to be Retired

Oak Creek Power Plant Units 7-8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for Koshkonong and have acquired 200 MWs of capacity in West Riverside. See Note 2, Acquisitions, for more information on the West Riverside acquisitions. OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of our ownership share of OCPP Units 7 and 8 was $675.8 million at June 30, 2024, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; and the closure of CCR landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the PSCW.

On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs:

(in millions)						2024						2023
Balance at January 1						$	73.1					$	71.7
Accretion						1.0						0.9
Additions						34.0			(1)			—
Balance at June 30						$	108.1					$	72.6

(1)    AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 21, Commitments and Contingencies, for more information.

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 11, Common Equity, in our 2023 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

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

(in millions, except percentages)						June 30, 2024						December 31, 2023
Commercial paper
Amount outstanding						$	200.5					$	360.8
Weighted-average interest rate on amounts outstanding						5.44		%				5.48		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2024 was $220.0 million with a weighted-average interest rate during the period of 5.46%.

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The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:

(in millions)						Maturity						June 30, 2024
Revolving credit facility						September 2026						$	500.0
Less:
Letters of credit issued inside credit facility												1.0
Commercial paper outstanding												200.5
Available capacity under existing credit facility												$	298.5

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

On July 30, 2024, we, along with WPS, partnered with an unaffiliated utility to acquire and construct Koshkonong, a utility-scale solar-powered electric generating facility located in Dane County, Wisconsin. Once fully constructed, we will own 225 MWs of solar generation. Related to our investment in Koshkonong, we, WPS, and our unaffiliated utility partner, entered into several land leases that commenced in the third quarter of 2024. We are currently evaluating the impact these leases will have on our financial statements and related disclosures.

Our inventories consisted of:

(in millions)						June 30, 2024						December 31, 2023
Materials and supplies						$	205.4					$	186.6
Fossil fuel						62.3						74.5
Natural gas in storage						37.7						49.5
Total						$	305.4					$	310.6

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

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

						Three Months Ended June 30, 2024												Three Months Ended June 30, 2023
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	22.8					21.0		%				$	30.7					21.0		%
State income taxes net of federal tax benefit						6.5						6.0		%				8.7						6.0		%
Federal excess deferred tax amortization						(3.5)						(3.2)		%				(4.7)						(3.2)		%
PTCs, net						(3.1)						(2.9)		%				(1.8)						(1.2)		%
AFUDC–Equity						(1.9)						(1.7)		%				(1.9)						(1.3)		%
Domestic production activities deferral						1.1						1.0		%				1.4						1.0		%
Other, net						1.7						1.4		%				1.9						1.2		%
Total income tax expense						$	23.6					21.6		%				$	34.3					23.5		%
						Six Months Ended June 30, 2024												Six Months Ended June 30, 2023
(in millions)						Amount						Effective Tax Rate						Amount						Effective Tax Rate
Statutory federal income tax						$	58.5					21.0		%				$	63.1					21.0		%
State income taxes net of federal tax benefit						16.5						5.9		%				18.0						6.0		%
Federal excess deferred tax amortization						(9.2)						(3.3)		%				(10.0)						(3.3)		%
PTCs, net						(8.2)						(3.0)		%				(6.9)						(2.3)		%
AFUDC–Equity						(5.1)						(1.8)		%				(4.1)						(1.4)		%
Domestic production activities deferral						2.8						1.0		%				3.0						1.0		%
Other, net						4.1						1.5		%				3.9						1.3		%
Total income tax expense						$	59.4					21.3		%				$	67.0					22.3		%

The effective tax rates for the three and six months ended June 30, 2024, do not materially differ from the United States statutory federal income tax rate of 21%. This is primarily due to the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs, offset by state income taxes.

The effective tax rates for the three and six months ended June 30, 2023, differ from the United States statutory federal income tax rate of 21%, primarily due to state income taxes. This item was partially offset by the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below.

The Tax Legislation required us to remeasure the deferred income taxes at our utility segment, and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization lines above). See Note 24, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information about the impact of the Tax Legislation.

The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023 and May 2024, under this transferability provision, WEC Energy Group entered into agreements to sell substantially all of the PTCs we generated in 2023 and substantially all of the PTCs expected to be generated in 2024 to third parties. We elect to account for tax credits transferred under the scope of Accounting Standards Codification 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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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 derivative 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, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our FTRs are valued using MISO auction prices.

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

						June 30, 2024
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	1.3					$	1.0					$	—					$	2.3
FTRs						—						—						9.7						9.7
Total derivative assets						$	1.3					$	1.0					$	9.7					$	12.0
Derivative liabilities
Natural gas contracts						$	5.3					$	0.8					$	—					$	6.1
Coal contracts						—						14.7						—						14.7
Total derivative liabilities						$	5.3					$	15.5					$	—					$	20.8

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						December 31, 2023
(in millions)						Level 1						Level 2						Level 3						Total
Derivative assets
Natural gas contracts						$	0.9					$	1.3					$	—					$	2.2
FTRs						—						—						2.5						2.5
Total derivative assets						$	0.9					$	1.3					$	2.5					$	4.7
Derivative liabilities
Natural gas contracts						$	16.1					$	3.1					$	—					$	19.2
Coal contracts						—						19.3						—						19.3
Total derivative liabilities						$	16.1					$	22.4					$	—					$	38.5

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 to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets.

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

						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Balance at the beginning of the period						$	1.0					$	0.8					$	2.5					$	2.0
Purchases						12.1						8.1						12.1						8.1
Settlements						(3.4)						(2.0)						(4.9)						(3.2)
Balance at the end of the period						$	9.7					$	6.9					$	9.7					$	6.9

Fair Value of Financial Instruments

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

						June 30, 2024												December 31, 2023
(in millions)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Preferred stock						$	30.4					$	21.2					$	30.4					$	21.4
Long-term debt, including current portion						3,697.9						3,529.0						3,354.4						3,255.4

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

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

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, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

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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 are designated as hedging instruments.

						June 30, 2024												December 31, 2023
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Current
Natural gas contracts						$	2.3					$	5.9					$	2.2					$	18.6
FTRs						9.7						—						2.5						—
Coal contracts						—						10.0						—						10.2
Total current						12.0						15.9						4.7						28.8
Long-term
Natural gas contracts						—						0.2						—						0.6
Coal contracts						—						4.7						—						9.1
Total long-term						—						4.9						—						9.7
Total						$	12.0					$	20.8					$	4.7					$	38.5

Realized gains and losses on derivatives are primarily 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 fuel and natural gas cost recovery mechanisms. Our estimated notional sales volumes and realized gains and losses were as follows:

						Three Months Ended June 30, 2024												Three Months Ended June 30, 2023
(in millions)						Volumes						Gains (Losses)						Volumes						Gains (Losses)
Natural gas contracts						16.3 Dth						$	(9.4)					17.0 Dth						$	(25.3)
FTRs						5.1 MWh						1.4						5.2 MWh						1.9
Total												$	(8.0)											$	(23.4)
						Six Months Ended June 30, 2024												Six Months Ended June 30, 2023
(in millions)						Volumes						Gains (Losses)						Volumes						Gains (Losses)
Natural gas contracts						39.2 Dth						$	(26.4)					35.9 Dth						$	(54.5)
FTRs						10.0 MWh						3.3						10.1 MWh						2.0
Total												$	(23.1)											$	(52.5)

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2024 and December 31, 2023, we had posted cash collateral of $13.9 million and $26.7 million, respectively. These amounts were recorded on our balance sheets in other current assets.

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

						June 30, 2024												December 31, 2023
(in millions)						Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
Gross amount recognized on the balance sheet						$	12.0					$	20.8					$	4.7					$	38.5
Gross amount not offset on the balance sheet						(1.4)						(5.5)			(1)			(1.3)						(16.5)			(2)
Net amount						$	10.6					$	15.3					$	3.4					$	22.0

(1)    Includes cash collateral posted of $4.1 million.

(2)    Includes cash collateral posted of $15.2 million.

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As of June 30, 2024, we had $26.0 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

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

						Pension Benefits
						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Service cost						$	2.4					$	2.3					$	5.2					$	5.1
Interest cost						11.0						11.7						22.3						23.6
Expected return on plan assets						(15.2)						(15.8)						(30.8)						(32.2)
Amortization of net actuarial loss						4.7						2.7						9.0						4.6
Net periodic benefit cost						$	2.9					$	0.9					$	5.7					$	1.1

						OPEB Benefits
						Three Months Ended June 30												Six Months Ended June 30
(in millions)						2024						2023						2024						2023
Service cost						$	0.8					$	0.6					$	1.6					$	1.3
Interest cost						2.0						1.9						4.1						3.8
Expected return on plan assets						(2.8)						(3.3)						(5.5)						(6.7)
Amortization of prior service credit						—						(0.2)						(0.1)						(0.4)
Amortization of net actuarial gain						(1.4)						(2.2)						(2.8)						(4.4)
Net periodic benefit credit						$	(1.4)					$	(3.2)					$	(2.7)					$	(6.4)

During the six months ended June 30, 2024, we made contributions and payments of $3.3 million related to our pension plans and an insignificant amount related to our OPEB plans. We expect to make contributions and payments of $0.2 million related to our OPEB plans and an insignificant amount related to our pension plans during the remainder of 2024, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of June 30, 2024, we recorded a $4.3 million regulatory asset for pension costs and an $11.5 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

We use net income attributed to common shareholder to measure segment profitability and to allocate resources to our business. At June 30, 2024, we reported two segments, our utility segment and our other segment, which are described below.

Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations.

•Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee.

•Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin.

No significant items were reported in the other segment during the three and six months ended June 30, 2024 and 2023.

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All of our operations and assets are located within the United States.

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 our 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 us 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 our wholly owned subsidiary.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from us. 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 our retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders do not have any recourse to us or any of our affiliates.

We act as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and are responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, we are 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 remit 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 have the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, we are considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.

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

(in millions)						June 30, 2024						December 31, 2023
Assets
Other current assets (restricted cash)						$	0.3					$	0.8
Regulatory assets						82.3						85.9
Other long-term assets (restricted cash)						0.3						0.6
Liabilities
Current portion of long-term debt						9.1						9.0
Accounts payable						0.1						—
Other current liabilities (accrued interest)						0.1						0.1
Long-term debt						80.9						85.3

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We 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

We have obligations to distribute and sell electricity and natural gas to our customers and 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. Our minimum future commitments related to these purchase obligations as of June 30, 2024, were approximately $7.1 billion.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

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

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

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

Mercury and Air Toxics Standards

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

National Ambient Air Quality Standards

Ozone

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

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

The effective date for the initial nonattainment area designation was August 2018 and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit adequate SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard. This action triggered a May 2025 deadline for states to get their SIP approved or the EPA will issue a federal implementation plan. Additionally, offset sanctions will take effect 18 months from the May 2025 deadline if the SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas. The WDNR intends to submit a SIP revision by the May 2025 deadline.

The next attainment evaluation date is August 2024. If the moderate attainment deadline is not met, the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. We are currently evaluating what, if any, impacts the potential nonattainment redesignation will have on our operations.

Particulate Matter

All counties within our service territory are in attainment with current 2012 standards for fine PM2.5. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard of 35 µg/m3. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until May 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units.

Climate Change

In May 2023, the EPA proposed GHG performance standards for fossil-fired steam generating and natural gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. The final rule, known as the Greenhouse Gas Power Plant Rule, was published in May 2024. Pursuant to the final rule, there are no applicable standards for coal plants until the end of 2031 and after 2031, the applicable standard is dependent upon the unit's retirement date. Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029. For new combined cycle natural gas plants above a 40% capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031. For new simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our new Weston RICE units are not affected under the rule because the rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the Greenhouse Gas Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals.

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

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

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The ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired nearly 2,100 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle Power Plant, and the 2018 retirement of the Pleasant Prairie Power Plant. WEC Energy Group expects to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8 in late 2025. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements. In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for WEC Energy Group's generation fleet is to be net carbon neutral by 2050.

WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution systems, and has set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its natural gas utility distribution systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

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

We have received interim BTA determinations for all generation facilities where Section 316(b) is applicable. With respect to OCPP Units 7 and 8, we believe the WDNR will determine that existing technology (wet cooling towers) installed at the units represents BTA for minimizing adverse environmental impacts in accordance with the requirements in the CWA when the WPDES permit for those units is reissued, which is expected in 2025.

Steam Electric Effluent Limitation Guidelines

The EPA's final ELG rule, which took effect in January 2016 ("2015 ELG rule"), was modified in 2020 ("2020 ELG rule"), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect us relate to discharge limits for BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP and ERGS to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $97 million in capital investment.

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

The final Supplemental ELG Rule allows owners of coal-fueled units who opted into a cessation of coal subcategory to operate beyond the end of 2028 or 2034, required by either the 2015 or the 2020 ELG Rule, respectively, if needed for reliability concerns

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(i.e., energy emergencies, reliability must run agreements, etc.) as determined by the United States Department of Energy, a public utility commission, or independent system operator.

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

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we 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. We are responsible for the environmental remediation of these sites. We are also working with the state of Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

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

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

(in millions)						June 30, 2024						December 31, 2023
Regulatory assets						$	11.2					$	12.2
Reserves for future environmental remediation (1)						10.3						10.3

(1)Recorded within other long-term liabilities on our balance sheets.

Coal Combustion Residuals Rule

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

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

Enforcement and Litigation Matters

We 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.

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Non-Cash Transactions

						Six Months Ended June 30
(in millions)						2024						2023
Cash paid for interest, net of amount capitalized						$	236.9					$	233.5
Cash paid for income taxes, net (1)						59.9						65.0
Significant non-cash investing and financing transactions:
Accounts payable related to construction costs						102.6						61.0

(1)    Cash paid for income taxes in 2024 was net of $10.7 million related to 2023 and 2024 PTCs that were sold to third parties.

Restricted Cash

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

(in millions)						June 30, 2024						December 31, 2023
Cash and cash equivalents						$	—					$	6.1
Restricted cash included in other current assets						0.3						0.8
Restricted cash included in other long-term assets						0.3						0.6
Cash, cash equivalents, and restricted cash						$	0.6					$	7.5

Our restricted cash consisted of cash on deposit in a financial institution that is restricted to satisfy the requirements of a debt agreement at WEPCo Environmental Trust. See Note 20, Variable Interest Entities, for more information.

2025 and 2026 Rate Case

On April 12, 2024, we filed a request with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2025 and January 1, 2026, as applicable. The request reflected the following:

Proposed 2025 rate increase
Electric						$	240.7	million	/			6.9%
Gas						$	57.5	million	/			10.0%
Steam						$	2.5	million	/			8.4%
Proposed 2026 rate increase (1)
Electric						$	177.9	million	/			4.6%
Gas						$	31.0	million	/			4.6%
Proposed ROE						10.0%
Proposed common equity component average on a financial basis						53.5%

(1)    The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025.

The primary drivers of the requested increases in electric rates are continued capital investments to transition our generation fleet from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW.

The requested increases in natural gas rates are driven by our ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates.

We also proposed retaining our current earnings sharing mechanism. Under the current earnings sharing mechanism, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the

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next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers.

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

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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v3.24.2

COVER PAGE	6 Months Ended
	Jun. 30, 2024 shares
Cover [Abstract]
Document type	10-Q
Document Quarterly Report	true
Document period end date	Jun. 30, 2024
Document Transition Report	false
Entity File Number	001-01245
Entity registrant name	WISCONSIN ELECTRIC POWER COMPANY
Entity Tax Identification Number	39-0476280
Entity Incorporation, State or Country Code	WI
Entity Address, Address Line One	231 West Michigan Street
Entity Address, Address Line Two	P.O. Box 2046
Entity Address, City or Town	Milwaukee
Entity Address, State or Province	WI
Entity Address, Postal Zip Code	53201
City Area Code	414
Local Phone Number	221-2345
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity filer category	Non-accelerated Filer
Small business	false
Emerging growth company	false
Entity Shell Company	false
Entity common stock, shares outstanding	33,289,327
Entity central index key	0000107815
Current fiscal year end date	--12-31
Document fiscal year focus	2024
Document fiscal period focus	Q2
Amendment flag	false

v3.24.2

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Income Statement [Abstract]
Operating revenues	$ 902.0	$ 900.3	$ 1,940.8	$ 1,992.2
Operating expenses
Cost of sales	279.9	292.5	632.1	737.0
Other operation and maintenance	237.4	206.0	479.0	438.3
Depreciation and amortization	142.0	129.3	281.6	257.1
Property and revenue taxes	29.3	28.4	60.1	58.3
Total operating expenses	688.6	656.2	1,452.8	1,490.7
Operating income	213.4	244.1	488.0	501.5
Other income, net	16.2	19.0	32.5	34.1
Interest expense	120.4	116.9	241.2	234.7
Other expense	(104.2)	(97.9)	(208.7)	(200.6)
Income before income taxes	109.2	146.2	279.3	300.9
Income tax expense	23.6	34.3	59.4	67.0
Net income	85.6	111.9	219.9	233.9
Preferred stock dividend requirements	0.3	0.3	0.6	0.6
Net income attributed to common shareholder	$ 85.3	$ 111.6	$ 219.3	$ 233.3

v3.24.2

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 0.0	$ 6.1
Materials, supplies, and inventories	305.4	310.6
Prepaid taxes	128.3	112.7
Other prepayments	13.3	26.7
Other	26.2	32.3
Current assets	1,142.4	1,205.3
Long-term assets
Property, plant, and equipment, net of accumulated depreciation and amortization of $5,779.6 and $5,779.2, respectively	11,982.9	11,585.5
Regulatory assets (June 30, 2024 and December 31, 2023 include $82.3 and $85.9, respectively, related to WEPCo Environmental Trust)	2,954.9	2,860.7
Pension and OPEB assets	73.1	71.0
Other	93.4	118.9
Long-term assets	15,104.3	14,636.1
Total assets	16,246.7	15,841.4
Current liabilities
Short-term debt	200.5	360.8
Current portion of long-term debt (June 30, 2024 and December 31, 2023 include $9.1 and $9.0 related to WEPCo Environmental Trust)	559.1	309.0
Current portion of finance lease obligations	93.2	87.8
Other	168.1	201.4
Current liabilities	1,600.5	1,484.9
Long-term liabilities
Long-term debt (June 30, 2024 and December 31, 2023 include $80.9 and $85.3, respectively, related to WEPCo Environmental Trust)	3,138.8	3,045.4
Finance lease obligations	2,708.3	2,752.2
Deferred income taxes	1,556.0	1,513.5
Regulatory liabilities	1,708.2	1,631.4
Other	351.6	330.5
Long-term liabilities	9,462.9	9,273.0
Commitments and contingencies (Note 21)
Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9	332.9
Additional paid in capital	2,552.9	2,552.4
Retained earnings	2,267.1	2,167.8
Common shareholder's equity	5,152.9	5,053.1
Preferred stock	30.4	30.4
Total liabilities and equity	16,246.7	15,841.4
Nonrelated party
Current assets
Accounts receivable	558.8	573.0
Current liabilities
Accounts payable	383.7	332.1
Related party
Current assets
Accounts receivable	110.4	143.9
Current liabilities
Accounts payable	$ 195.9	$ 193.8

v3.24.2

CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 42.0	$ 44.5
Property, plant, and equipment, accumulated depreciation and amortization	$ 5,779.6	$ 5,779.2
Common stock, par value (in dollars per share)	$ 10	$ 10
Common stock, shares authorized	65,000,000	65,000,000
Common stock, shares outstanding	33,289,327	33,289,327
Regulatory assets (June 30, 2024 and December 31, 2023 include $82.3 and $85.9, respectively, related to WEPCo Environmental Trust)	$ 2,954.9	$ 2,860.7
Long-term debt (June 30, 2024 and December 31, 2023 include $80.9 and $85.3, respectively, related to WEPCo Environmental Trust)	3,138.8	3,045.4
Current portion of long-term debt (June 30, 2024 and December 31, 2023 include $9.1 and $9.0 related to WEPCo Environmental Trust)	559.1	309.0
WEPCo Environmental Trust
Regulatory assets (June 30, 2024 and December 31, 2023 include $82.3 and $85.9, respectively, related to WEPCo Environmental Trust)	82.3	85.9
Long-term debt (June 30, 2024 and December 31, 2023 include $80.9 and $85.3, respectively, related to WEPCo Environmental Trust)	80.9	85.3
Current portion of long-term debt (June 30, 2024 and December 31, 2023 include $9.1 and $9.0 related to WEPCo Environmental Trust)	$ 9.1	$ 9.0

v3.24.2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Operating activities
Net income	$ 219.9	$ 233.9
Reconciliation to cash provided by operating activities
Depreciation and amortization	281.6	257.1
Deferred income taxes and ITCs, net	31.9	14.6
Change in –
Accounts receivable and unbilled revenues, net	42.0	75.4
Materials, supplies, and inventories	5.2	42.2
Prepaid taxes	(15.6)	(15.7)
Other prepayments	12.8	8.5
Collateral on deposit	12.8	(7.5)
Other current assets	0.0	0.5
Accounts payable	12.3	(101.0)
Amounts refundable to customers	7.4	13.0
Other current liabilities	(25.6)	(36.7)
Other, net	32.1	(26.0)
Net cash provided by operating activities	616.8	458.3
Investing activities
Capital expenditures	(548.3)	(467.8)
Acquisition of West Riverside	(98.2)	(95.3)
Acquisition of Whitewater	0.0	(38.0)
Proceeds from the sale of assets	0.8	24.2
Reimbursement for ATC's construction costs	6.2	0.0
Payments for ATC's construction costs that will be reimbursed	(0.5)	(15.9)
Other, net	(1.9)	(7.4)
Net cash used in investing activities	(641.9)	(600.2)
Financing activities
Change in short-term debt	(160.3)	(417.7)
Issuance of long-term debt	349.2	0.0
Retirement of long-term debt	(4.5)	(4.4)
Payments for finance lease obligations	(42.4)	(37.3)
Equity contribution from parent	0.0	705.0
Payment of dividends to parent	(120.0)	(120.0)
Other, net	(3.8)	(0.6)
Net cash provided by financing activities	18.2	125.0
Net change in cash, cash equivalents, and restricted cash	(6.9)	(16.9)
Cash, cash equivalents, and restricted cash at beginning of period	7.5	47.7
Cash, cash equivalents, and restricted cash at end of period	$ 0.6	$ 30.8

v3.24.2

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total common shareholder's equity	Common stock	Additional paid in capital	Retained earnings	Preferred stock
Balance at Dec. 31, 2022	$ 4,167.2	$ 4,136.8	$ 332.9	$ 1,746.8	$ 2,057.1	$ 30.4
Statements of equity
Net income attributed to common shareholder	121.7	121.7	0.0	0.0	121.7	0.0
Payment of dividends to parent	(60.0)	(60.0)	0.0	0.0	(60.0)	0.0
Equity contribution from parent	415.0	415.0	0.0	415.0	0.0	0.0
Stock-based compensation and other	0.6	0.6	0.0	0.5	0.1	0.0
Balance at Mar. 31, 2023	4,644.5	4,614.1	332.9	2,162.3	2,118.9	30.4
Balance at Dec. 31, 2022	4,167.2	4,136.8	332.9	1,746.8	2,057.1	30.4
Statements of equity
Net income attributed to common shareholder	233.3
Payment of dividends to parent	(120.0)
Equity contribution from parent	705.0
Balance at Jun. 30, 2023	4,986.1	4,955.7	332.9	2,452.3	2,170.5	30.4
Balance at Mar. 31, 2023	4,644.5	4,614.1	332.9	2,162.3	2,118.9	30.4
Statements of equity
Net income attributed to common shareholder	111.6	111.6	0.0	0.0	111.6	0.0
Payment of dividends to parent	(60.0)	(60.0)	0.0	0.0	(60.0)	0.0
Equity contribution from parent	290.0	290.0	0.0	290.0	0.0	0.0
Balance at Jun. 30, 2023	4,986.1	4,955.7	332.9	2,452.3	2,170.5	30.4
Balance at Dec. 31, 2023	5,083.5	5,053.1	332.9	2,552.4	2,167.8	30.4
Statements of equity
Net income attributed to common shareholder	134.0	134.0	0.0	0.0	134.0	0.0
Payment of dividends to parent	(60.0)	(60.0)	0.0	0.0	(60.0)	0.0
Stock-based compensation and other	0.4	0.4	0.0	0.5	(0.1)	0.0
Balance at Mar. 31, 2024	5,157.9	5,127.5	332.9	2,552.9	2,241.7	30.4
Balance at Dec. 31, 2023	5,083.5	5,053.1	332.9	2,552.4	2,167.8	30.4
Statements of equity
Net income attributed to common shareholder	219.3
Payment of dividends to parent	(120.0)
Equity contribution from parent	0.0
Balance at Jun. 30, 2024	5,183.3	5,152.9	332.9	2,552.9	2,267.1	30.4
Balance at Mar. 31, 2024	5,157.9	5,127.5	332.9	2,552.9	2,241.7	30.4
Statements of equity
Net income attributed to common shareholder	85.3	85.3	0.0	0.0	85.3	0.0
Payment of dividends to parent	(60.0)	(60.0)	0.0	0.0	(60.0)	0.0
Stock-based compensation and other	0.1	0.1	0.0	0.0	0.1	0.0
Balance at Jun. 30, 2024	$ 5,183.3	$ 5,152.9	$ 332.9	$ 2,552.9	$ 2,267.1	$ 30.4

v3.24.2

GENERAL INFORMATION	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	GENERAL INFORMATION Wisconsin Electric Power Company serves approximately 1.2 million electric customers and 0.5 million natural gas customers. As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, 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 Wisconsin Electric Power Company and its subsidiary. On our financial statements, we consolidate VIEs of which we are the primary beneficiary. We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2023. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2024, are not necessarily indicative of expected results for 2024 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

v3.24.2

ACQUISITIONS	6 Months Ended
	Jun. 30, 2024
Asset Acquisition [Abstract]
ACQUISITIONS	ACQUISITIONS In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions. Acquisitions of Electric Generation Facilities in Wisconsin In May 2024, we completed the acquisition of 100 MWs of West Riverside's nameplate capacity for $98.2 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. Prior to the acquisition, WPS received approval to transfer its ownership interest rights to us. Including this acquisition, we own 200 MWs, or 27.5%, of West Riverside at a total cost of $193.5 million. In January 2023, we, along with 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. Our share of the cost of this facility was $38.0 million for 50% of the capacity.

v3.24.2

DISPOSITION	6 Months Ended
	Jun. 30, 2024
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITION	DISPOSITION Sale of Real Estate In June 2023, we sold approximately 192 acres of real estate at our former Pleasant Prairie power plant site that was no longer being utilized in our operations, for $23.0 million, which is net of closing costs. As a result of the sale, a pre-tax gain in the amount of $22.2 million was recorded within other operation and maintenance expense on our income statement. The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

v3.24.2

OPERATING REVENUES	6 Months Ended
	Jun. 30, 2024
Revenue from Contract with Customer [Abstract]
OPERATING REVENUES	OPERATING REVENUES For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K. Disaggregation of Operating Revenues The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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. Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Wisconsin Electric Power Company Electric utility $ 831.4  $ 824.9  $ 1,677.6  $ 1,668.8  Natural gas utility 66.5  70.7  254.4  314.3  Total revenues from contracts with customers 897.9  895.6  1,932.0  1,983.1  Other operating revenues 4.1  4.7  8.8  9.1  Total operating revenues $ 902.0  $ 900.3  $ 1,940.8  $ 1,992.2  Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Residential $ 347.9  $ 338.3  $ 707.9  $ 695.7  Small commercial and industrial 282.2  287.5  569.7  572.1  Large commercial and industrial 144.9  151.6  279.4  290.7  Other 4.9  4.8  10.5  10.5  Total retail revenues 779.9  782.2  1,567.5  1,569.0  Wholesale 13.7  10.3  24.7  22.0  Resale 32.3  26.6  68.8  60.0  Steam 4.7  4.7  14.8  15.7  Other utility revenues 0.8  1.1  1.8  2.1  Total electric utility operating revenues $ 831.4  $ 824.9  $ 1,677.6  $ 1,668.8  Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Residential $ 38.0  $ 35.1  $ 173.9  $ 214.3  Commercial and industrial 13.9  13.0  75.0  100.9  Total retail revenues 51.9  48.1  248.9  315.2  Transportation 5.2  4.6  12.7  11.4  Other utility revenues (1) 9.4  18.0  (7.2) (12.3) Total natural gas utility operating revenues $ 66.5  $ 70.7  $ 254.4  $ 314.3  (1)Includes the revenues subject to our purchased gas recovery mechanism, which fluctuate based on actual natural gas costs incurred, compared with the recovery of natural gas costs that were anticipated in rates. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Late payment charges $ 2.9  $ 3.3  $ 6.4  $ 7.0  Rental revenues 1.8  1.3  2.1  1.7  Alternative revenues (1) (0.6) 0.1  0.3  0.4  Total other operating revenues $ 4.1  $ 4.7  $ 8.8  $ 9.1  (1)Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to wholesale customers subject to true-ups. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

v3.24.2

CREDIT LOSSES	6 Months Ended
	Jun. 30, 2024
Credit Loss [Abstract]
CREDIT LOSSES	CREDIT LOSSES Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at June 30, 2024 and December 31, 2023. 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 the PSCW, 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 a table below that shows our gross third-party receivable balances and related allowance for credit losses. (in millions) June 30, 2024 December 31, 2023 Accounts receivable and unbilled revenues $ 600.8  $ 617.5  Allowance for credit losses 42.0  44.5  Accounts receivable and unbilled revenues, net (1) $ 558.8  $ 573.0  Total accounts receivable, net – past due greater than 90 days (1) $ 39.2  $ 37.2  Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 94.4  % 94.1  % (1)Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at June 30, 2024, $311.8 million, or 55.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. A rollforward of the allowance for credit losses is included below: Three Months Ended June 30 (in millions) 2024 2023 Balance at April 1 $ 48.9  $ 53.7  Provision for credit losses 7.1  4.7  Provision for credit losses deferred for future recovery or refund 6.5  1.7  Write-offs charged against the allowance (26.5) (21.3) Recoveries of amounts previously written off 6.0  6.3  Balance at June 30 $ 42.0  $ 45.1  Six Months Ended June 30 (in millions) 2024 2023 Balance at January 1 $ 44.5  $ 49.7  Provision for credit losses 15.2  11.3  Provision for credit losses deferred for future recovery or refund 20.7  15.5  Write-offs charged against the allowance (51.5) (41.6) Recoveries of amounts previously written off 13.1  10.2  Balance at June 30 $ 42.0  $ 45.1  There was a $2.5 million decrease in the allowance for credit losses at June 30, 2024, compared to January 1, 2024, largely driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. The winter moratorium begins on November 1 and ends on April 15. Also contributing to the decrease in the allowance for credit losses, we have seen lower required reserve percentages as a result of an improvement in loss rates. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. There was a $4.6 million decrease in the allowance for credit losses at June 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. Also contributing to the decrease in the allowance for credit losses, we believe that the lower energy costs that customers were seeing, which were driven by lower natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

v3.24.2

REGULATORY ASSETS AND LIABILITIES	6 Months Ended
	Jun. 30, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities were reflected on our balance sheets at June 30, 2024 and December 31, 2023. For more information on our regulatory assets and liabilities, see Note 7, Regulatory Assets and Liabilities, in our 2023 Annual Report on Form 10-K. (in millions) June 30, 2024 December 31, 2023 Regulatory assets We Power finance leases $ 1,125.6  $ 1,109.7  Plant retirement related items (1) 675.3  595.5  Income tax related items 367.8  373.1  Pension and OPEB costs 352.1  348.9  System support resource 108.0  113.2  Uncollectible expense 82.8  62.1  Securitization 82.3  85.9  Asset retirement obligations 50.3  41.2  Derivatives 22.2  45.2  Energy efficiency programs 19.8  23.3  Bluewater Natural Gas Holding, LLC 19.8  17.2  Environmental remediation costs 11.2  12.2  Other, net 37.7  33.2  Total regulatory assets $ 2,954.9  $ 2,860.7  (1)    Included in plant retirement related items at June 30, 2024, are $19.5 million of capitalized retirement costs related to the new EPA CCR Rule that was enacted in April 2024. See Note 21, Commitments and Contingencies, for more information. (in millions) June 30, 2024 December 31, 2023 Regulatory liabilities Removal costs $ 788.9  $ 758.9  Income tax related items 668.6  683.5  Pension and OPEB benefits 125.3  124.0  Energy costs refundable through rate adjustments 49.0  5.5  Electric transmission costs 25.2  23.9  Paris (1) 17.7  —  Other, net 46.2  40.9  Total regulatory liabilities $ 1,720.9  $ 1,636.7  Balance sheet presentation Other current liabilities $ 12.7  $ 5.3  Regulatory liabilities 1,708.2  1,631.4  Total regulatory liabilities $ 1,720.9  $ 1,636.7  (1)In accordance with our rate order approved by the PSCW in December 2023, we are deferring to a future rate proceeding the incremental revenue requirement impact associated with the change to the in-service date of Paris. Oak Creek Power Plant Units 5-6 In May 2024, OCPP Units 5 and 6 were retired. Due to the retirement of these units and the determination that recovery was probable, their net book value of $78.3 million at June 30, 2024 was classified as a regulatory asset. In addition, a $43.9 million cost of removal reserve related to the units continued to be classified as a regulatory liability at June 30, 2024. Not included in these amounts was $9.4 million of deferred tax liabilities previously recorded for the retired units. Effective with our rate order issued by the PSCW in December 2022, we received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. We also intend to request FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

v3.24.2

PROPERTY, PLANT, AND EQUIPMENT	6 Months Ended
	Jun. 30, 2024
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	PROPERTY, PLANT, AND EQUIPMENT Plant to be Retired Oak Creek Power Plant Units 7-8 As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for Koshkonong and have acquired 200 MWs of capacity in West Riverside. See Note 2, Acquisitions, for more information on the West Riverside acquisitions. OCPP Units 7 and 8 are expected to be retired by late 2025. The total net book value of our ownership share of OCPP Units 7 and 8 was $675.8 million at June 30, 2024, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

v3.24.2

ASSET RETIREMENT OBLIGATIONS	6 Months Ended
	Jun. 30, 2024
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; and the closure of CCR landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the PSCW. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs: (in millions) 2024 2023 Balance at January 1 $ 73.1  $ 71.7  Accretion 1.0  0.9  Additions 34.0  (1) —  Balance at June 30 $ 108.1  $ 72.6  (1)    AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 21, Commitments and Contingencies, for more information.

v3.24.2

COMMON EQUITY	6 Months Ended
	Jun. 30, 2024
Equity [Abstract]
COMMON EQUITY	COMMON EQUITY Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 11, Common Equity, in our 2023 Annual Report on Form 10-K for additional information on these and other restrictions. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

v3.24.2

SHORT-TERM DEBT AND LINES OF CREDIT	6 Months Ended
	Jun. 30, 2024
Short-Term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) June 30, 2024 December 31, 2023 Commercial paper Amount outstanding $ 200.5  $ 360.8  Weighted-average interest rate on amounts outstanding 5.44  % 5.48  % Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2024 was $220.0 million with a weighted-average interest rate during the period of 5.46%. The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility: (in millions) Maturity June 30, 2024 Revolving credit facility September 2026 $ 500.0  Less:   Letters of credit issued inside credit facility 1.0  Commercial paper outstanding   200.5  Available capacity under existing credit facility   $ 298.5

v3.24.2

LONG-TERM DEBT	6 Months Ended
	Jun. 30, 2024
Long-Term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT In May 2024, we issued $350.0 million of 5.00% Debentures, due May 15, 2029, and used the net proceeds to repay short-term debt and for other general corporate purposes.

v3.24.2

LEASES	6 Months Ended
	Jun. 30, 2024
Lessee Disclosure [Abstract]
LEASES	LEASES On July 30, 2024, we, along with WPS, partnered with an unaffiliated utility to acquire and construct Koshkonong, a utility-scale solar-powered electric generating facility located in Dane County, Wisconsin. Once fully constructed, we will own 225 MWs of solar generation. Related to our investment in Koshkonong, we, WPS, and our unaffiliated utility partner, entered into several land leases that commenced in the third quarter of 2024. We are currently evaluating the impact these leases will have on our financial statements and related disclosures.

v3.24.2

MATERIALS, SUPPLIES, AND INVENTORIES	6 Months Ended
	Jun. 30, 2024
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	MATERIALS, SUPPLIES, AND INVENTORIES Our inventories consisted of: (in millions) June 30, 2024 December 31, 2023 Materials and supplies $ 205.4  $ 186.6  Fossil fuel 62.3  74.5  Natural gas in storage 37.7  49.5  Total $ 305.4  $ 310.6  Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.

v3.24.2

INCOME TAXES	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 22.8  21.0  % $ 30.7  21.0  % State income taxes net of federal tax benefit 6.5  6.0  % 8.7  6.0  % Federal excess deferred tax amortization (3.5) (3.2) % (4.7) (3.2) % PTCs, net (3.1) (2.9) % (1.8) (1.2) % AFUDC–Equity (1.9) (1.7) % (1.9) (1.3) % Domestic production activities deferral 1.1  1.0  % 1.4  1.0  % Other, net 1.7  1.4  % 1.9  1.2  % Total income tax expense $ 23.6  21.6  % $ 34.3  23.5  % Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 58.5  21.0  % $ 63.1  21.0  % State income taxes net of federal tax benefit 16.5  5.9  % 18.0  6.0  % Federal excess deferred tax amortization (9.2) (3.3) % (10.0) (3.3) % PTCs, net (8.2) (3.0) % (6.9) (2.3) % AFUDC–Equity (5.1) (1.8) % (4.1) (1.4) % Domestic production activities deferral 2.8  1.0  % 3.0  1.0  % Other, net 4.1  1.5  % 3.9  1.3  % Total income tax expense $ 59.4  21.3  % $ 67.0  22.3  % The effective tax rates for the three and six months ended June 30, 2024, do not materially differ from the United States statutory federal income tax rate of 21%. This is primarily due to the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs, offset by state income taxes. The effective tax rates for the three and six months ended June 30, 2023, differ from the United States statutory federal income tax rate of 21%, primarily due to state income taxes. This item was partially offset by the impact of the protected deferred tax benefits associated with the Tax Legislation, as discussed in more detail below. The Tax Legislation required us to remeasure the deferred income taxes at our utility segment, and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization lines above). See Note 24, Regulatory Environment, in our 2023 Annual Report on Form 10-K for more information about the impact of the Tax Legislation. The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023 and May 2024, under this transferability provision, WEC Energy Group entered into agreements to sell substantially all of the PTCs we generated in 2023 and substantially all of the PTCs expected to be generated in 2024 to third parties. We elect to account for tax credits transferred under the scope of Accounting Standards Codification 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid. In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

v3.24.2

FAIR VALUE MEASUREMENTS	6 Months Ended
	Jun. 30, 2024
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative 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, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our FTRs are valued using MISO auction prices. The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: June 30, 2024 (in millions) Level 1 Level 2 Level 3 Total Derivative assets         Natural gas contracts $ 1.3  $ 1.0  $ —  $ 2.3  FTRs —  —  9.7  9.7  Total derivative assets $ 1.3  $ 1.0  $ 9.7  $ 12.0  Derivative liabilities Natural gas contracts $ 5.3  $ 0.8  $ —  $ 6.1  Coal contracts —  14.7  —  14.7  Total derivative liabilities $ 5.3  $ 15.5  $ —  $ 20.8  December 31, 2023 (in millions) Level 1 Level 2 Level 3 Total Derivative assets         Natural gas contracts $ 0.9  $ 1.3  $ —  $ 2.2  FTRs —  —  2.5  2.5  Total derivative assets $ 0.9  $ 1.3  $ 2.5  $ 4.7  Derivative liabilities Natural gas contracts $ 16.1  $ 3.1  $ —  $ 19.2  Coal contracts —  19.3  —  19.3  Total derivative liabilities $ 16.1  $ 22.4  $ —  $ 38.5  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 to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Balance at the beginning of the period $ 1.0  $ 0.8  $ 2.5  $ 2.0  Purchases 12.1  8.1  12.1  8.1  Settlements (3.4) (2.0) (4.9) (3.2) Balance at the end of the period $ 9.7  $ 6.9  $ 9.7  $ 6.9  Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: June 30, 2024 December 31, 2023 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4  $ 21.2  $ 30.4  $ 21.4  Long-term debt, including current portion 3,697.9  3,529.0  3,354.4  3,255.4  The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

v3.24.2

DERIVATIVE INSTRUMENTS	6 Months Ended
	Jun. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. 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, the PSCW allows 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 are designated as hedging instruments. June 30, 2024 December 31, 2023 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 2.3  $ 5.9  $ 2.2  $ 18.6  FTRs 9.7  —  2.5  —  Coal contracts —  10.0  —  10.2  Total current 12.0  15.9  4.7  28.8  Long-term Natural gas contracts —  0.2  —  0.6  Coal contracts —  4.7  —  9.1  Total long-term —  4.9  —  9.7  Total $ 12.0  $ 20.8  $ 4.7  $ 38.5  Realized gains and losses on derivatives are primarily 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 fuel and natural gas cost recovery mechanisms. Our estimated notional sales volumes and realized gains and losses were as follows: Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 16.3 Dth $ (9.4) 17.0 Dth $ (25.3) FTRs 5.1 MWh 1.4  5.2 MWh 1.9  Total $ (8.0) $ (23.4) Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 39.2 Dth $ (26.4) 35.9 Dth $ (54.5) FTRs 10.0 MWh 3.3  10.1 MWh 2.0  Total   $ (23.1)   $ (52.5) On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At June 30, 2024 and December 31, 2023, we had posted cash collateral of $13.9 million and $26.7 million, respectively. These amounts were recorded on our balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: June 30, 2024 December 31, 2023 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 12.0  $ 20.8  $ 4.7  $ 38.5  Gross amount not offset on the balance sheet (1.4) (5.5) (1) (1.3) (16.5) (2) Net amount $ 10.6  $ 15.3  $ 3.4  $ 22.0  (1)    Includes cash collateral posted of $4.1 million. (2)    Includes cash collateral posted of $15.2 million.

v3.24.2

GUARANTEES	6 Months Ended
	Jun. 30, 2024
Guarantees [Abstract]
GUARANTEES	GUARANTEES As of June 30, 2024, we had $26.0 million of standby letters of credit issued by financial institutions for the benefit of third parties that have extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.

v3.24.2

EMPLOYEE BENEFITS	6 Months Ended
	Jun. 30, 2024
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	EMPLOYEE BENEFITS The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans. Pension Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 2.4  $ 2.3  $ 5.2  $ 5.1  Interest cost 11.0  11.7  22.3  23.6  Expected return on plan assets (15.2) (15.8) (30.8) (32.2) Amortization of net actuarial loss 4.7  2.7  9.0  4.6  Net periodic benefit cost $ 2.9  $ 0.9  $ 5.7  $ 1.1  OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 0.8  $ 0.6  $ 1.6  $ 1.3  Interest cost 2.0  1.9  4.1  3.8  Expected return on plan assets (2.8) (3.3) (5.5) (6.7) Amortization of prior service credit —  (0.2) (0.1) (0.4) Amortization of net actuarial gain (1.4) (2.2) (2.8) (4.4) Net periodic benefit credit $ (1.4) $ (3.2) $ (2.7) $ (6.4) During the six months ended June 30, 2024, we made contributions and payments of $3.3 million related to our pension plans and an insignificant amount related to our OPEB plans. We expect to make contributions and payments of $0.2 million related to our OPEB plans and an insignificant amount related to our pension plans during the remainder of 2024, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs. As a result, as of June 30, 2024, we recorded a $4.3 million regulatory asset for pension costs and an $11.5 million regulatory asset for OPEB costs. The above tables do not reflect any adjustments for the creation of these regulatory assets.

v3.24.2

SEGMENT INFORMATION	6 Months Ended
	Jun. 30, 2024
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION We use net income attributed to common shareholder to measure segment profitability and to allocate resources to our business. At June 30, 2024, we reported two segments, our utility segment and our other segment, which are described below. Our utility segment includes our electric utility operations, including steam operations, and our natural gas utility operations. •Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee. •Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin. No significant items were reported in the other segment during the three and six months ended June 30, 2024 and 2023. All of our operations and assets are located within the United States.

v3.24.2

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES The primary beneficiary of a VIE must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in VIEs. We assess our relationships with potential VIEs, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. WEPCo Environmental Trust Finance I, LLC In November 2020, the PSCW issued a financing order approving the securitization of $100 million of undepreciated environmental control costs related to our 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 us 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 our wholly owned subsidiary. In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from us. 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 our retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders do not have any recourse to us or any of our affiliates. We act as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and are responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, we are 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 remit 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 have the power to direct the activities that most significantly impact WEPCo Environmental Trust's economic performance. Therefore, we are considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required. The following table summarizes the impact of WEPCo Environmental Trust on our balance sheets: (in millions) June 30, 2024 December 31, 2023 Assets Other current assets (restricted cash) $ 0.3  $ 0.8  Regulatory assets 82.3  85.9  Other long-term assets (restricted cash) 0.3  0.6  Liabilities Current portion of long-term debt 9.1  9.0  Accounts payable 0.1  —  Other current liabilities (accrued interest) 0.1  0.1  Long-term debt 80.9  85.3

v3.24.2

COMMITMENTS AND CONTINGENCIES	6 Months Ended
	Jun. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES We 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 We have obligations to distribute and sell electricity and natural gas to our customers and 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. Our minimum future commitments related to these purchase obligations as of June 30, 2024, were approximately $7.1 billion. Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. Air Quality Cross State Air Pollution Rule – Good Neighbor Rule In March 2023, the EPA issued its final Good Neighbor Rule, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. After review of the final rule, we are well positioned to meet the requirements. Our RICE units are not currently subject to the final rule as each unit is less than 25 MWs. To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026. The EPA has exempted LDCs from the final rule. In February 2024, the Supreme Court heard oral arguments regarding stay applications related to the EPA's Good Neighbor Rule. In June 2024, the Supreme Court granted a stay of the Good Neighbor Rule pending disposition of the applicants' petitions for review at the D.C. Circuit Court of Appeals. We will continue to monitor this case as arguments at the D.C. Circuit Court of Appeals move forward. Mercury and Air Toxics Standards In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants. In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units. In May 2024, the EPA published a final rule in the Federal Register lowering the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu. After review of the final rule, we believe we are well positioned to meet its requirements. National Ambient Air Quality Standards Ozone After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting the reconsideration of the 2015 standard. The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration; however, in August 2023, the EPA announced that it is instead restarting its ozone standard evaluation. The EPA has indicated it plans to release its Integrated Review Plan in fall 2024. This new review is anticipated to take 3 to 5 years to complete. In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized. The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard. The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023. The effective date for the initial nonattainment area designation was August 2018 and the attainment status is evaluated every 3 years thereafter until attainment is achieved. The Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021, so in April 2022 the EPA proposed "moderate" nonattainment status for the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022. Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status. In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit adequate SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard. This action triggered a May 2025 deadline for states to get their SIP approved or the EPA will issue a federal implementation plan. Additionally, offset sanctions will take effect 18 months from the May 2025 deadline if the SIP is not approved. The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas. The WDNR intends to submit a SIP revision by the May 2025 deadline. The next attainment evaluation date is August 2024. If the moderate attainment deadline is not met, the EPA will propose the nonattainment areas in Wisconsin be redesignated as serious nonattainment based on 2021-2023 data. We are currently evaluating what, if any, impacts the potential nonattainment redesignation will have on our operations. Particulate Matter All counties within our service territory are in attainment with current 2012 standards for fine PM2.5. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from a December 2020 review of the 2012 standards supported revising the level of the annual standard for the PM2.5 NAAQS to below the current level of 12 µg/m3, while retaining the 24-hour standard of 35 µg/m3. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS to 9 µg/m3. The secondary (welfare-based) PM2.5 standard and 24-hour standards (both primary and secondary) remain unchanged. The EPA has until May 2026 to designate areas as attainment and nonattainment with the new standard. The WDNR will need to draft and submit a SIP for the EPA's approval. A designation of nonattainment status could impact future permitting activities for facilities in applicable locations, including the potential need for improved or new air pollution control equipment. With our planned transition from coal-fired plants to natural gas-fired plants and renewable generating facilities, we do not expect this new standard to have a material impact on our units. Climate Change In May 2023, the EPA proposed GHG performance standards for fossil-fired steam generating and natural gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan. The final rule, known as the Greenhouse Gas Power Plant Rule, was published in May 2024. Pursuant to the final rule, there are no applicable standards for coal plants until the end of 2031 and after 2031, the applicable standard is dependent upon the unit's retirement date. Coal-fired units that are planned to refuel to natural gas-fired units must convert to natural gas and no longer retain the capability to burn coal by the end of 2029. For new combined cycle natural gas plants above a 40% capacity factor, the rule is dependent upon the implementation of carbon capture by the end of 2031. For new simple cycle natural gas-fired combustion turbines, there are no applicable limits as long as the capacity factor is less than 20%. Our new Weston RICE units are not affected under the rule because the rule excludes RICE units that are less than 25 MWs. Numerous parties have challenged the Greenhouse Gas Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals. In March 2024, the EPA announced it had removed regulations on existing natural gas combustion turbines from the rule. The EPA indicated that it intends to draft a new rule for existing natural gas-fired units and opened a non-regulatory docket for this new rulemaking. The EPA has stated it anticipates a proposed rule by the end of 2024. In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98, which includes updates to the global warming potentials to determine CO2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. The revisions will impact the reporting required for our electric generation facilities, LDCs, and underground natural gas storage facilities. In May 2024, the EPA also issued its final rule to amend reporting requirements for petroleum and natural gas systems. Under the final rule, new leak emission factors and reporting requirements for large release events will impact the reporting required for our LDCs and underground natural gas storage facilities. The ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation. We have already retired nearly 2,100 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the Presque Isle Power Plant, and the 2018 retirement of the Pleasant Prairie Power Plant. WEC Energy Group expects to retire approximately 1,200 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8 in late 2025. See Note 7, Property, Plant, and Equipment, for more information related to planned power plant retirements. In May 2021, WEC Energy Group announced goals to achieve reductions in carbon emissions from its electric generation fleet by 60% by the end of 2025 and by 80% by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing its capital plan. Over the longer term, the target for WEC Energy Group's generation fleet is to be net carbon neutral by 2050. WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution systems, and has set a target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030. WEC Energy Group plans to achieve its net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout its natural gas utility distribution systems. Water Quality Clean Water Act Cooling Water Intake Structure Rule Section 316(b) of the CWA became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts. The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities. Effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code. The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into WPDES permits for our facilities. We have received interim BTA determinations for all generation facilities where Section 316(b) is applicable. With respect to OCPP Units 7 and 8, we believe the WDNR will determine that existing technology (wet cooling towers) installed at the units represents BTA for minimizing adverse environmental impacts in accordance with the requirements in the CWA when the WPDES permit for those units is reissued, which is expected in 2025. Steam Electric Effluent Limitation Guidelines The EPA's final ELG rule, which took effect in January 2016 ("2015 ELG rule"), was modified in 2020 ("2020 ELG rule"), and again in 2024 with the May 2024 publication of the Supplemental ELG Rule. These rules establish federal technology-based requirements for several types of power plant wastewaters. The three requirements that affect us relate to discharge limits for BATW, FGD wastewater, and CRL (landfill leachate). Although our coal-fueled facilities were constructed with advanced wastewater treatment technologies that meet many of the discharge limits established by the 2015 rule, facility modifications were still necessary at OCPP and ERGS to meet all of the 2015 ELG requirements and the additional ones established by the 2020 ELG rule. Through 2023, compliance costs associated with the 2015 and 2020 ELG rules required $97 million in capital investment. The 2024 Supplemental ELG rule established zero discharge requirements for BATW, FGD, and CRL wastewaters at coal-fueled units with no planned retirement date. The Supplemental ELG Rule also kept one existing and created one new “permanent cessation of coal” subcategory. Those electing to cease coal combustion by either retiring or repowering a unit by December 31, 2028 or December 31, 2034 can limit ELG-related capital investments to what was required by either the 2015 or the 2020 ELG Rule, respectively. For units where cessation of coal is planned to occur no later than December 31, 2034, facility owners must complete all 2020 ELG rule required capital investments by December 31, 2025. All of our coal-fueled units fully meet the 2020 ELG rule requirements. Based on current electrical generation resource planning, we plan to file a Notice of Planned Participation by December 31, 2025 to opt into the "cessation of coal by December 31, 2034" subcategory for the ERGS coal-fueled facility. The final Supplemental ELG Rule allows owners of coal-fueled units who opted into a cessation of coal subcategory to operate beyond the end of 2028 or 2034, required by either the 2015 or the 2020 ELG Rule, respectively, if needed for reliability concerns (i.e., energy emergencies, reliability must run agreements, etc.) as determined by the United States Department of Energy, a public utility commission, or independent system operator. We are still evaluating the Supplemental ELG Rule CRL provisions to determine the applicability and potential compliance costs for inactive/closed landfills. Numerous parties have challenged the rule through litigation pending in the U.S. Court of Appeals for the 8th Circuit. Land Quality Manufactured Gas Plant Remediation We have identified sites at which we 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. We are responsible for the environmental remediation of these sites. We are also working with the state of Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves for manufactured gas plant sites: (in millions) June 30, 2024 December 31, 2023 Regulatory assets $ 11.2  $ 12.2  Reserves for future environmental remediation (1) 10.3  10.3  (1)Recorded within other long-term liabilities on our balance sheets. Coal Combustion Residuals Rule The EPA finalized a rule for CCR in April 2024 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site. The rule will regulate previously exempt closed landfills. We expect the final rule, which will become effective in November 2024, to have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. We expect the cost of the additional remediation would be recovered through future rates. See Note 8, Asset Retirement Obligations, for more information on the estimated cost of the additional remediation. Enforcement and Litigation Matters We 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.

v3.24.2

SUPPLEMENTAL CASH FLOW INFORMATION	6 Months Ended
	Jun. 30, 2024
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION Non-Cash Transactions Six Months Ended June 30 (in millions) 2024 2023 Cash paid for interest, net of amount capitalized $ 236.9  $ 233.5  Cash paid for income taxes, net (1) 59.9  65.0  Significant non-cash investing and financing transactions: Accounts payable related to construction costs 102.6  61.0  (1)    Cash paid for income taxes in 2024 was net of $10.7 million related to 2023 and 2024 PTCs that were sold to third parties. Restricted Cash The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) June 30, 2024 December 31, 2023 Cash and cash equivalents $ —  $ 6.1  Restricted cash included in other current assets 0.3  0.8  Restricted cash included in other long-term assets 0.3  0.6  Cash, cash equivalents, and restricted cash $ 0.6  $ 7.5  Our restricted cash consisted of cash on deposit in a financial institution that is restricted to satisfy the requirements of a debt agreement at WEPCo Environmental Trust. See Note 20, Variable Interest Entities, for more information.

v3.24.2

REGULATORY ENVIRONMENT	6 Months Ended
	Jun. 30, 2024
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT 2025 and 2026 Rate Case On April 12, 2024, we filed a request with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2025 and January 1, 2026, as applicable. The request reflected the following: Proposed 2025 rate increase Electric $ 240.7   million / 6.9% Gas $ 57.5   million / 10.0% Steam $ 2.5   million / 8.4% Proposed 2026 rate increase (1) Electric $ 177.9   million / 4.6% Gas $ 31.0   million / 4.6% Proposed ROE 10.0% Proposed common equity component average on a financial basis 53.5% (1)    The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025. The primary drivers of the requested increases in electric rates are continued capital investments to transition our generation fleet from coal to renewables and natural gas-fueled generation, increased costs driven by higher inflation and interest rates, and the recovery of regulatory assets previously approved by the PSCW. The requested increases in natural gas rates are driven by our ongoing capital investments in reliability and safety projects, including LNG storage facilities, as well as the impacts from higher inflation and increased interest rates. We also proposed retaining our current earnings sharing mechanism. Under the current earnings sharing mechanism, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii) 50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii) 100.0% of any remaining excess earnings is required to be refunded to ratepayers. A decision is expected in the fourth quarter of 2024, with any rate adjustments expected to be effective January 1, 2025 and 2026.

v3.24.2

NEW ACCOUNTING PRONOUNCEMENTS	6 Months Ended
	Jun. 30, 2024
Accounting Changes and Error Corrections [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures. Improvements to Reportable Segment Disclosures In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The amendments require additional disclosures about reportable segments on an annual and interim basis. The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss. The amendments also require disclosure of an amount for other segment items and a description of its composition. The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

v3.24.2

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

v3.24.2

GENERAL INFORMATION (Policies)	6 Months Ended
	Jun. 30, 2024
Accounting policies
Consolidation	As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, 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 Wisconsin Electric Power Company and its subsidiary. On our financial statements, we consolidate VIEs of which we are the primary beneficiary.
Basis of accounting	We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2023. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and six months ended June 30, 2024, are not necessarily indicative of expected results for 2024 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.
Credit losses	Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are generated from the sale of electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at June 30, 2024 and December 31, 2023. 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 the PSCW, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk.
Income taxes	The IRA contains a tax credit transferability provision that allows us to sell PTCs produced after December 31, 2022, to third parties. In September 2023 and May 2024, under this transferability provision, WEC Energy Group entered into agreements to sell substantially all of the PTCs we generated in 2023 and substantially all of the PTCs expected to be generated in 2024 to third parties. We elect to account for tax credits transferred under the scope of Accounting Standards Codification 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs. The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid. In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures
Fair value measurements	Fair value 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 derivative 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, are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Our FTRs are valued using MISO auction prices.
Derivative instruments	We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. 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, the PSCW allows 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.

v3.24.2

OPERATING REVENUES (Tables) - Utility segment	6 Months Ended
	Jun. 30, 2024
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. 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. Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Wisconsin Electric Power Company Electric utility $ 831.4  $ 824.9  $ 1,677.6  $ 1,668.8  Natural gas utility 66.5  70.7  254.4  314.3  Total revenues from contracts with customers 897.9  895.6  1,932.0  1,983.1  Other operating revenues 4.1  4.7  8.8  9.1  Total operating revenues $ 902.0  $ 900.3  $ 1,940.8  $ 1,992.2
Revenues from contracts with customers | Electric
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following table disaggregates electric utility operating revenues into customer class: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Residential $ 347.9  $ 338.3  $ 707.9  $ 695.7  Small commercial and industrial 282.2  287.5  569.7  572.1  Large commercial and industrial 144.9  151.6  279.4  290.7  Other 4.9  4.8  10.5  10.5  Total retail revenues 779.9  782.2  1,567.5  1,569.0  Wholesale 13.7  10.3  24.7  22.0  Resale 32.3  26.6  68.8  60.0  Steam 4.7  4.7  14.8  15.7  Other utility revenues 0.8  1.1  1.8  2.1  Total electric utility operating revenues $ 831.4  $ 824.9  $ 1,677.6  $ 1,668.8
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	The following table disaggregates natural gas utility operating revenues into customer class: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Residential $ 38.0  $ 35.1  $ 173.9  $ 214.3  Commercial and industrial 13.9  13.0  75.0  100.9  Total retail revenues 51.9  48.1  248.9  315.2  Transportation 5.2  4.6  12.7  11.4  Other utility revenues (1) 9.4  18.0  (7.2) (12.3) Total natural gas utility operating revenues $ 66.5  $ 70.7  $ 254.4  $ 314.3  (1)Includes the revenues subject to our purchased gas recovery mechanism, which fluctuate based on actual natural gas costs incurred, compared with the recovery of natural gas costs that were anticipated in rates.
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	Other operating revenues consist primarily of the following: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Late payment charges $ 2.9  $ 3.3  $ 6.4  $ 7.0  Rental revenues 1.8  1.3  2.1  1.7  Alternative revenues (1) (0.6) 0.1  0.3  0.4  Total other operating revenues $ 4.1  $ 4.7  $ 8.8  $ 9.1  (1)Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to wholesale customers subject to true-ups. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2023 Annual Report on Form 10-K.

v3.24.2

CREDIT LOSSES (Tables)	6 Months Ended
	Jun. 30, 2024
Credit Loss [Abstract]
Schedule of gross receivables and related allowances for credit losses	We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses. (in millions) June 30, 2024 December 31, 2023 Accounts receivable and unbilled revenues $ 600.8  $ 617.5  Allowance for credit losses 42.0  44.5  Accounts receivable and unbilled revenues, net (1) $ 558.8  $ 573.0  Total accounts receivable, net – past due greater than 90 days (1) $ 39.2  $ 37.2  Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) 94.4  % 94.1  % (1)Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at June 30, 2024, $311.8 million, or 55.8%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.
Rollforward of the allowances for credit losses	A rollforward of the allowance for credit losses is included below: Three Months Ended June 30 (in millions) 2024 2023 Balance at April 1 $ 48.9  $ 53.7  Provision for credit losses 7.1  4.7  Provision for credit losses deferred for future recovery or refund 6.5  1.7  Write-offs charged against the allowance (26.5) (21.3) Recoveries of amounts previously written off 6.0  6.3  Balance at June 30 $ 42.0  $ 45.1  Six Months Ended June 30 (in millions) 2024 2023 Balance at January 1 $ 44.5  $ 49.7  Provision for credit losses 15.2  11.3  Provision for credit losses deferred for future recovery or refund 20.7  15.5  Write-offs charged against the allowance (51.5) (41.6) Recoveries of amounts previously written off 13.1  10.2  Balance at June 30 $ 42.0  $ 45.1  There was a $2.5 million decrease in the allowance for credit losses at June 30, 2024, compared to January 1, 2024, largely driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. The winter moratorium begins on November 1 and ends on April 15. Also contributing to the decrease in the allowance for credit losses, we have seen lower required reserve percentages as a result of an improvement in loss rates. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. There was a $4.6 million decrease in the allowance for credit losses at June 30, 2023, compared to January 1, 2023, driven by customer write-offs related to the winter moratorium months ending. After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance. Also contributing to the decrease in the allowance for credit losses, we believe that the lower energy costs that customers were seeing, which were driven by lower natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

v3.24.2

REGULATORY ASSETS AND LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	(in millions) June 30, 2024 December 31, 2023 Regulatory assets We Power finance leases $ 1,125.6  $ 1,109.7  Plant retirement related items (1) 675.3  595.5  Income tax related items 367.8  373.1  Pension and OPEB costs 352.1  348.9  System support resource 108.0  113.2  Uncollectible expense 82.8  62.1  Securitization 82.3  85.9  Asset retirement obligations 50.3  41.2  Derivatives 22.2  45.2  Energy efficiency programs 19.8  23.3  Bluewater Natural Gas Holding, LLC 19.8  17.2  Environmental remediation costs 11.2  12.2  Other, net 37.7  33.2  Total regulatory assets $ 2,954.9  $ 2,860.7  (1)    Included in plant retirement related items at June 30, 2024, are $19.5 million of capitalized retirement costs related to the new EPA CCR Rule that was enacted in April 2024. See Note 21, Commitments and Contingencies, for more information.
Schedule of regulatory liabilities	(in millions) June 30, 2024 December 31, 2023 Regulatory liabilities Removal costs $ 788.9  $ 758.9  Income tax related items 668.6  683.5  Pension and OPEB benefits 125.3  124.0  Energy costs refundable through rate adjustments 49.0  5.5  Electric transmission costs 25.2  23.9  Paris (1) 17.7  —  Other, net 46.2  40.9  Total regulatory liabilities $ 1,720.9  $ 1,636.7  Balance sheet presentation Other current liabilities $ 12.7  $ 5.3  Regulatory liabilities 1,708.2  1,631.4  Total regulatory liabilities $ 1,720.9  $ 1,636.7  (1)In accordance with our rate order approved by the PSCW in December 2023, we are deferring to a future rate proceeding the incremental revenue requirement impact associated with the change to the in-service date of Paris.

v3.24.2

ASSET RETIREMENT OBLIGATIONS (Tables)	6 Months Ended
	Jun. 30, 2024
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to asset retirement obligations	On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs: (in millions) 2024 2023 Balance at January 1 $ 73.1  $ 71.7  Accretion 1.0  0.9  Additions 34.0  (1) —  Balance at June 30 $ 108.1  $ 72.6  (1)    AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 21, Commitments and Contingencies, for more information.

v3.24.2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	6 Months Ended
	Jun. 30, 2024
Short-Term Debt [Abstract]
Schedule of short-term borrowings and weighted-average interest rates	The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) June 30, 2024 December 31, 2023 Commercial paper Amount outstanding $ 200.5  $ 360.8  Weighted-average interest rate on amounts outstanding 5.44  % 5.48  %
Schedule of revolving credit facility and remaining available capacity	The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility: (in millions) Maturity June 30, 2024 Revolving credit facility September 2026 $ 500.0  Less:   Letters of credit issued inside credit facility 1.0  Commercial paper outstanding   200.5  Available capacity under existing credit facility   $ 298.5

v3.24.2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	6 Months Ended
	Jun. 30, 2024
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventories consisted of: (in millions) June 30, 2024 December 31, 2023 Materials and supplies $ 205.4  $ 186.6  Fossil fuel 62.3  74.5  Natural gas in storage 37.7  49.5  Total $ 305.4  $ 310.6

v3.24.2

INCOME TAXES (Tables)	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
Schedule of effective income tax rate reconciliation	The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 22.8  21.0  % $ 30.7  21.0  % State income taxes net of federal tax benefit 6.5  6.0  % 8.7  6.0  % Federal excess deferred tax amortization (3.5) (3.2) % (4.7) (3.2) % PTCs, net (3.1) (2.9) % (1.8) (1.2) % AFUDC–Equity (1.9) (1.7) % (1.9) (1.3) % Domestic production activities deferral 1.1  1.0  % 1.4  1.0  % Other, net 1.7  1.4  % 1.9  1.2  % Total income tax expense $ 23.6  21.6  % $ 34.3  23.5  % Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 58.5  21.0  % $ 63.1  21.0  % State income taxes net of federal tax benefit 16.5  5.9  % 18.0  6.0  % Federal excess deferred tax amortization (9.2) (3.3) % (10.0) (3.3) % PTCs, net (8.2) (3.0) % (6.9) (2.3) % AFUDC–Equity (5.1) (1.8) % (4.1) (1.4) % Domestic production activities deferral 2.8  1.0  % 3.0  1.0  % Other, net 4.1  1.5  % 3.9  1.3  % Total income tax expense $ 59.4  21.3  % $ 67.0  22.3  %

v3.24.2

FAIR VALUE MEASUREMENTS (Tables)	6 Months Ended
	Jun. 30, 2024
Fair Value Disclosures [Abstract]
Schedule of fair value of assets and liabilities measured on a recurring basis categorized by level within the fair value hierarchy	The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: June 30, 2024 (in millions) Level 1 Level 2 Level 3 Total Derivative assets         Natural gas contracts $ 1.3  $ 1.0  $ —  $ 2.3  FTRs —  —  9.7  9.7  Total derivative assets $ 1.3  $ 1.0  $ 9.7  $ 12.0  Derivative liabilities Natural gas contracts $ 5.3  $ 0.8  $ —  $ 6.1  Coal contracts —  14.7  —  14.7  Total derivative liabilities $ 5.3  $ 15.5  $ —  $ 20.8  December 31, 2023 (in millions) Level 1 Level 2 Level 3 Total Derivative assets         Natural gas contracts $ 0.9  $ 1.3  $ —  $ 2.2  FTRs —  —  2.5  2.5  Total derivative assets $ 0.9  $ 1.3  $ 2.5  $ 4.7  Derivative liabilities Natural gas contracts $ 16.1  $ 3.1  $ —  $ 19.2  Coal contracts —  19.3  —  19.3  Total derivative liabilities $ 16.1  $ 22.4  $ —  $ 38.5
Reconciliation of changes in fair value of items categorized as level 3 measurements	The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Balance at the beginning of the period $ 1.0  $ 0.8  $ 2.5  $ 2.0  Purchases 12.1  8.1  12.1  8.1  Settlements (3.4) (2.0) (4.9) (3.2) Balance at the end of the period $ 9.7  $ 6.9  $ 9.7  $ 6.9
Schedule of carrying value and fair value of financial instruments not recorded at fair value	The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: June 30, 2024 December 31, 2023 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4  $ 21.2  $ 30.4  $ 21.4  Long-term debt, including current portion 3,697.9  3,529.0  3,354.4  3,255.4

v3.24.2

DERIVATIVE INSTRUMENTS (Tables)	6 Months Ended
	Jun. 30, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative assets and liabilities	The following table shows our derivative assets and derivative liabilities. None of the derivatives shown below are designated as hedging instruments. June 30, 2024 December 31, 2023 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Current Natural gas contracts $ 2.3  $ 5.9  $ 2.2  $ 18.6  FTRs 9.7  —  2.5  —  Coal contracts —  10.0  —  10.2  Total current 12.0  15.9  4.7  28.8  Long-term Natural gas contracts —  0.2  —  0.6  Coal contracts —  4.7  —  9.1  Total long-term —  4.9  —  9.7  Total $ 12.0  $ 20.8  $ 4.7  $ 38.5
Schedule of estimated notional volumes and realized gains and losses	Our estimated notional sales volumes and realized gains and losses were as follows: Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 16.3 Dth $ (9.4) 17.0 Dth $ (25.3) FTRs 5.1 MWh 1.4  5.2 MWh 1.9  Total $ (8.0) $ (23.4) Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 39.2 Dth $ (26.4) 35.9 Dth $ (54.5) FTRs 10.0 MWh 3.3  10.1 MWh 2.0  Total   $ (23.1)   $ (52.5)
Schedule of net derivative instruments	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: June 30, 2024 December 31, 2023 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 12.0  $ 20.8  $ 4.7  $ 38.5  Gross amount not offset on the balance sheet (1.4) (5.5) (1) (1.3) (16.5) (2) Net amount $ 10.6  $ 15.3  $ 3.4  $ 22.0  (1)    Includes cash collateral posted of $4.1 million. (2)    Includes cash collateral posted of $15.2 million.

v3.24.2

EMPLOYEE BENEFITS (Tables)	6 Months Ended
	Jun. 30, 2024
Retirement Benefits [Abstract]
Schedule of net benefit cost (credit)	The following tables show the components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for our benefit plans. Pension Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 2.4  $ 2.3  $ 5.2  $ 5.1  Interest cost 11.0  11.7  22.3  23.6  Expected return on plan assets (15.2) (15.8) (30.8) (32.2) Amortization of net actuarial loss 4.7  2.7  9.0  4.6  Net periodic benefit cost $ 2.9  $ 0.9  $ 5.7  $ 1.1  OPEB Benefits Three Months Ended June 30 Six Months Ended June 30 (in millions) 2024 2023 2024 2023 Service cost $ 0.8  $ 0.6  $ 1.6  $ 1.3  Interest cost 2.0  1.9  4.1  3.8  Expected return on plan assets (2.8) (3.3) (5.5) (6.7) Amortization of prior service credit —  (0.2) (0.1) (0.4) Amortization of net actuarial gain (1.4) (2.2) (2.8) (4.4) Net periodic benefit credit $ (1.4) $ (3.2) $ (2.7) $ (6.4)

v3.24.2

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

v3.24.2

COMMITMENTS AND CONTINGENCIES (Tables)	6 Months Ended
	Jun. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of regulatory assets and reserves related to manufactured gas plant sites	We have established the following regulatory assets and reserves for manufactured gas plant sites: (in millions) June 30, 2024 December 31, 2023 Regulatory assets $ 11.2  $ 12.2  Reserves for future environmental remediation (1) 10.3  10.3  (1)Recorded within other long-term liabilities on our balance sheets.

v3.24.2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2024
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Schedule of supplemental cash flow information	Six Months Ended June 30 (in millions) 2024 2023 Cash paid for interest, net of amount capitalized $ 236.9  $ 233.5  Cash paid for income taxes, net (1) 59.9  65.0  Significant non-cash investing and financing transactions: Accounts payable related to construction costs 102.6  61.0  (1)    Cash paid for income taxes in 2024 was net of $10.7 million related to 2023 and 2024 PTCs that were sold to third parties.
Reconciliation of cash, cash equivalents, and restricted cash	The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows: (in millions) June 30, 2024 December 31, 2023 Cash and cash equivalents $ —  $ 6.1  Restricted cash included in other current assets 0.3  0.8  Restricted cash included in other long-term assets 0.3  0.6  Cash, cash equivalents, and restricted cash $ 0.6  $ 7.5

v3.24.2

REGULATORY ENVIRONMENT (Tables)	6 Months Ended
	Jun. 30, 2024
Regulated Operations [Abstract]
Schedule of rate requests	The request reflected the following: Proposed 2025 rate increase Electric $ 240.7   million / 6.9% Gas $ 57.5   million / 10.0% Steam $ 2.5   million / 8.4% Proposed 2026 rate increase (1) Electric $ 177.9   million / 4.6% Gas $ 31.0   million / 4.6% Proposed ROE 10.0% Proposed common equity component average on a financial basis 53.5% (1)    The proposed 2026 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2025.

v3.24.2

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Jun. 30, 2024 customer
Electric
Product Information [Line Items]
Number Of Customers	1.2
Natural gas
Product Information [Line Items]
Number Of Customers	0.5

v3.24.2

ACQUISITIONS - WEST RIVERSIDE (Details) - West Riverside Energy Center $ in Millions	1 Months Ended
	May 31, 2024 USD ($) MW
Asset Acquisition
Capacity of generation unit (in megawatts) | MW	100
Acquisition purchase price | $	$ 98.2
Share of capacity (in megawatts) | MW	200
Ownership (as a percentage)	27.50%
Asset acquisition, total consideration transferred | $	$ 193.5

v3.24.2

ACQUISITIONS - WHITEWATER (Details) - Whitewater cogeneration facility $ in Millions	1 Months Ended
	Jan. 31, 2023 USD ($)	Jan. 01, 2023 MW
Asset Acquisition
Capacity of generation unit (in megawatts) | MW		236.5
Acquisition purchase price | $	$ 38.0
Ownership (as a percentage)		50.00%

v3.24.2

DISPOSITION (Details) $ in Millions	3 Months Ended
	Jun. 30, 2023 USD ($) a
Discontinued Operations and Disposal Groups [Abstract]
Number of Acres Sold | a	192
Proceeds from sale of real estate	$ 23.0
Pre-tax gain on sale of real estate	$ 22.2

v3.24.2

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES FOR UTILITY SEGMENT (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Total operating revenues	$ 902.0	$ 900.3	$ 1,940.8	$ 1,992.2
Utility segment
Disaggregation of Operating Revenues
Total operating revenues	902.0	900.3	1,940.8	1,992.2
Utility segment | Other operating revenues
Disaggregation of Operating Revenues
Other operating revenues	4.1	4.7	8.8	9.1
Utility segment | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	897.9	895.6	1,932.0	1,983.1
Utility segment | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	831.4	824.9	1,677.6	1,668.8
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 66.5	$ 70.7	$ 254.4	$ 314.3

v3.24.2

OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 897.9	$ 895.6	$ 1,932.0	$ 1,983.1
Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	831.4	824.9	1,677.6	1,668.8
Electric | Total retail
Disaggregation of Operating Revenues
Revenues from contracts with customers	779.9	782.2	1,567.5	1,569.0
Electric | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	347.9	338.3	707.9	695.7
Electric | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	282.2	287.5	569.7	572.1
Electric | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	144.9	151.6	279.4	290.7
Electric | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.9	4.8	10.5	10.5
Electric | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	13.7	10.3	24.7	22.0
Electric | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	32.3	26.6	68.8	60.0
Electric | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.7	4.7	14.8	15.7
Electric | Other utility
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 0.8	$ 1.1	$ 1.8	$ 2.1

v3.24.2

OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 897.9	$ 895.6	$ 1,932.0	$ 1,983.1
Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	66.5	70.7	254.4	314.3
Natural gas | Total retail
Disaggregation of Operating Revenues
Revenues from contracts with customers	51.9	48.1	248.9	315.2
Natural gas | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	38.0	35.1	173.9	214.3
Natural gas | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	13.9	13.0	75.0	100.9
Natural gas | Transportation
Disaggregation of Operating Revenues
Revenues from contracts with customers	5.2	4.6	12.7	11.4
Natural gas | Other utility
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 9.4	$ 18.0	$ (7.2)	$ (12.3)

v3.24.2

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - Utility segment - Other operating revenues - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Operating Revenues
Other operating revenues	$ 4.1	$ 4.7	$ 8.8	$ 9.1
Late payment charges
Disaggregation of Operating Revenues
Other operating revenues	2.9	3.3	6.4	7.0
Rental revenues
Disaggregation of Operating Revenues
Other operating revenues	1.8	1.3	2.1	1.7
Alternative revenues
Disaggregation of Operating Revenues
Other operating revenues	$ (0.6)	$ 0.1	$ 0.3	$ 0.4

v3.24.2

CREDIT LOSSES - GROSS RECEIVABLES AND RELATED ALLOWANCES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022
Utility segment
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 600.8		$ 617.5
Allowance for credit losses	42.0	$ 48.9	44.5	$ 45.1	$ 53.7	$ 49.7
Accounts receivable and unbilled revenues, net	558.8		573.0
Total accounts receivable, net - past due greater than 90 days	$ 39.2		$ 37.2
Past due greater than 90 days - collection risk mitigated by regulatory mechanisms	94.40%		94.10%
Amount of net accounts receivable with regulatory protections	$ 311.8
Percent of net accounts receivable with regulatory protections	55.80%
Other Segment
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable and unbilled revenues	$ 0.0		$ 0.0

v3.24.2

CREDIT LOSSES - ROLLFORWARD OF ALLOWANCES (Details) - Utility segment - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at beginning of period	$ 48.9	$ 53.7	$ 44.5	$ 49.7
Provision for credit losses	7.1	4.7	15.2	11.3
Write-offs charged against the allowance	(26.5)	(21.3)	(51.5)	(41.6)
Recovery of amounts previously written off	6.0	6.3	13.1	10.2
Balance at end of period	42.0	45.1	42.0	45.1
Change in allowance for credit losses			2.5	4.6
Uncollectible expense
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Provision for credit losses deferred for future recovery or refund	$ 6.5	$ 1.7	$ 20.7	$ 15.5

v3.24.2

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Regulatory assets
Total regulatory assets	$ 2,954.9	$ 2,860.7
We Power finance leases
Regulatory assets
Total regulatory assets	1,125.6	1,109.7
Plant retirement related items
Regulatory assets
Total regulatory assets	675.3	595.5
Plant retirement related items | Coal Combustion Residuals Rule
Regulatory assets
Total regulatory assets	19.5
Income tax related items
Regulatory assets
Total regulatory assets	367.8	373.1
Pension and OPEB costs
Regulatory assets
Total regulatory assets	352.1	348.9
System support resource
Regulatory assets
Total regulatory assets	108.0	113.2
Uncollectible expense
Regulatory assets
Total regulatory assets	82.8	62.1
Securitization
Regulatory assets
Total regulatory assets	82.3	85.9
Asset retirement obligations
Regulatory assets
Total regulatory assets	50.3	41.2
Derivatives
Regulatory assets
Total regulatory assets	22.2	45.2
Energy efficiency programs
Regulatory assets
Total regulatory assets	19.8	23.3
Bluewater Natural Gas Holding, LLC
Regulatory assets
Total regulatory assets	19.8	17.2
Environmental remediation costs
Regulatory assets
Total regulatory assets	11.2	12.2
Other, net
Regulatory assets
Total regulatory assets	$ 37.7	$ 33.2

v3.24.2

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Regulatory liabilities
Other current liabilities	$ 12.7	$ 5.3
Regulatory liabilities	1,708.2	1,631.4
Total regulatory liabilities	1,720.9	1,636.7
Removal costs
Regulatory liabilities
Total regulatory liabilities	788.9	758.9
Income tax related items
Regulatory liabilities
Total regulatory liabilities	668.6	683.5
Pension and OPEB benefits
Regulatory liabilities
Total regulatory liabilities	125.3	124.0
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	49.0	5.5
Electric transmission costs
Regulatory liabilities
Total regulatory liabilities	25.2	23.9
Paris
Regulatory liabilities
Total regulatory liabilities	17.7	0.0
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 46.2	$ 40.9

v3.24.2

REGULATORY ASSETS AND LIABILITIES - PLANT RETIREMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Oak Creek Power Plant Units 5 and 6
Regulatory assets	$ 2,954.9	$ 2,860.7
Regulatory liability	1,720.9	1,636.7
Removal costs
Oak Creek Power Plant Units 5 and 6
Regulatory liability	788.9	758.9
Plant retirement related items
Oak Creek Power Plant Units 5 and 6
Regulatory assets	675.3	$ 595.5
Oak Creek Power Plant Units 5 and 6
Oak Creek Power Plant Units 5 and 6
Deferred tax liabilities	9.4
Oak Creek Power Plant Units 5 and 6 | Removal costs
Oak Creek Power Plant Units 5 and 6
Regulatory liability	43.9
Oak Creek Power Plant Units 5 and 6 | Plant retirement related items
Oak Creek Power Plant Units 5 and 6
Regulatory assets	$ 78.3

v3.24.2

PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	Jun. 30, 2024 USD ($)	May 31, 2024 MW
OCPP
Property, plant, and equipment
Net book value of plant to be retired | $	$ 675.8
West Riverside Energy Center
Property, plant, and equipment
Share of capacity (in megawatts) | MW		200

v3.24.2

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Balance at January 1	$ 73.1	$ 71.7
Accretion	1.0	0.9
Additions	34.0	0.0
Balance at June 30	$ 108.1	$ 72.6

v3.24.2

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Short-term borrowings
Commercial paper outstanding	$ 200.5	$ 360.8
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 200.5	$ 360.8
Weighted-average interest rate on amounts outstanding	5.44%	5.48%
Average amount outstanding during the period	$ 220.0
Weighted-average interest rate during the period	5.46%

v3.24.2

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Revolving credit facility
Commercial paper outstanding	$ 200.5	$ 360.8
Available capacity under existing credit facility	298.5
Credit facility maturing September 2026
Revolving credit facility
Revolving credit facility	500.0
Commercial paper
Revolving credit facility
Commercial paper outstanding	200.5	$ 360.8
Letter of Credit
Revolving credit facility
Letters of credit issued inside credit facility	$ 1.0

v3.24.2

LONG-TERM DEBT (Details) - 5.00% WE Debentures due 05/15/2029 $ in Millions	1 Months Ended
	May 31, 2024 USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of debt	$ 350.0
Interest rate on long-term debt	5.00%

v3.24.2

LEASES - KOSHKONONG (Details)	Jul. 30, 2024 MW
Koshkonong Solar Park | Subsequent event
Leases
Jointly owned utility plant, proportionate ownership share of solar capacity	225

v3.24.2

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Inventory Disclosure [Abstract]
Materials and supplies	$ 205.4	$ 186.6
Fossil fuel	62.3	74.5
Natural gas in storage	37.7	49.5
Total	$ 305.4	$ 310.6

v3.24.2

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount	$ 22.8	$ 30.7	$ 58.5	$ 63.1
State income taxes net of federal tax benefit, amount	6.5	8.7	16.5	18.0
Federal excess deferred tax amortization, amount	(3.5)	(4.7)	(9.2)	(10.0)
PTCs, amount	(3.1)	(1.8)	(8.2)	(6.9)
AFUDC-Equity, amount	(1.9)	(1.9)	(5.1)	(4.1)
Domestic production activities deferral, amount	1.1	1.4	2.8	3.0
Other, net, amount	1.7	1.9	4.1	3.9
Total income tax expense, amount	$ 23.6	$ 34.3	$ 59.4	$ 67.0
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percent	21.00%	21.00%	21.00%	21.00%
State income taxes net of federal tax benefit, percent	6.00%	6.00%	5.90%	6.00%
Federal excess deferred tax amortization, percent	(3.20%)	(3.20%)	(3.30%)	(3.30%)
PTCs, percent	(2.90%)	(1.20%)	(3.00%)	(2.30%)
AFUDC-Equity, percent	(1.70%)	(1.30%)	(1.80%)	(1.40%)
Domestic production activities deferral, percent	1.00%	1.00%	1.00%	1.00%
Other, net, percent	1.40%	1.20%	1.50%	1.30%
Total income tax expense, percent	21.60%	23.50%	21.30%	22.30%

v3.24.2

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Assets
Derivative assets	$ 12.0	$ 4.7
Liabilities
Derivative liabilities	20.8	38.5
Fair value measurements on a recurring basis
Assets
Derivative assets	12.0	4.7
Liabilities
Derivative liabilities	20.8	38.5
Fair value measurements on a recurring basis | Level 1
Assets
Derivative assets	1.3	0.9
Liabilities
Derivative liabilities	5.3	16.1
Fair value measurements on a recurring basis | Level 2
Assets
Derivative assets	1.0	1.3
Liabilities
Derivative liabilities	15.5	22.4
Fair value measurements on a recurring basis | Level 3
Assets
Derivative assets	9.7	2.5
Liabilities
Derivative liabilities	0.0	0.0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative assets	2.3	2.2
Liabilities
Derivative liabilities	6.1	19.2
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative assets	1.3	0.9
Liabilities
Derivative liabilities	5.3	16.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative assets	1.0	1.3
Liabilities
Derivative liabilities	0.8	3.1
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative assets	0.0	0.0
Liabilities
Derivative liabilities	0.0	0.0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative assets	9.7	2.5
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative assets	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative assets	0.0	0.0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative assets	9.7	2.5
Fair value measurements on a recurring basis | Coal contracts
Liabilities
Derivative liabilities	14.7	19.3
Fair value measurements on a recurring basis | Coal contracts | Level 1
Liabilities
Derivative liabilities	0.0	0.0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Liabilities
Derivative liabilities	14.7	19.3
Fair value measurements on a recurring basis | Coal contracts | Level 3
Liabilities
Derivative liabilities	$ 0.0	$ 0.0

v3.24.2

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Level 3 rollforward
Balance at the beginning of the period	$ 1.0	$ 0.8	$ 2.5	$ 2.0
Purchases	12.1	8.1	12.1	8.1
Settlements	(3.4)	(2.0)	(4.9)	(3.2)
Balance at the end of the period	$ 9.7	$ 6.9	$ 9.7	$ 6.9

v3.24.2

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Financial instruments
Preferred stock	$ 30.4	$ 30.4
Carrying amount
Financial instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	3,697.9	3,354.4
Fair value
Financial instruments
Preferred stock	21.2	21.4
Long-term debt, including current portion	$ 3,529.0	$ 3,255.4

v3.24.2

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) $ in Millions	Jun. 30, 2024 USD ($) Instruments	Dec. 31, 2023 USD ($) Instruments
Derivative assets
Current derivative assets	$ 12.0	$ 4.7
Long-term derivative assets	0.0	0.0
Total derivative assets	$ 12.0	$ 4.7
Current derivative assets balance sheet location	Other	Other
Long-term derivative assets balance sheet location	Other	Other
Derivative liabilities
Current derivative liabilities	$ 15.9	$ 28.8
Long-term derivative liabilities	4.9	9.7
Total derivative liabilities	$ 20.8	$ 38.5
Current derivative liabilities balance sheet location	Other	Other
Long-term derivative liabilities balance sheet location	Other	Other
Natural gas contracts
Derivative assets
Current derivative assets	$ 2.3	$ 2.2
Long-term derivative assets	0.0	0.0
Derivative liabilities
Current derivative liabilities	5.9	18.6
Long-term derivative liabilities	0.2	0.6
FTRs
Derivative assets
Current derivative assets	9.7	2.5
Derivative liabilities
Current derivative liabilities	0.0	0.0
Coal contracts
Derivative assets
Current derivative assets	0.0	0.0
Long-term derivative assets	0.0	0.0
Derivative liabilities
Current derivative liabilities	10.0	10.2
Long-term derivative liabilities	$ 4.7	$ 9.1
Derivatives designated as hedging instruments
Derivative instruments
Number of derivative instruments | Instruments	0	0

v3.24.2

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024 USD ($) MMBTU MWh	Jun. 30, 2023 USD ($) MWh MMBTU	Jun. 30, 2024 USD ($) MMBTU MWh	Jun. 30, 2023 USD ($) MWh MMBTU
Realized gains and losses
Realized gains and losses on derivatives income statement location	Cost of sales	Cost of sales	Cost of sales	Cost of sales
Gains (losses)	$ (8.0)	$ (23.4)	$ (23.1)	$ (52.5)
Natural gas contracts
Realized gains and losses
Gains (losses)	$ (9.4)	$ (25.3)	$ (26.4)	$ (54.5)
Notional sales volumes
Notional sales volumes | MMBTU	16.3	17.0	39.2	35.9
FTRs
Realized gains and losses
Gains (losses)	$ 1.4	$ 1.9	$ 3.3	$ 2.0
Notional sales volumes
Notional sales volumes | MWh	5.1	5.2	10.0	10.1

v3.24.2

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023
Cash collateral
Cash collateral posted	$ 13.9	$ 26.7
Offsetting derivative assets
Gross amount recognized on the balance sheet	12.0	4.7
Gross amount not offset on the balance sheet	(1.4)	(1.3)
Net amount	10.6	3.4
Offsetting derivative liabilities
Gross amount recognized on the balance sheet	20.8	38.5
Gross amount not offset on the balance sheet	(5.5)	(16.5)
Net amount	15.3	22.0
Cash collateral posted	$ 4.1	$ 15.2

v3.24.2

GUARANTEES (Details) $ in Millions	Jun. 30, 2024 USD ($)
Standby letters of credit
Guarantees
Guarantees with expiration over 3 years	$ 26.0

v3.24.2

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Components of net periodic benefit cost (credit)
Regulatory assets	$ 2,954.9		$ 2,954.9		$ 2,860.7
Pension Benefits
Components of net periodic benefit cost (credit)
Service cost	2.4	$ 2.3	5.2	$ 5.1
Interest cost	11.0	11.7	22.3	23.6
Expected return on plan assets	(15.2)	(15.8)	(30.8)	(32.2)
Amortization of net actuarial (gain) loss	4.7	2.7	9.0	4.6
Net periodic benefit (credit) cost	2.9	0.9	5.7	1.1
Contributions and payments related to pension and OPEB plans			3.3
Pension Benefits | Pension and Other Postretirement Plans Cost
Components of net periodic benefit cost (credit)
Regulatory assets	4.3		4.3
Other Postretirement Benefits
Components of net periodic benefit cost (credit)
Service cost	0.8	0.6	1.6	1.3
Interest cost	2.0	1.9	4.1	3.8
Expected return on plan assets	(2.8)	(3.3)	(5.5)	(6.7)
Amortization of prior service credit	0.0	(0.2)	(0.1)	(0.4)
Amortization of net actuarial (gain) loss	(1.4)	(2.2)	(2.8)	(4.4)
Net periodic benefit (credit) cost	(1.4)	$ (3.2)	(2.7)	$ (6.4)
Estimated future employer contributions for the remainder of the year	0.2		0.2
Other Postretirement Benefits | Pension and Other Postretirement Plans Cost
Components of net periodic benefit cost (credit)
Regulatory assets	$ 11.5		$ 11.5

v3.24.2

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024 USD ($)	Jun. 30, 2023 USD ($)	Jun. 30, 2024 USD ($) numberOfSegments	Jun. 30, 2023 USD ($)
Segment Reporting [Abstract]
Number of reportable segments | numberOfSegments			2
Other Segment
Segment Reporting Information [Line Items]
Significant items reported in the other segment | $	$ 0.0	$ 0.0	$ 0.0	$ 0.0

v3.24.2

VARIABLE INTEREST ENTITIES - WEPCO ENVIRONMENTAL TRUST (Details) - USD ($) $ in Millions	1 Months Ended
	Nov. 30, 2020	Jun. 30, 2024	Dec. 31, 2023
Assets
Other current assets (restricted cash)		$ 0.3	$ 0.8
Regulatory assets		2,954.9	2,860.7
Other long-term assets (restricted cash)		0.3	0.6
Liabilities
Current portion of long-term debt		559.1	309.0
Long-term debt		3,138.8	3,045.4
WEPCo Environmental Trust
Variable interest entities
Securitization of environmental control costs related to Pleasant Prairie power plant	$ 100.0
Assets
Other current assets (restricted cash)		0.3	0.8
Regulatory assets		82.3	85.9
Other long-term assets (restricted cash)		0.3	0.6
Liabilities
Current portion of long-term debt		9.1	9.0
Accounts payable		0.1	0.0
Other current liabilities (accrued interest)		0.1	0.1
Long-term debt		$ 80.9	$ 85.3

v3.24.2

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Billions	Jun. 30, 2024 USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 7.1

v3.24.2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended					6 Months Ended
	May 31, 2024 MMBTU performance_obligations	Feb. 29, 2024 micrograms	Oct. 31, 2023 mo States	Aug. 31, 2023	Dec. 31, 2020 micrograms	Jun. 30, 2024 USD ($) MW	Dec. 31, 2023 USD ($)
Manufactured gas plant remediation
Regulatory assets | $						$ 2,954.9	$ 2,860.7
Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets | $						$ 11.2	12.2
Cross State Air Pollution Rule - Good Neighbor Rule | Electric | Maximum
Air quality
RICE unit megawatts | MW						25
Mercury and Air Toxics Standards | Electric
Air quality
Previous level of particulate matter in pounds per million british thermal unit | MMBTU	0.03
New limit for particulate matter published in the EPA's final rule | MMBTU	0.01
National Ambient Air Quality Standards | Electric
Air quality
Number of states that failed to submit timely SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard | States			11
Number of months after May 2025 deadline for SIP that offset sanctions will take effect if the state SIP revision isn't approved | mo			18
Current level of micrograms per cubic meter that particulate matter needs to be below | micrograms					12
Current level of micrograms per cubic under 24-hour standard that fine particulate matter needs to be below | micrograms					35
National Ambient Air Quality Standards | Electric | Maximum
Air quality
Period of time for EPA review of ozone plan				5 years
New primary annual PM2.5 level | micrograms		9
National Ambient Air Quality Standards | Electric | Minimum
Air quality
Period of time for EPA review of ozone plan				3 years
Number of years between evaluation of attainment status				3 years
Climate Change | Electric
Air quality
Number of applicable GHG performance standards for coal plants | performance_obligations	0
Percent capacity factor that if combined cycle natural gas plants are above it causes the rule to be highly dependent on hydrogen or carbon capture	40.00%
Number of applicable GHG limits for new simple cycle natural gas-fired combustion turbines | performance_obligations	0
Percent capacity factor for simple cycle natural gas fired combustion turbines that there are no applicable limits if the capacity factor is less than this	20.00%
Capacity of coal-fired generation retired, in megawatts | MW						2,100
Capacity of fossil-fueled generation to be retired by the end of 2031, in megawatts | MW						1,200
Company goal for percent carbon emission reduction below 2005 levels by the end of 2025						60.00%
Company goal for percentage of carbon emission reduction below 2005 levels by the end of 2030						80.00%
Climate Change | Electric | Maximum
Air quality
RICE unit megawatts | MW						25
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Number of new ELG rule requirements that affect our electric utilities | performance_obligations	3
Compliance costs through 2023 associated with the ELG rule that were required to achieve discharge limits | $							97.0
Number of existing coal categories that were kept as part of the 2024 supplemental ELG role requirements | performance_obligations	1
Number of new coal categories that were created as part of the 2024 supplemental ELG rule requirements | performance_obligations	1
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Reserves for future environmental remediation (1) | $						$ 10.3	10.3
Manufactured Gas Plant Remediation | Natural gas | Environmental remediation costs
Manufactured gas plant remediation
Regulatory assets | $						$ 11.2	$ 12.2

v3.24.2

SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Supplemental cash flow information
Cash paid for interest, net of amount capitalized	$ 236.9	$ 233.5
Cash paid for income taxes, net	59.9	65.0
Cash received from sale of production tax credits	10.7
Significant non-cash investing and financing transactions
Accounts payable related to construction costs	$ 102.6	$ 61.0

v3.24.2

SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH, CASH EQUIVALENTS, AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Jun. 30, 2024	Dec. 31, 2023	Jun. 30, 2023	Dec. 31, 2022
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 0.0	$ 6.1
Restricted cash included in other current assets	0.3	0.8
Restricted cash included in other long-term assets	0.3	0.6
Cash, cash equivalents, and restricted cash	$ 0.6	$ 7.5	$ 30.8	$ 47.7

v3.24.2

REGULATORY ENVIRONMENT - 2025 AND 2026 RATE CASE (Details) - Public Service Commission of Wisconsin (PSCW) $ in Millions	Apr. 12, 2024 USD ($)
Public Utilities, General Disclosures [Line Items]
Requested return on equity (as a percent)	10.00%
Requested common equity component average (as a percent)	53.50%
Percentage of first 15 basis points of additional earnings retained by the utility	100.00%
Return on equity in excess of authorized amount (as a percent)	0.15%
Percentage of additional earnings between 15 and 75 basis points refunded to customers	50.00%
Return on equity in excess of first 15 basis points above authorized amount (as a percent)	0.60%
Percentage of earnings in excess of 75 basis points refunded to customers	100.00%
2025 Rates | Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 240.7
Requested rate increase (as a percent)	6.90%
2025 Rates | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 57.5
Requested rate increase (as a percent)	10.00%
2025 Rates | Steam Rate Request
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 2.5
Requested rate increase (as a percent)	8.40%
2026 Rates | Electric
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 177.9
Requested rate increase (as a percent)	4.60%
2026 Rates | Natural gas
Public Utilities, General Disclosures [Line Items]
Requested rate increase	$ 31.0
Requested rate increase (as a percent)	4.60%

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