WEC ENERGY GROUP, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

September 30, 2026

NOTE 1—GENERAL INFORMATION

WEC Energy Group serves approximately 1.7 million electric customers and 3.1 million natural gas customers, owns approximately 60% of ATC, and owns majority interests in multiple renewable generating facilities as part of its non-utility energy infrastructure segment.

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

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

We use the equity method to account for investments in companies we do not control but over which we exercise significant influence regarding their operating and financial policies. As a result of our limited voting rights, we account for ATC and ATC Holdco as equity method investments. See Note 19, Investment in Transmission Affiliates, for more information.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2025. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2026, are not necessarily indicative of expected results for 2026 due to seasonal variations and other factors.

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

NOTE 2—ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that the below acquisitions met the criteria of asset acquisitions. The purchase price of the Hardin III acquisition discussed below includes intangibles recorded as long-term liabilities related to PPAs. See Note 18, Goodwill and Intangibles, for more information.

Pending Acquisitions of Electric Generation Facilities in Wisconsin

WE filed for PSCW approval to purchase a 30% ownership interest in Weston Unit 4, an approximately 500 MW supercritical pulverized coal base-load electric generating facility located in the Villages of Kronenwetter and Rothschild, Wisconsin and the Town of Knowlton, Wisconsin. WPS currently owns a 70% interest in this facility. Pursuant to the asset purchase agreement, WE would purchase the remaining 30% interest currently owned by an unrelated third-party for its book value at the closing date, currently estimated at $150 million. If approved, it is anticipated that the transaction would close in the first half of 2027.

In December 2025, WE and WPS, along with an unaffiliated utility, signed an agreement to acquire Whitetail Wind Energy Generation Facility, a wind-powered electric generation project with a total capacity of 67.2 MW. This project has been approved by the PSCW and will be located in Grant County, Wisconsin and WE will own 80% and WPS will own 10%. WE's share of the purchase price is expected to be approximately $178 million and WPS's share of the purchase price is expected to be approximately $22 million. The project is expected to close in late 2027 and it is expected to qualify for PTCs.

Acquisition of a Solar Generation Facility in Ohio

Upon commercial operation in February 2025, WECI completed the acquisition of a 90% ownership interest in Hardin III, a 250 MW solar generating facility located in Hardin County, Ohio for $409.1 million. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Hardin III qualifies for PTCs and is included in the non-utility energy infrastructure segment.

NOTE 3—DISPOSITION

Illinois Segment

Sale of Certain Real Estate by The Peoples Gas Light and Coke Company

In January 2026, we sold approximately 15 acres of real estate owned by PGL that was no longer being utilized in its operations, for $20.9 million, which is net of selling costs. The real estate was located in Chicago, Illinois. As a result of the sale, a pre-tax gain in the amount of $11.9 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.

NOTE 4—OPERATING REVENUES

For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

Disaggregation of Operating Revenues

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

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

Revenues from Contracts with Customers

Electric Utility Operating Revenues

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

(1)Includes the revenues from VLCs.

Natural Gas Utility Operating Revenues

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

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

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

Other non-utility operating revenues consist primarily of the following:

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

Other Operating Revenues

Other operating revenues consist of the following:

(1)Consists of revenues related to carrying costs recognized during the construction of certain Bespoke Resources assigned to WE's VLCs. Consistent with the timing of when we recognize revenue, customer billings for the Bespoke Resources that are subject to current return (as opposed to AFUDC) occur on a monthly basis. For more information about the Bespoke Resources current return, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

(2)We account for our asset acquisitions by recognizing identifiable intangible assets and liabilities assumed at fair value at the acquisition date. Amortization of these intangible assets and liabilities, which relate to PPAs and a proxy revenue swap, is recognized on a straight-line basis over

the remaining contract term as a decrease or increase to operating revenues, respectively. See Note 18, Goodwill and Intangibles, for more information.

(3)Alternative revenues consist of amounts to be recovered or refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups. Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. For more information about our alternative revenues, see Note 1(d), Operating Revenues, in our 2025 Annual Report on Form 10-K.

NOTE 5—CREDIT LOSSES

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

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

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

We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers, including VLCs, to mitigate credit risk. See Note 24, Regulatory Environment, for more information about the VLC and Bespoke Resources tariffs.

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at September 30, 2026 and December 31, 2025, by reportable segment.

(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at September 30, 2026, $842.4 million, or 60.0%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 24, Regulatory Environment, for more information on PGL and NSG's UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and amounts recovered in rates.

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

On a consolidated basis, there was a $8.8 million decrease in the allowance for credit losses at September 30, 2026, compared to January 1, 2026. This decrease was largely driven by customer write-offs in Wisconsin and a decrease in past due accounts in both Wisconsin and Illinois that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears.

On a consolidated basis, there was a $33.3 million decrease in the allowance for credit losses at September 30, 2025, compared to January 1, 2025. This decrease was largely driven by customer write-offs in Wisconsin in addition to a decrease in past due account balances in Wisconsin that we believe was related to a continued focus on collection efforts and lower energy bills in the spring and summer months, enabling customers to pay down their arrears. Also, the allowance for credit losses in Illinois decreased based on the lower accounts receivable balance at the end of the period.

NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2026 and December 31, 2025. For more information on our regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities, in our 2025 Annual Report on Form 10-K.

(1)These amounts primarily represent the deferral of the incremental revenue requirement of incurred costs resulting from changes to the retirement of certain generation facilities.

(1)We defer as a regulatory asset or liability the difference between actual costs associated with the We Power generation units and those included in rates until recovery or refund is authorized in a future rate proceeding.

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7-8

The retirement of OCPP Units 7 and 8 became probable at the end of 2022, following initial PSCW approvals for replacement generation. On April 1, 2026, we announced plans to extend the operating lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through 2027. These units were previously scheduled to be retired at the end of 2026. The decision to postpone the retirement dates for these units is based ontwo critical factors, reliability and affordability for WE’s customers. This past winter the Midwest power market experienced tightened energy supply and higher energy costs during extreme temperatures. Keeping OCPP Units 7 and 8 available will better position WE to serve customers with safe, reliable and affordable energy on the hottest and coldest days of the year. The extension of these units will serve as a bridge until new dispatchable generation begins to come online, which is expected in late 2027.

The total net book value of OCPP Units 7 and 8 was $595.7 million at September 30, 2026, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson Solar Energy LLC and Delilah Solar Energy LLC– Storm Damage

During several storms that occurred in 2023 and 2024, certain sections of our Samson I solar facility incurred damage. We had previously recognized an impairment loss of $2.8 million related to damage from these storms, and recorded an offsetting $2.8 million receivable for future insurance recoveries. However, in the second quarter of 2025, we determined it was no longer probable that we would receive insurance proceeds sufficient to recover our losses associated with the 2023 and 2024 storms. As a result, the insurance receivable balance was written off, resulting in the recognition of the $2.8 million impairment loss within other operation and maintenance expense on our income statement.

In March 2025, both our Samson I and Delilah I solar facilities experienced damage from a storm. In the second quarter of 2025, we recognized an impairment loss within other operation and maintenance expense on our income statement in the amount of $8.8 million, related to damage incurred associated with the March 2025 storm. The impairment loss associated with the March

2025 storm was increased from $8.8 million to $12.0 million in the third quarter of 2025 based on finalization of the damage assessment.

In addition, in June 2026, our Delilah I solar facility experienced minor damage from a storm, resulting in the recognition of a $1.7 million impairment loss within other operation and maintenance in the second quarter of 2026. In the third quarter of 2026, we increased the impairment by $1.3 million to $3.0 million based on finalization of the damage assessment.

As a result of storm damage sustained over the past several years, we have undertaken storm hardening efforts at both our Samson I and Delilah I solar facilities, and those efforts remain ongoing.

The Peoples Gas Light and Coke Company Impairment

In the fourth quarter of 2025, PGL recorded a $130.0 million impairment to property, plant, and equipment related to the terms of a proposed settlement that was finalized in May 2026, resolving its open proceedings related to the QIP Rider. See Note 24, Regulatory Environment, for more information.

NOTE 8—COMMON EQUITY

Stock-Based Compensation

During the nine months ended September 30, 2026, the Compensation Committee of our Board of Directors awarded the following stock-based compensation to our directors, officers, and certain other key employees:

(1)Stock options awarded had a weighted-average exercise price of $106.09 and a weighted-average grant date fair value of $21.20 per option.

(2)Restricted shares awarded had a weighted-average grant date fair value of $106.09 per share.

Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, Bluewater, ATC Holding LLC (which holds our ownership interest in ATC), and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. Our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our 2025 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Common Stock

We issue new shares of common stock to fulfill our obligations under various stock-based employee benefit and compensation plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

In August 2024, we entered into an EDA, under which we could offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $1.5 billion through an at-the-market offering program. In October 2025, we terminated this EDA and entered into a new EDA, under which we may offer and sell, from time to time, shares of our common stock having an aggregate sales price of up to $3.0 billion through an at-the-market offering program. This EDA also includes an equity forward sales component and a collared forward sales component. We may offer and sell our common shares through the sales agents party to the EDA during the term of the agreement. The October 2025 EDA will terminate upon the earliest of (i) the sale of all common stock subject to the EDA, (ii) termination of the EDA pursuant to its terms, or (iii) October 31, 2028. Actual sales of common stock under

the EDA will depend on a variety of factors, including market conditions, the trading price of our common stock, capital needs, and our determination of the appropriate sources of funding. Any shares offered and sold under our October 2025 EDA will be done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplements.

We have entered into several forward sales contracts under our October 2025 EDA. The following table presents information related to the common stock sold under our outstanding forward sales contracts at September 30, 2026:

(1)Amount represents the weighted-average initial forward price of the forward sales contracts that became effective during the quarter. The initial forward price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts as specified in the contract.

No amounts are recorded on our balance sheet with respect to these contracts until actual settlement occurs. The contracts require us, at our election, to either (i) physically settle the transaction by issuing shares of our stock in exchange for net cash proceeds at the then-applicable forward sales price or (ii) net settle the transaction through the delivery or receipt of cash or shares in accordance with the contract provisions. At September 30, 2026, we could have settled our outstanding forward sales contracts as follows:

During the third quarter of 2026, we physically settled various forward sales contracts that were entered into under our October 2025 EDA. As a result of these settlements, we issued 3,027,623 shares of common stock at a weighted-average net price of $114.79 per share. The net proceeds from the issuance were $347.5 million.

We had the following changes to our outstanding common stock during the three and nine months ended September 30, 2026 and 2025:

On October 15, 2026, our Board of Directors declared a quarterly cash dividend of $0.9525 per share, payable on December 1, 2026, to shareholders of record on November 13, 2026.

Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the three and nine months ended September 30, 2026 and 2025:

NOTE 9—SHORT-TERM DEBT AND LINES OF CREDIT

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

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

Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2026 was $2,055.8 million with a weighted-average interest rate during the period of 3.97%.

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

NOTE 10—LONG-TERM DEBT

WEC Energy Group, Inc.

In January 2026, our $1,000.0 million of 4.75% Senior Notes due January 9, 2026, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In February 2026, we issued an additional $400.0 million of our 4.75% Senior Notes due January 15, 2028, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In September 2026, our $350.0 million of 5.60% Senior Notes due September 12, 2026, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

Convertible Senior Notes

As of September 30, 2026, the conditions allowing holders to convert their notes were not met. In accordance with the guidance in ASC Subtopic 470-20, Debt – Debt with Conversion and Other Options, the 2027 Notes, 2028 Notes, and 2029 Notes were accounted for in their entirety as a liability on our balance sheet. The following is a summary of our convertible debt instruments as of September 30, 2026:

(1)The fair values are categorized in Level 2 of the fair value hierarchy. See Note 14, Fair Value Measurements, for more information on the levels of the fair value hierarchy.

The following table provides a summary of the interest expense recorded for each of the 2027 Notes, 2028 Notes, and 2029 Notes:

Wisconsin Electric Power Company

In March 2026, WE issued $300.0 million of 5.65% Debentures, due March 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In June 2026, WE issued $400.0 million of 4.65% Debentures, due June 15, 2031, and $400.0 million of 5.10% Debentures, due June 15, 2036, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In August 2026, WE issued an additional $300.0 million of its 5.10% Debentures, due June 15, 2036, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Public Service Corporation

In January 2026, WPS issued $300.0 million of 4.25% Senior Notes, due January 15, 2031, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In August 2026, WPS issued $300.0 million of 6.05% Senior Notes, due August 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Gas LLC

In October 2026, WG issued $50.0 million of 5.60% Debentures, due November 1, 2031, and $50.0 million of 5.90% Debentures, due November 1, 2036, and used the net proceeds to repay short-term debt and for other general corporate purposes

The Peoples Gas Light and Coke Company

PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued tax exempt bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued $100.0 million of collateralized First Mortgage Bonds. In February 2026, PGL provided notice of its intent to redeem in full all $50.0 million of its First and Refunding Mortgage Bonds, Series VV and all of its $50.0 million First and Refunding Mortgage Bonds, Series ZZ. In addition, notices of redemption for all $50.0 million of the related 3.90% Illinois Finance Authority Gas Supply Refunding Revenue Bonds, Series 2010 due March 1, 2030 and all $50.0 million of the 4.00% Illinois Finance Authority Gas Supply Refunding Revenue Bonds, Series 2013A due February 1, 2033 were issued. In March 2026, all redemptions were made.

NOTE 11—LEASES

Obligations Under Finance Leases

During 2026, WE and WPS, along with an unaffiliated utility, acquired various land leases related to our investments in utility solar generation. Each lease has an initial term andone or more optional extensions. We expect the optional extensions to be exercised, and, as a result, all of the land leases are being amortized over an extended term. The weighted-average remaining lease term for these land leases was 50.1 years at September 30, 2026. Once a solar project achieves commercial operation, the lease liability will be remeasured to reflect the final total acres being leased.

The right of use assets obtained in exchange for these finance lease liabilities was $43.1 million. Our total obligation under these land-related leases was $43.9 million at September 30, 2026, and was included in finance lease obligations on our balance sheet. Our finance lease right of use asset related to these leases was $42.8 million as of September 30, 2026, and was included in property, plant, and equipment on our balance sheet. Our weighted-average discount rate for these leases was 6.39%. We used an estimate of the fully collateralized incremental borrowing rate based upon information available for similarly rated companies in determining the present value of lease payments.

Future minimum lease payments and the corresponding present value of our net minimum lease payments under these land-related leases as of September 30, 2026, were as follows:

NOTE 12—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventories consisted of:

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2026, all LIFO layers were replenished, and the LIFO liquidation balance waszero.

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

NOTE 13—INCOME TAXES

Statutory 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:

(1)State taxes in Wisconsin made up the majority of the tax effect in this category.

(2)PTCs are an inflation adjusted United States federal income tax credit for each kilowatt hour of electricity generated by certain renewable energy projects.

(3)AFUDC-Equity represents the cost of capital (i.e. ROE) that is added to the construction cost of an asset while it is being built. The tax benefit for regulated utilities from AFUDC-Equity is a regulatory gross-up to allow the recovery of income taxes on the equity portion of construction costs, even though it is not a tax deductible expense.

(4)The Tax Cuts and Jobs Act of 2017 required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018, in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting inno impact on net income.

The IRA contains a tax credit transferability provision that allows us to sell PTCs and ITCs produced after December 31, 2022, to third parties. Under this transferability provision, we entered into agreements to sell substantially all of the PTCs and ITCs we generated in 2025 to third parties. We have also entered into agreements to sell the majority of PTCs that we expect to generate in 2026 and a portion of the PTCs that we expect to generate in 2027 and 2028 to third parties. We elect to account for tax credits transferred under the scope of ASC 740. We include the discount from the sale of tax credits as a component of income tax expense. We also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs and ITCs. 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.

Cash Paid (Received) For Income Taxes, Net

The table below is a summary of income taxes paid (received) by jurisdiction:

(1)Amount includes $153.3 million of cash received related to third-party sales of both 2026 and 2025 PTCs, and $81.6 million of cash received related to third-party sales of 2025 ITCs.

(2)Amount includes $195.0 million of cash received related to third party sales of both 2025 and 2024 PTCs.

The table below is a summary of income taxes received (net of refunds) that exceeded five percent of total income taxes paid or received (net of refunds) by jurisdiction. There was no jurisdiction exceeding the threshold for the nine months ended September 30, 2026.

NOTE 14—FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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

The tables above include derivative assets and liabilities for options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. Both tables also include FTRs used at our electric utilities to manage electric transmission congestion costs in the MISO Energy Markets. Additionally, the December 31, 2025 table includes FTRs used at certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets, which were all settled during the first six months of 2026.

We hold investments in the Integrys rabbi trust. These investments are used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. For the three months ended September 30, 2026 and 2025, the net unrealized gains included in earnings related to the investments held at the end of the period were $0.7 million and $3.0 million, respectively. For the nine months ended September 30, 2026 and 2025, the net unrealized gains included in earnings related to the investments held at the end of the period were $4.6 million and $4.9 million, respectively.

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

(1)Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment. These net realized and unrealized losses were recorded in operating revenues on our income statements. During the first six months of 2026, all remaining FTRs used in our non-utility operations were settled. Our TCRs were all settled during the year ended December 31, 2025.

Fair Value of Financial Instruments

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

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

NOTE 15—DERIVATIVE INSTRUMENTS

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

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

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

Realized gains and losses on derivatives used in our regulated utility operations are recorded incost of sales upon settlement; however, they may be subsequently deferred for future rate recovery or refund as the gains and losses are included in our utilities’ fuel and natural gas cost recovery mechanisms. Realized gains and losses on FTRs and TCRs used in our non-utility operations were recorded inoperating revenues on the income statements. During the first six months of 2026, all remaining FTRs used in our non-utility operations were settled. Our TCRs were all settled during the year ended December 31, 2025. Our realized gains and losses and the estimated notional volumes related to these settlements were as follows:

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2026 and December 31, 2025, we had posted cash collateral of $92.2 million and $41.4 million, respectively. These amounts were recorded on our balance sheets in other current assets. At September 30, 2026, we had also received cash collateral of $2.0 million. This amount was recorded on our balance sheet in other current liabilities.

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

(1)Includes cash collateral posted of $45.9 million.

(2)Includes cash collateral posted of $21.8 million.

Cash Flow Hedges

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings. The derivative gains related to these swap agreements reclassified from accumulated other comprehensive loss to interest expense during the three and nine months ended September 30, 2026 and 2025 were not significant. At September 30, 2026, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 16—GUARANTEES

The following table shows our outstanding guarantees:

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

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

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

NOTE 17—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:

During the nine months ended September 30, 2026, we made contributions and payments of $9.1 million related to our pension plans and $1.4 million related to our OPEB plans. We expect to make contributions and payments of $2.7 million related to our pension plans and $0.9 million related to our OPEB plans during the remainder of 2026, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

Certain of our utility subsidiaries utilize escrow accounting for our current pension and OPEB costs, as approved by the PSCW. As of September 30, 2026 and December 31, 2025, our balance sheets included regulatory liabilities of $26.9 million and $14.7 million, respectively, for pension costs and regulatory assets of $2.8 million and $0.7 million, respectively, for OPEB costs. In accordance with our PSCW rate orders, we amortize the related regulatory assets and liabilities. The above tables do not reflect any adjustments for the creation or amortization of these regulatory assets and liabilities.

NOTE 18—GOODWILL AND INTANGIBLES

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at September 30, 2026. We hadno changes to the carrying amount of goodwill during the nine months ended September 30, 2026.

(1)We hadno accumulated impairment losses related to our goodwill as of September 30, 2026.

During the third quarter of 2026, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2026. No impairments resulted from these tests.

Other Indefinite-Lived Intangible Assets

At September 30, 2026 and December 31, 2025, we had $229.7 million and $44.4 million, respectively, of other indefinite-lived intangible assets included in other long-term assets on our balance sheets. In July 2026, WE and WPS entered into an option agreement and made a refundable aggregate payment of $170.8 million for exclusive rights to purchase certain generation projects to be constructed in Wisconsin. In October 2025, we entered into an option agreement for exclusive rights to purchase land for future generation development in Wisconsin. We have madetwo annual option payments for exclusive rights to purchase the land and incurred total costs of $29.6 million and $15.1 million as of September 30, 2026 and December 31, 2025, respectively, with a right to exercise our option before December 31, 2030. In addition, we have other indefinite-lived intangible assets consisting of $24.1 million of spectrum frequencies, which enable our utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories. We also have $5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition.

Finite-Lived Intangible Assets

At September 30, 2026 and December 31, 2025, we had $18.3 million and $17.4 million, respectively, of finite-lived intangible assets included in other long-term assets on our balance sheets. These assets largely consist of a PPA for Maple Flats Solar Energy Center LLC acquired by WECI in November 2024, with a gross carrying amount of $18.8 million. The PPA is being amortized over a useful life

of 15 years and expires in 2039. At September 30, 2026 and December 31, 2025, accumulated amortization related to the intangible assets was $2.3 million and $1.4 million, respectively. Amortization was not material for the three and nine months ended September 30, 2026 and 2025. Amortization to be recorded as a decrease to operating revenues is expected to be $1.3 million in each of the next five years.

Intangible Liabilities

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

(1)Represents PPAs related to the acquisitions of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky Wind Energy LLC, Delilah I, and Hardin III expiring between 2030 and 2040. The weighted-average remaining useful life of the PPAs is 9 years. See Note 2, Acquisitions, for more information on recent WECI acquisitions.

(2)Represents an agreement with a counterparty to swap the market revenue of Upstream Wind Energy LLC's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap istwo years.

(3)Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill Energy III LLC, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 14 years.

Amortization related to these intangible liabilities for the three and nine months ended September 30, 2026, was $15.1 million and $45.1 million, respectively. Amortization related to these intangible liabilities for the three and nine months ended September 30, 2025, was $14.7 million and $43.4 million, respectively. Amortization for the next five years, including amounts recorded through September 30, 2026, is estimated to be:

NOTE 19—INVESTMENT IN TRANSMISSION AFFILIATES

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

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

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

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

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

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

NOTE 20—SEGMENT INFORMATION

Our President and Chief Executive Officer, who is our CODM, reviews financial information presented on a segment basis for purposes of making operating decisions and assessing performance. The CODM regularly reviews net income attributed to common shareholders to measure segment profitability and to allocate resources, including assets, to our businesses. Net income attributed to common shareholders best measures our segment profitability as it reflects all revenues and costs, including the impact on our tax provision from tax credits generated through investments in renewable generation facilities.

Our CODM allocates resources, such as employees, as well as financial and capital resources, to our segments during the annual review of budgets and the capital plan. Our CODM also reviews and revises the resources throughout the year during the monthly forecasting process in order to make timely decisions that align with our overall corporate strategy. The CODM uses each segment's net income to evaluate performance by comparing actual results to budgeted and forecasted amounts, as well as the ROE earned for each utility within the various utility segments.

Segments were determined based on a combination of factors, including the regulatory environment of each geographical jurisdiction in which the segment operates, equity investment interests, as well as the revenue streams for the products or services provided to customers through electric, natural gas, and renewable operations. See Note 4, Operating Revenues, for more information on disaggregation of operating revenues, including intercompany eliminations. The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies, in our 2025 Annual Report on Form 10-K.

At September 30, 2026, we reportedsix segments, which are described below. All of our operations are located within the United States.

•The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.

•The Illinois segment includes the natural gas utility operations of PGL and NSG.

•The other states segment includes the natural gas utility operations of MERC and MGU and the non-utility operations of MERC.

•The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint. See Note 19, Investment in Transmission Affiliates, for more information on ATC and ATC Holdco.

•The non-utility energy infrastructure segment includes:

◦We Power, which owns and leases generating facilities to WE,

◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and

◦WECI, which holds majority interests in multiple renewable generating facilities.

See Note 2, Acquisitions, for more information on WECI's acquisition of Hardin III.

•The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, and WEC Business Services LLC.

The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2026 and 2025:

(2)Total assets at September 30, 2026 reflect an elimination of $2,552.4 million for all lease activity between We Power and WE.

(2)Total assets at September 30, 2025 reflect an elimination of $2,613.4 million for all lease activity between We Power and WE.

NOTE 21—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 use of securitization to recover $100 million of undepreciated environmental control costs related to WE's retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized WE to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is a wholly owned subsidiary of WE.

In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from WE. The environmental control property is recorded as a regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from WE's retail electric distribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the environmental control property. Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation. The bondholders do not have any recourse to WE or any of WE's affiliates.

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

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

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

Investment in Transmission Affiliates

We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a VIE but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At September 30, 2026 and December 31, 2025, our equity investment in ATC was $2,474.1 million and $2,256.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.

We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a VIE but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At September 30, 2026 and December 31, 2025, our equity investment in ATC Holdco was $22.9 million and $23.5 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.

See Note 19, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.

NOTE 22—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

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

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

Our minimum future commitments related to these purchase obligations as of September 30, 2026, including those of our subsidiaries, were approximately $11.0 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, PM, ozone, 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.

Federal Deregulatory Actions

In March 2025, the EPA announced a large-scale deregulatory effort that will likely take multiple years to complete. Of the proposed deregulatory actions, those that apply to us include actions impacting the Good Neighbor Rule, MATS, the PM2.5 Standard, the GHG Power Plant Rule, the Mandatory Greenhouse Gas Reporting Rule, the ELG, and the CCR Rule. The EPA has initiated various deregulatory actions. These and any future actions require formal rulemaking proceedings and have been, and future actions are likely to be, subject to legal challenges. We continue to monitor and evaluate these deregulatory actions for potential risks and benefits.

In February 2026, the EPA published a final rule rescinding the 2009 declaration that determined that CO 2 and other GHGs endanger public health and welfare. The "endangerment finding" has been the legal underpinning of a host of climate regulations under the Clean Air Act. Litigation over the rule has been initiated in the D.C. Circuit Court of Appeals.

Air Quality

Cross State Air Pollution Rule – Good Neighbor Rule

In 2023, the EPA issued a final Good Neighbor Rule, which required significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities. In June 2024, the rule was stayed by the Supreme Court with respect to the specific applicant states, pending ongoing judicial review.

In response to the Supreme Court's order, in November 2024, the EPA administratively stayed the effectiveness of the Good Neighbor Rule through an interim final rule which extends a stay to all states to which the rule originally applied, including states in which we operate. The interim final rule also includes provisions to ensure that covered facilities in states with previously established requirements to mitigate interstate air pollution with respect to the 2008 ozone NAAQS will remain subject to equivalent requirements while the Good Neighbor Rule's effectiveness is stayed. Regardless of the outcome, we believe we are well positioned

to comply with either standard. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Mercury and Air Toxics Standards

The EPA issued the MATS rule to limit emissions of mercury, acid gases, and other hazardous air pollutants. In May 2024, the EPA finalized amendments to the MATS rule (the "2024 Amendments") which among other things, lowered the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu.

In February 2026, the EPA issued a final rule effective April 27, 2026, repealing the 2024 Amendments. The final rule reverts back to the prior PM limit of 0.03 lb/MMBtu and eliminates the requirement of continuous emissions monitoring of PM emissions.

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. The EPA's initial ozone nonattainment area designation was effective 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 based on the 2015 standard. In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 2022.

After the most recent evaluation, the EPA issued a final rule in December 2024 that determined that parts of Southeast Wisconsin failed to attain 2015 ozone NAAQS and consequently would be reclassified from "moderate" to "serious," effective January 2025.

In February 2025, the State of Wisconsin filed a petition for review of this reclassification in the United States Court of Appeals for the Seventh Circuit and was granted a stay of the reclassification in September 2025, pending the Court's review. The case is being held in abeyance and Southeast Wisconsin is currently under a "moderate" reclassification status pending a further court order. In August 2026, Clean Wisconsin and Sierra Club filed a motion to intervene and defend the final rule reclassifying the nonattainment area from "moderate" to "serious".

A nonattainment status of "serious" could have a material adverse effect on future permitting activities for our facilities in applicable locations, including additional costs associated with more strenuous emission control requirements or the need to purchase emission reduction credits.

Particulate Matter

All counties within our service territories are currently in attainment with current 2012 NAAQS for PM2.5. In February 2024, the EPA finalized a rule which lowered the primary (health-based) annual PM2.5 NAAQS from 12 µg/m 3 to 9 µg/m 3 (the "2024 PM2.5 Standard"). In February 2025, the Wisconsin Department of Natural Resources submitted a State Implementation Plan to the EPA recommending Wisconsin be designated as an attainment area under the 2024 PM2.5 Standard. The EPA has not yet issued its attainment designations. 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. We do not expect the 2024 PM2.5 Standard to have a material impact on our units.

In November 2025, the EPA filed a motion in the litigation pending in the D.C. Circuit Court of Appeals to vacate the 2024 PM2.5 Standard. The court issued an order in June 2026, denying the EPA's motion. The 2024 PM2.5 Standard therefore remains in effect. Previously, in April 2026, the State of Wisconsin signed onto a complaint filed in California that seeks an order directing the EPA to implement the 2024 PM2.5 Standard and make nonattainment designations. In July 2026, the Northern District Court of California ordered the EPA to publish final designations for all areas of the country no later than February 6, 2027. The EPA is appealing the order while continuing to move forward with completing the designations. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

New Source Performance Standards

Nitrogen Oxides

In January 2026, the EPA released a final rule regulating NOx for CTs constructed, modified, or reconstructed after December 13, 2024. The final rule became effective January 15, 2026, and established NOx emissions standards for several subcategories of new, modified, and reconstructed CTs based on the size, rates of utilization, design efficiency, and fuel type of these turbines. We believe the CTs included in our capital plan will be well positioned to comply with this rule. The existing simple cycle CTs will require more stringent NOx limits if they undergo upgrades.

Climate Change

Pursuant to the final GHG Power Plant Rule, there areno applicable GHG emission standards for coal plants until the end of 2031. Thereafter, the applicable standard is dependent upon the unit's retirement date. Numerous parties have challenged the GHG Power Plant Rule through litigation pending in the D.C. Circuit Court of Appeals, and it is being held in abeyance at the request of the parties.

In September 2026, the EPA issuedtwo actions for addressing the 2024 GHG Power Plant Rule. The EPA issued a final rule repealing carbon capture, storage-based standards, and emission guidelines and a proposed supplemental rule that would repeal all GHG standards for the power sector. The final rule becomes effective on November 16, 2026, and the proposed rule has a comment period ending November 2, 2026. The final rule has already been challenged in court, and the proposed supplemental rule is expected to be challenged if finalized. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

In April 2024, the EPA issued its final Mandatory Greenhouse Gas Reporting Rule, which includes updates to the global warming potentials to determine CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption. In its current form, the rule 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 current form of this 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. However, as part of the Federal Deregulatory Actions discussed above, in September 2025, the EPA released a proposal to amend the GHG Reporting Program to permanently remove program obligations for most source categories, including our generation facilities. The EPA is also proposing to suspend program reporting requirements that would be applicable to our underground storage, LNG, and transmission affiliates until 2034. We continue to monitor the status of these deregulatory actions.

Our capital plan includes the planned retirement of older, fossil-fueled generation, to be replaced with natural gas-fired generation and zero-carbon-emitting renewables. We have retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018. We expect to retire additional coal-fired generation, including OCPP Units 7 and 8. See Note 7, Property, Plant, and Equipment, for more information related to our planned power plant retirements. As part of our capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2030. We have a long-term goal to achieve net carbon-neutral electric generation by the end of 2050. We expect to achieve this goal by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan. As part of our path toward this goal, we started implementing co-firing with natural gas at the ERGS coal-fired units and at Weston Unit 4.

We also continue to focus on methane emission reductions by improving and upgrading our natural gas distribution systems and using RNG throughout our natural gas utility systems.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

The Clean Water Act Cooling Water Intake Structure Rule 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.

Other than OCPP Units 7 and 8, we have received final or interim BTA determinations for all generation facilities where applicable. We believe existing technology at OCPP Units 7 and 8 also meets the rule requirements for BTA and anticipate that the units will receive that determination when their Wisconsin Pollutant Discharge Elimination System permit is reissued, which is expected in 2026.

Steam Electric Effluent Limitation Guidelines

The EPA's 2024 Supplemental ELG Rule (the "2024 ELG Rule") established ZLD requirements for bottom ash transport water, flue gas desulfurization, and CRL wastewaters at coal-fueled facilities. The 2024 ELG Rule also established a new subcategory, providing an alternative compliance pathway for facility owners that commit to the PCCC at a particular facility by December 31, 2034. In exchange for this commitment, ZLD technologies will not be required and less stringent standards will apply at applicable facilities. The 2024 ELG Rule also allows owners of coal-fired units who opted into a cessation of coal subcategory to operate beyond the end of 2034 if needed for reliability concerns (i.e., energy emergencies and reliability must run agreements) as determined by the United States Department of Energy, a public utility commission, or independent system operator. Based on current electric generation resource planning, in December 2025, we filed Notices of Planned Participation to opt into the PCCC subcategory for certain of our past and current coal-fueled facilities.

The EPA published a final rule which became effective March 2, 2026, that extends the deadline for facility owners to opt into a subcategory under the 2024 ELG Rule, allowing them more time to assess potential compliance pathways to continue producing low-cost electricity into the future while meeting wastewater standards.

When the deadline extension rule was proposed, the EPA also solicited public comments related to the economic achievability and technical availability of ZLD technologies. Additional ELG rulemaking is anticipated that may lead to substantive changes to the ZLD technology-based requirements established in the 2024 ELG Rule. Another proposed ELG rule was published in May 2026, to address CRL treatment requirements. As currently written, the proposed rule confirms that CRL from our Company's landfills is not subject to the limitations in the 2024 ELG Rule.

In addition, numerous parties have challenged the 2024 ELG Rule through litigation in SWEPCO v. U.S. EPA pending in the United States Court of Appeals for the Eighth Circuit, which has been held in abeyance since February 2025. The 2025 deadline extension rule is also being challenged in the United States Court of Appeals for the Second Circuit. The 2024 ELG Rule, as well as the deadline extension rule, remain in effect during the pendency of the legal challenges. The outcome of these cases may affect our compliance plans.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites. We are working with the EPA as well as various state jurisdictions, as applicable, in our investigation and remediation planning and efforts. 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:

Coal Combustion Residuals Rule

An EPA rule for CCR that applies to landfills, historic fill sites, and projects where CCR was placed at a power plant site became effective in November 2024. The rule also regulates previously exempt closed landfills.

We anticipate this rule will have an impact on some of our coal ash landfills, requiring additional remediation that is not currently required under the state programs. We expect the cost of additional remediation would be recoverable through future rates.

The rule is being challenged through litigation pending in the D.C. Circuit Court of Appeals. In December 2025, the D.C. Circuit Court of Appeals granted the EPA's motion to extend the ongoing abeyance while the EPA reconsiders certain aspects of the rule. In February 2026, the EPA published a final rule extending certain deadlines and making various corrections to the 2024 CCR rule. In April 2026, the EPA published a rule seeking comments on proposed amendments to the 2024 CCR rule. These amendments include (1) changes to the existing self-implementing regulations; (2) new compliance pathways allowing for site-specific flexibility under a state or federal permit; and (3) changes impacting the definition of CCR beneficial use. The EPA stated its intent is to revise the rule based on public feedback, including technical information submittals, and currently plans to publish a new final rule by early 2027. The EPA stated that it intends to address closure issues in a separate proposed rulemaking, which is also expected in 2027. See the Federal Deregulatory Actions discussion above for more information regarding potential deregulatory actions regarding this rule.

Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.

NOTE 23—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides additional information regarding our statements of cash flows:

Cash, Cash Equivalents, and 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:

Our restricted cash primarily consisted of the following:

•Cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans.

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

•Cash related to WECI's ownership interests in certain renewable generation projects. These projects are required to deposit into an escrow account in order to fund future decommissioning.

NOTE 24—REGULATORY ENVIRONMENT

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

2027 and 2028 Rate Cases

On April 1, 2026, WE, WPS, and WG filed requests with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2027 and January 1, 2028. The requests reflected the following:

(1)The proposed 2028 rate increases are incremental to the currently authorized revenue plus the requested rate increases for 2027.

(2)Amounts reflect the impact to our Wisconsin retail electric operations and exclude any impacts from updated fuel costs.

(3)Increase excludes the impact of the costs directly assigned to natural gas electric generation facilities.

The primary driver of the requested increases in electric rates is continued capital investments to transition our generation fleet from coal to renewables and natural gas-fueled generation, as well as the related investments in transmission and distribution assets. These capital investments, which will strengthen reliability and help reduce carbon emissions, have either already been approved by the PSCW or are expected to receive PSCW approval before or during 2028. Increased operation and maintenance costs, driven by higher inflation, was also a significant driver of the rate increases.

The requested increases in natural gas rates are driven by our ongoing capital investments in reliability and safety projects, including the previously approved Oak Creek LNG storage facility and the Rochester lateral, as well as the impact from higher inflation on operation and maintenance costs.

The utilities also proposed retaining their respective current earnings sharing mechanisms. Under WE's current earnings sharing mechanism, if WE earns above its authorized ROE: (i) it retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii)50.0% of the next 25 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. Under WPS's and WG's current mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 15 basis points above the authorized ROE; (ii)50.0% of the next 60 basis points is required to be refunded to ratepayers; and (iii)100.0% of any remaining excess earnings is required to be refunded to ratepayers.

A PSCW decision is expected in the fourth quarter of 2026.

Very Large Customer and Bespoke Resources Tariffs

In March 2025, WE filed an application with the PSCW requesting approval to implement a VLC tariff and a Bespoke Resources tariff. The PSCW issued a final written order approving the tariffs, with modifications (including to the credit support criteria and collateral provisions), in May 2026. Under these inter-connected tariffs, VLCs (customers with new demand exceeding 100 MWs, such as large data centers) will have access to reliable power to meet their needs and will directly pay for the electricity they consume, along with the power plants and distribution facilities built to serve them and operating and transmission costs allocated to their usage. The tariffs are designed so that the costs associated with these VLCs are not subsidized by or shifted to residential or business customers.

Thetwo new tariffs work in tandem as VLCs are required to sign a service agreement and subscribe to a portion ofone or more Bespoke Resources to service their electric load, including renewable generation facilities, battery storage, natural gas generation units, and PPAs. Under these agreements, if a VLC terminates or downsizes its plans, it will still be required to pay for the Bespoke Resources and dedicated distribution facilities that have been built to support its forecasted load, unless the facilities can be repurposed, subject to PSCW approval. Service agreements under the Bespoke Resources tariff will be effective for the depreciable life of a company-owned generation resource, except for wind and solar resources which will have a term of 20 years, or the duration of any PPAs that will be utilized as a Bespoke Resource. The ROE, which may range from 10.48% to 10.98% as agreed upon with the customer, and the equity ratio of 57% will both be fixed for the entire term of the agreement. The revenue and costs recovered through the tariffs will be excluded from future rate case proceedings and earnings sharing mechanisms.

In June 2026, WE, along withtwo intervenors, filed a petition for rehearing with the PSCW requesting reconsideration and modification to the credit support criteria and collateral provisions in the May 2026 order. The PSCW did not take action on the petition within the allowed 30-day time period so it was deemed denied by operation of law. A VLC had also filed a petition for review of the VLC tariff's credit support and collateral requirements in the Wisconsin Circuit Court, but subsequently withdrew its petition.

WE requires VLCs to enter into payment and cancellation agreements which obligate the VLC to reimburse WE for all costs associated with projects, including any associated costs incurred by ATC for transmission infrastructure projects, requested by the customer until service agreements are executed under the approved tariffs. Reimbursement is required if, among other things, the VLC terminates the payment and cancellation agreement or reduces its anticipated load, or regulatory approval is not received for the construction of a project.

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

2026 Rate Application

In January 2026, PGL and NSG filed requests with the ICC to increase their natural gas base rates. Subsequent to the initial filing, PGL and NSG made various concessions, compromises, and adjustments to their capital plans that reduced their initial requests by $57.3 million and $4.0 million, respectively. PGL and NSG are currently requesting rate increases of $144.0 million (14.6%) and $8.7 million (8.4%), respectively. The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL's rate request includes the estimated revenue requirements associated with its PRP projects. As discussed below, projects completed under PGL's PRP are to meet the ICC's directive to retire all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035. PGL's rate request includes the revenue requirements associated with approximately $349 million of capital investments planned under its PRP in 2027. Higher operating costs, driven by inflation, and increases in the cost of capital, also drove the requested rate increases. Both companies are requesting an ROE of 10.10% and a common equity component average of 54.0%.

An ICC decision is anticipated in the fourth quarter of 2026, with new rates expected to be effective by January 1, 2027.

2023 Rate Order

In January 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates. The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system. PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service. PGL did not request an extension of the QIP rider as PGL returned to the traditional rate making process to recover the costs of necessary infrastructure improvements.

In November 2023, the ICC issued final written orders approving base rate increases for PGL and NSG. The written orders were subsequently amended for various technical corrections. The amended written orders approved the following base rate increases:

•A $304.6 million (43.5%) base rate increase for PGL’s natural gas customers. This amount includes the recovery of costs that were previously being recovered under its QIP rider. PGL's new rates were effective December 1, 2023.

•An $11.0 million (11.6%) base rate increase for NSG’s natural gas customers. The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.

The ICC approved an authorized ROE of 9.38% for both PGL and NSG, and set the common equity component average at 50.79% and 52.58% for PGL and NSG, respectively.

As part of its decisions, the ICC, among other things, disallowed $236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. In addition, the ICC ordered PGL to pause spending on its projects to upgrade its natural gas delivery system until the ICC had a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In December 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 2023 written orders. The ICC granted PGL and NSG a limited-scope rehearing focused exclusively on the authorized spending for the completion of projects to upgrade PGL's natural gas delivery system that started in 2023 and emergency repairs needed to ensure the safety and reliability of the delivery system. In May 2024, the ICC issued a written order on the rehearing. The order approved $28.5 million of additional spending for emergency work, representing a $1.6 million increase to PGL's annual revenue requirement.

In June 2024, PGL and NSG filed a petition with the Illinois Appellate Court for review of the November 2023 and May 2024 orders; however, the Illinois Appellate Court affirmed these orders and the related disallowances in March 2026. PGL and NSG subsequently petitioned the Illinois Supreme Court for review and reversal of these orders, but their request was denied in September 2026.

In accordance with the November 2023 rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and a prudent investment level for replacing aging natural gas infrastructure. In February 2025, the ICC issued an order setting expectations for PGL's prospective operations. The ICC directed PGL to focus on retiring all cast and ductile iron pipes that have a diameter under 36 inches by January 1, 2035. The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute. PGL is working to retire this cast and ductile iron pipe through its PRP. Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases. In addition, the program will be overseen by a safety monitor hired by the ICC. As discussed above, PGL initiated a general rate case proceeding in January 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated with the PRP.

Illinois Riders

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC.

In May 2026, the ICC issued a final written order approving a settlement agreement PGL and NSG entered into with the Illinois Attorney General and ICC staff that resolved all open proceedings related to the 2019 through 2023 annual reconciliations of the UEA rider. Under the terms of the settlement, PGL and NSG will refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a period ofthree years between 2026 and 2028. Half of the refunds will be credited to customers in 2026, and 25% will be refunded in each of 2027 and 2028. PGL and NSG will begin refunding amounts in November 2026. As a result of this agreement, we recorded a $50.0 million reduction to revenues during the fourth quarter of 2025.

Qualifying Infrastructure Plant Rider

In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provided natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which was in effect until

December 1, 2023. As discussed above, PGL has returned to the traditional rate-making process for recovery of these costs, and they are now included in PGL's base rates.

Costs previously incurred under PGL's QIP rider were still subject to an annual reconciliation whereby such costs were reviewed for accuracy and prudency by the ICC. In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL subsequently filed a petition with the Illinois Appellate Court for review of the ICC's August 2024 order; however, in connection with the settlement agreement discussed below, in June 2026, PGL, the ICC, and the Illinois Attorney General filed a joint motion to dismiss the appeal with prejudice, which was granted by the court.

In May 2026, the ICC issued a final written order approving a settlement agreement PGL entered into with the Illinois Attorney General, ICC staff, and the Illinois Citizens Utility Board that resolved all remaining open annual reconciliation proceedings from 2017 through 2023 related to the QIP rider. Under the terms of the settlement, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a period ofthree years between 2026 and 2028. As a result of this agreement, we recorded a $155.0 million charge to income during the fourth quarter of 2025. The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $25.0 million reduction to revenues. The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at September 30, 2026 was $205.0 million. This includes the $155.0 million charge to income recorded during the fourth quarter of 2025 and a $50.0 million charge to income recorded in years prior to 2025. PGL will begin refunding amounts to customers in November 2026, with $25.0 million being refunded in each of thethree years starting in 2026 through 2028.

Upper Michigan Energy Resources Corporation

Amended Renewable Energy Plan

In accordance with Michigan Public Act 235, UMERC filed an AREP with the MPSC in February 2025. UMERC's AREP addressed its compliance with the Act 235 renewable portfolio standards and its proposal to recover the projected compliance costs through an incremental renewable energy surcharge. The projected compliance costs included the purchase of Michigan-sourced renewable energy credits and the revenue requirements for UMERC's previously approved investment in Renegade, a 100 MW utility-scale solar-powered electric generating facility, and any other incremental renewable generation resources required to meet the Act 235 renewable portfolio standards. In December 2025, the MPSC issued an order denying UMERC's AREP. UMERC is required to file a new AREP by the end of 2026.

Renegade achieved commercial operation in March 2026. The estimated cost of Renegade is approximately $226 million. As UMERC's proposal to recover the annual revenue requirement of Renegade through a renewable energy surcharge was denied, UMERC subsequently filed a request for deferral accounting treatment. In April 2026, the MPSC issued an order authorizing UMERC to defer all of the costs associated with owning and operating Renegade. The costs will be reviewed for recovery in a future proceeding.

NOTE 25—OTHER INCOME, NET

Total other income, net was as follows for the three and nine months ended September 30:

(1)Amounts do not include equity earnings of transmission affiliates as those earnings are shown as a separate line item on the income statements.

NOTE 26—NEW ACCOUNTING PRONOUNCEMENTS

Environmental Credits and Environmental Credit Obligations

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818). The amendments improve the financial accounting for and disclosure of environmental credits and environmental credit obligations. The update provides recognition, measurement, presentation, and disclosure requirements for all entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits. The amendments are effective for annual periods beginning after December 15, 2027, and interim periods within those annual periods. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Interim Reporting

In December 2025, the FASB issued ASU No. 2025-11, Interim Reporting (Topic 270) Narrow-Scope Improvements. The amendments clarify interim disclosure requirements and the applicability of Topic 270. The amendments include a comprehensive list of interim disclosures that are currently required under GAAP. The amendments also include a disclosure principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. Finally, the amendments clarify the types of interim reporting and the form and content of interim financial statements in accordance with GAAP. The amendments are effective for interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Accounting for Government Grants

In December 2025, the FASB issued ASU No. 2025-10, Government Grants (Topic 832) Accounting for Government Grants Received by Business Entities. The amendments establish the accounting for a government grant received by a business entity, including guidance for a grant related to an asset and a grant related to income. The amendments also require disclosures, including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. The amendments are effective for annual periods beginning after December 15, 2028, and interim periods within those annual periods, with early adoption permitted. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) Disaggregation of Income Statement Expenses. The amendments require disclosure of certain costs and expenses in the notes to financial statements, which are disaggregated from relevant expense captions on the income statement. The amendments also require additional qualitative disclosures of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. Finally, the amendments require disclosure of the total amount of selling expenses and, in annual reporting periods, an entity's definition of selling expenses. The amendments are effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with early adoption permitted. We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2027, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.