WEC ENERGY GROUP, INC.

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

As used in these notes, the term "financial statements" refers to the 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. 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 sheet as of December 31, 2025 related to the minority interests held by third parties in the renewable generating facilities that are included in our non-utility energy infrastructure segment.

Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:

•Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.

•Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.

•Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.

•Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.

•Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our majority interests in multiple renewable generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on recently acquired WECI renewable generating facilities.

•Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities.

Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly-Owned Utility Facilities, for more information.

(b) Basis of Presentation—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity ofthree months or less.

(d) Operating Revenues—The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues.

Revenues from Contracts with Customers

Electric Utility Operating Revenues

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist ofone distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation.

The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together underone contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity containtwo performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales, and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Natural Gas Utility Operating Revenues

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.

The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. Under normal circumstances, we defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. Finally, through the end of 2023 and effective again starting January 1, 2025, the rates of MGU include a rider to recover costs incurred to replace or modify natural gas facilities.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater owns underground natural gas storage facilities in southeastern Michigan and provides natural gas storage and hub services to customers. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. We recognize revenues using a time-based output method through a monthly fixed service fee. Typical storage contract rates consist of firm storage reservation charges and firm injection and withdrawal charges. All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

Wind and solar generation revenues from WECI's ownership interests in renewable generation facilities continued to grow in 2025. See Note 2, Acquisitions, for more information on recent acquisitions. Most of these renewable generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with capacity and RECs. We consider bundled energy, capacity, and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace.

When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the renewable generation facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and the recognition of REC revenues generally occur concurrently.

Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration ofone year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.

Consistent with the timing of when we recognize revenue, customer billings for the renewable generation and servicing revenues generally occur on a monthly basis, with payments typically due in full within 30 days.

As part of the construction of the We Power electric 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. During 2025, 2024, and 2023, we recorded $24.6 million, $24.3 million, and $23.5 million, respectively, of revenues related to these deferred carrying costs.

Other Operating Revenues

Bespoke Resources Current Return

We recognize revenues monthly associated with carrying costs, including financing costs, during the construction period of bespoke resources assigned to WE's very large utility customers under payment and cancellation agreements. These amounts are not considered revenues from contracts with customers as electricity is not yet being provided by WE. 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, with payments typically due in full within 45 days.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Below is a summary of the alternative revenue programs at our utilities:

•The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

•MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.

•WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

(e) Credit Losses—The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see 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.

(f) Materials, Supplies, and Inventories—Our inventories as of December 31 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. Inventories stated on a LIFO basis represented approximately 17% and 18% of total inventories at December 31, 2025 and 2024, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2025 and 2024, exceeded the LIFO cost by $94.9 million and $77.9 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.36 at December 31, 2025, and $3.10 at December 31, 2024.

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

(g) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the ratemaking process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 6, Regulatory Assets and Liabilities, for more information.

(h) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2.

We depreciate our WECI assets over the estimated useful life of the property, with wind and solar generating facilities being depreciated over 30 and 35 years, respectively.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.

See Note 7, Property, Plant, and Equipment, for more information.

(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC-Debt) used during plant construction, and a return on shareholders' capital (AFUDC-Equity) used for construction purposes. AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. AFUDC rates are determined by their respective state commissions, each with specific requirements. Average AFUDC rates are shown below:

Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31:

See Note 16, Income Taxes, for more information on how AFUDC-Equity is treated for tax purposes and the related impact on total WEC Energy Group income tax expense.

(j) Cloud Computing Hosting Arrangements that are Service Contracts—We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, a centralized repository for data to improve analytics, reporting, work and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, training, information technology service management, and customer contact systems. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements.

At December 31, 2025 and 2024, we had $27.0 million and $17.0 million, respectively, of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Accumulated amortization at December 31, 2025 and 2024, was $5.8 million and $4.1 million, respectively. Amortization expense for the years ended December 31, 2025, 2024, and 2023 was not significant. The presentation of the implementation costs, along with the related accumulated amortization, follows the prepaid hosting fees.

(k) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test for all of our reporting units that carried a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value. An impairment loss is recorded as the excess of the carrying amount of the goodwill over its fair value. For our indefinite-lived intangible assets, an impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. An impairment loss is measured as the excess of the carrying amount of the intangible asset over its fair value. No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2025, 2024, and 2023. See Note 10, Goodwill and Intangibles, for more information.

We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

We also periodically assess the recoverability of our non-utility long-lived assets, which includes reviewing current activities, changes in the conditions of our renewable generating facilities, and market conditions in which they operate to determine the existence of any indicators requiring an impairment analysis. Indicators of potential impairment for a non-utility long-lived asset group, generally an individual renewable generation project, include adverse changes in the financial condition of a customer to our offtake agreements, a significant decline in the forecasted operating revenues and earnings of our renewable generation projects, and deterioration in the performance of our renewable generation projects.

We assess the likelihood of a disallowance of part of the cost of recently completed plant by considering factors such as applicable regulatory environment changes, our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. When it becomes probable that part of the cost of recently completed plant will be disallowed for rate-making purposes, we assess whether a reasonable estimate of the amount of the disallowance can be made. The estimated amount of the probable disallowance will then be deducted from the reported cost of the plant and recognized as an impairment loss.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 6, Regulatory Assets and Liabilities, and Note 7, Property, Plant, and Equipment, for more information.

We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.

We recorded the following impairment losses on our income statements in the following segments during the years ended December 31:

(1)Represents a probable disallowance of certain capital costs at PGL under the QIP rider. See Note 26, Regulatory Environment, for more information.

(2)Represents a disallowance of certain previously incurred capital costs at PGL resulting from an ICC order received in August 2024 related to the 2016 annual prudency review of the QIP rider. See Note 26, Regulatory Environment, for more information.

(3)Represents a disallowance of certain previously incurred capital costs resulting from PGL's and NSG's November 2023 rate orders from the ICC. See Note 26, Regulatory Environment, for more information.

(4)Represents impairment losses related to storm damage at certain of WECI's renewable generation facilities.

(l) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.

(m) Finite-Lived Intangible Asset and Liabilities—Our finite-lived intangible asset and liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which resulted from the acquisitions of renewable generation facilities by WECI in our non-utility energy infrastructure segment. Intangible asset and liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the related agreement. Amortization of the revenue intangible asset and liabilities are recorded within operating revenues in the income statements. Amortization of the interconnection agreement intangible liabilities is recorded within other operation and maintenance in the income statements. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used. The amounts and useful lives assigned to the intangible asset and liabilities assumed impact the amount and timing of future amortization. See Note 10, Goodwill and Intangibles, for more information.

(n) Stock-Based Compensation—In accordance with the Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. In addition to those shares of common stock that were subject to awards outstanding as of May 6, 2021, when the plan was last approved by shareholders,9.0 million shares were reserved for issuance under the plan.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur.

Stock Options

We grant non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised withinsix months of the grant date except in connection with certain termination of employment events following a change in control. Options expire no later than 10 years from the date of the grant.

Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models:

The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience.

Restricted Shares

Restricted shares granted to employees generally have a vesting period ofthree years with one-third of the award vesting on each anniversary of the grant date. Restricted shares granted to non-employee directors fully vest afterone year.

Our restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. Performance units accrue forfeitable dividend equivalents in the form of additional performance units. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which isthree years.

Pursuant to the terms of the WEC Energy Group Performance Unit Plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout of the performance unit awards. The ultimate number of units that will be paid out will be based on our total shareholder return compared to the total shareholder return of a peer group of companies over three years (55%), and our performance against the weighted average authorized ROE of all of our utility subsidiaries (45%). In addition, the Compensation Committee selected the level of our stock price to earnings ratio compared to our peer companies as a performance measure that can increase the payout by up to 25%. In no event can the performance unit payout be greater than 200% of the target award.

See Note 11, Common Equity, for more information on our stock-based compensation plans.

(o) Earnings Per Share—We compute basic EPS by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed in a similar manner, but includes the exercise, settlement, and/or conversion of all potentially dilutive securities. Our potentially dilutive securities include stock options, forward equity sales contracts, and shares issuable upon the conversion of our convertible debt instruments.

The dilutive impacts from our in-the-money stock options and forward equity sales contract are calculated using the treasury stock method. The calculation of diluted EPS for the year ended December 31, 2025 excluded 58,533 shares issuable under our forward equity sales contract as their effect was anti-dilutive. The calculation of diluted EPS for the years ended December 31, 2024 and 2023 excluded 66,870 and 1,716,286 stock options, respectively, that had an anti-dilutive effect. No stock options had an anti-dilutive effect for the year ended December 31, 2025, and we did not have any forward equity sales contracts prior to 2025.

Potentially dilutive common shares issuable upon conversion of our convertible debt instruments are calculated using the if-converted method. For the year ended December 31, 2025, there wereno shares of our common stock related to the potential conversion of the 2028 Notes (issued in June 2025) included in our diluted EPS calculation as the impact was anti-dilutive. For the year ended December 31, 2024, there wereno shares of our common stock related to the potential conversion of the 2027 Notes and 2029 Notes (both issued in 2024) included in our diluted EPS calculation as the impact was anti-dilutive.

See Note 11, Common Equity, for more information on the computation of our basic and diluted EPS.

(p) Leases—We recognize a right of use asset and lease liability for operating and finance leases with a term of greater thanone year. As a policy election, we account for each lease component separately from the nonlease components of a contract.

We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our renewable generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.

See Note 15, Leases, for more information.

(q) Income Taxes—In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table. The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold. For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold. We adopted ASU No. 2023-09 on January 1, 2025, on a retroactive basis, with the required disclosures first included in our 2025 Annual Report on Form 10-K.

We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

ITCs are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return.

We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.

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 the majority of the PTCs and ITCs we generated in 2023, 2024, and 2025 to third parties. See Note 16, Income Taxes, for more information on the PTCs we sold. We have also entered into an agreement to sell the majority of PTCs that we expect to generate in 2026 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.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. We adopted the safe harbor method of accounting for certain of our utilities on our 2023 tax return and adopted the safe harbor method of accounting for our remaining utilities on our 2024 tax return, which increased our deferred tax liabilities.

See Note 16, Income Taxes, for more information.

(r) 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 RTO.

See Note 17, Fair Value Measurements, for more information.

(s) 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 assets or liabilities 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.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information.

(t) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. See Note 19, Guarantees, for more information.

(u) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 20, Employee Benefits, for more information.

(v) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

(w) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including CCR landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding CCR landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable, and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state regulatory commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and CCR landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(x) Customer Concentrations of Credit Risk—The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations, and we could recognize financial losses as a result. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. There wereno customers that accounted for more than 10% of our revenues for the year ended December 31, 2025.

As a result, for the majority of our utility companies, we did not have any significant concentrations of credit risk at December 31, 2025. However, WE has contracts with a small number of customers to provide power to large-scale data centers to support AI and other technology capabilities. This concentration of business with a small number of customers in an industry based on emerging technologies presents several risks. WE is incurring significant costs to construct bespoke resources to serve these customers. Although WE requires these customers to enter into payment and cancellation agreements, WE may still experience significant losses or delayed recovery of these costs. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers, which would reduce our forecasted revenues. Significant capital spend to build out required infrastructure or a downturn in business could weaken their financial condition, liquidity and/or creditworthiness, including their ability to satisfy their reimbursement obligations to us.

NOTE 2—ACQUISITIONS

In accordance with Topic 805: Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions. It was determined that all of the below acquisitions met the criteria of asset acquisitions. The purchase price of certain acquisitions below includes intangibles recorded as long-term assets and long-term liabilities related to PPAs. See Note 10, Goodwill and Intangibles, for more information.

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 $406.1 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.

Acquisitions of Solar Generation Facilities in Texas

Upon commercial operation in December 2024, WECI completed the acquisition of a 90% ownership interest in Delilah I, a 300 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas. Delilah I was acquired for $462.5 million, which included transaction costs and was net of cash acquired. The project has offtake agreements for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Delilah I qualifies for PTCs and is included in the non-utility energy infrastructure segment.

In February 2023, WECI completed the acquisition of an 80% ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar, Franklin, Hopkins, and Red River counties in Texas. Samson I was acquired for $257.3 million, which included transaction costs and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation in May 2022. Samson I qualifies for PTCs and is included in the non-utility energy infrastructure segment. In January 2024, WECI acquired an additional 10% ownership interest in Samson I for $28.1 million.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the original acquisition.

Acquisitions of Electric Generation Facilities in Illinois

Upon commercial operation in November 2024, WECI completed the acquisition of a 90% ownership interest in Maple Flats, a 250 MW solar generating facility in Clay County, Illinois. Maple Flats was acquired for $431.2 million, which included transaction costs and was net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years from the date of commercial operation. Maple Flats qualifies for PTCs and is included in the non-utility energy infrastructure segment.

In February 2023, upon achievement of commercial operation, WECI completed the acquisition of a 90% ownership interest in Sapphire Sky, a 250 MW wind generating facility in McLean County, Illinois, for a total investment of $442.6 million, which includes transaction costs and is net of cash acquired. The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years from the date of commercial operation. Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

Acquisitions of Electric Generation Facilities in Wisconsin

In December 2025, WE and WPS, along with an unaffiliated utility, signed an agreement to acquire Whitetail, a wind-powered electric generation project with a total capacity of 67.2 MW. This project 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.

In May 2024, WE completed the acquisition of an additional 100 MWs of West Riverside's nameplate capacity for $97.9 million. West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin. In June 2023, WE completed the first acquisition of 100 MWs for $95.3 million. After the second acquisition, WE owns 200 MWs, or 27.5%, of West Riverside at a total cost of $193.2 million.

In April 2023, WPS, along with an unaffiliated utility, completed the acquisition of Red Barn, a commercially operational utility-scale wind-powered electric generating facility. The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project. WPS's share of the cost of this project was $145.9 million. Red Barn qualifies for PTCs.

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

NOTE 3—DISPOSITION

Wisconsin Segment

Sale of Certain Real Estate by Wisconsin Electric Power Company

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

NOTE 4—OPERATING REVENUES

For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues.

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:

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 at our utilities, compared with the recovery of natural gas costs that were anticipated in rates.

(2)For our Illinois segment, includes a $75.0 million reduction in revenues recorded in the fourth quarter of 2025 for future billing credits to customers, based on the terms of a proposed settlement in February 2026 to resolve open QIP and UEA proceedings.

Other Non-Utility Operating Revenues

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

Other Operating Revenues

Other operating revenues consist primarily of the following:

(1)Bespoke resources current return consists of carrying costs earned during the construction of bespoke resources assigned to WE's VLCs. See Note 1(d), Operating Revenues, for more information.

(2)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.

NOTE 5—CREDIT LOSSES

We have included tables below that show our gross third-party receivable balances and the related allowance for credit losses at December 31, 2025 and 2024, 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 December 31, 2025, $1,290.2 million, or 62.5%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. See Note 26, 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 rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2025, 2024, and 2023, is included below:

On a consolidated basis, there was a $14.1 million decrease in the allowance for credit losses during the year ended December 31, 2025. This decrease is 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.

On a consolidated basis, there was a $30.7 million decrease in the allowance for credit losses during the year ended December 31, 2024, largely driven by customer write-offs. We also believe that the lower energy costs that customers were seeing, which were driven by warmer than normal weather conditions during most of 2024 and low average natural gas prices, contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses.

On a consolidated basis, there was a $5.8 million decrease in the allowance for credit losses during the year ended December 31, 2023, primarily related to lower customer energy costs (driven by the warmer weather during the fourth quarter of 2023 when compared to the same quarter in 2022 and lower natural gas prices), which contributed to a reduction in past due accounts receivable balances and a related decrease in the allowance for credit losses. Customer write-offs also contributed to the decrease in the allowance for credit losses.

NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:

(1)Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $20.9 million and $26.7 million at December 31, 2025 and 2024, respectively.

(2)As of December 31, 2025, we had $183.1 million of regulatory assets not earning a return, $1.3 million of regulatory assets earning a return based on short-term interest rates, $106.1 million of regulatory assets earning a return based on long-term interest rates, and $5.5 million of regulatory assets earning a return based on the applicable utility's ROE. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, decoupling mechanisms, electric transmission costs, unamortized loss on reacquired debt, and uncollectible expense. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.

(3)Primarily represents the net book value of power plants we have both abandoned and retired. For all of these plants, we have approval to collect a return of their remaining net book value. We also have approval to collect a return on all but $100 million of their remaining net book value. For information on the securitization of this $100 million, see Note 23, Variable Interest Entities. These regulatory assets are amortized on a straight-line basis, using the composite depreciation rates approved before the plants were retired, and the amortization is included in depreciation and amortization in the income statement.

(4)As of December 31, 2025, we had made cash expenditures of $81.9 million related to these environmental remediation costs. The remaining $484.1 million represents our estimated future cash expenditures.

(5)Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.

(6)This regulatory asset relates to WE's 2014 announcement to retire the PIPP. Despite WE's intent to retire the PIPP, MISO designated the PIPP as a SSR, which meant the PIPP's operation was necessary for reliability, and the plant could not be shut down until new generation or transmission facilities were built. In December 2014, the PSCW authorized escrow accounting for WE's SSR revenues because of the fluctuations in the actual revenues WE received under the PIPP SSR agreements. The rate order WE received from the PSCW in December 2019 authorized recovery of this SSR regulatory asset over a 15-year period that began on January 1, 2020.

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

(8)In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

(9)Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards.

The following regulatory liabilities were reflected on our balance sheets as of December 31:

(1)Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 9, Asset Retirement Obligations, for more information on our legal obligations.

(2)Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.

(3)MERC defers as a regulatory asset or liability the difference between actual property tax expense and the amount included in rates until

recovery or refund is authorized in a future rate proceeding.

(4)These amounts represent the deferral of the incremental revenue requirement impact from the delayed in-service date of certain renewable generation facilities constructed by our electric utilities.

Oak Creek Power Plant Units 5-6

In May 2024, OCPP Units 5 and 6 were retired. Due to the retirement of these units and the determination that recovery was probable, their net book value of $68.3 million at December 31, 2025 was classified as a regulatory asset. In addition, a $45.0 million cost of removal reserve related to the units continued to be classified as a regulatory liability at December 31, 2025. Not included in these amounts was $6.3 million of deferred tax liabilities previously recorded for the retired units. Effective with its rate order issued by the PSCW in December 2022, WE received approval to collect a return of and on the entire net book value of OCPP Units 5 and 6 and, as a result, will continue to amortize the regulatory asset on a straight-line basis, using the composite depreciation rates approved by the PSCW before the units were retired. The amortization is included in depreciation and amortization on the income statement. WE also has FERC approval to continue to collect the net book value of OCPP Units 5 and 6 using the approved composite depreciation rates, in addition to a return on the remaining net book value.

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following at December 31:

Severance Liability for Plant Retirements

We have severance liabilities related to past and future plant retirements recorded in other current and other long-term liabilities on our balance sheets. Activity related to these severance liabilities for the years ended December 31 was as follows:

(1)The severance accrual was lowered in 2024 due to workforce realignment efforts.

Wisconsin Segment Plant to be Retired

Oak Creek Power Plant Units 7 and 8

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 7 and 8 became probable. Subsequently, we have received PSCW approval for several other renewable and other projects and have also acquired additional projects. On June 25, 2025, we announced plans to extend the lives of OCPP Units 7 and 8, and expect to have the units available to meet high energy demand periods through the end of 2026. These units were originally scheduled to be retired at the end of 2025. The total net book value of WE's ownership share of OCPP Units 7 and 8 was $621.7 million at December 31, 2025, which does not include deferred taxes. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Columbia Energy Center Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable. Through June 30, 2025, Columbia Units 1 and 2 were expected to be retired by the end of 2029 and, therefore, met the criteria to be considered probable of abandonment.

In conjunction with our new capital plan, we and the other co-owners currently plan to continue coal operations at Columbia Units 1 and 2 through at least 2029, and continue to evaluate the conversion of both units to natural gas. As a result, we and the other co-owners concluded that Columbia Units 1 and 2 (net book value of WPS's ownership share of Columbia Units 1 and 2 was $236.8 million at December 31, 2025, which does not include deferred taxes) no longer meet the criteria necessary to be considered probable of abandonment.

At December 31, 2025, these units continue to be included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Samson 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 addition, 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 as a result of ongoing damage assessment.

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

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 would resolve its open QIP proceedings.

In August 2024, the ICC issued a final order on PGL's 2016 QIP annual reconciliation, which included a disallowance of certain capital costs. As a result, we recorded a $12.1 million impairment to property, plant, and equipment in 2024.

In November 2023, the ICC issued written rate orders that disallowed $177.2 million of previously incurred capital costs related to the construction and improvement of PGL’s service centers and $1.7 million of capital costs related to NSG's construction of a gas infrastructure project. As a result of these disallowances, we recorded a $178.9 million non-cash impairment to property, plant, and equipment in 2023.

See Note 26, Regulatory Environment, for more information.

NOTE 8—JOINTLY-OWNED UTILITY FACILITIES

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

Information related to jointly owned utility facilities in-service at December 31, 2025 was as follows:

(1)We Power leases its ownership interest in ER 1 and ER 2 to WE.

(2)Capacity is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2026 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(3)Capacity for wind generating facilities is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds.

(4)Capacity for solar generating facilities is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(5)WE acquired a 13.8% ownership interest in June 2023 and acquired an additional 13.7% ownership interest in May 2024. See Note 2, Acquisitions, for more information.

Information related to jointly owned utility facilities approved by the PSCW at December 31, 2025 was as follows:

NOTE 9—ASSET RETIREMENT OBLIGATIONS

Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of a biomass generation facility; the dismantling of wind and solar generation projects; the removal and dismantlement of a battery storage facility; the disposal of PCB-contaminated transformers; the closure of CCR landfills at certain generation facilities; and the removal of above ground and underground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators.

WECI has also recorded AROs for the dismantling of our non-utility renewable generation projects.

The following table shows changes to our AROs during the years ended December 31:

(1)AROs increased primarily as a result of AROs being recorded related to the new EPA CCR Rule that was enacted in April 2024. See Note 24, Commitments and Contingencies, for more information.

(2)AROs decreased primarily due to revisions made to estimated cash flows for changes in removal cost estimates and settlements dates for mains and services at PGL and NSG.

NOTE 10—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 December 31, 2025. We hadno changes to the carrying amount of goodwill during the years ended December 31, 2025 and 2024.

(1)We hadno accumulated impairment losses related to our goodwill as of December 31, 2025.

During the third quarter of 2025, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2025. No impairments resulted from these tests.

Other Indefinite-Lived Intangible Assets

At December 31, 2025 and 2024, we had $44.4 million and $29.3 million, respectively, of other indefinite-lived intangible assets included in other long-term assets on our balance sheets. These assets consist 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. In October 2025, we entered into an option agreement for exclusive rights to purchase land for future generation development in Wisconsin. We made the first annual option payment and incurred costs of $15.1 million during 2025, with a right to exercise our option on or before December 31, 2030.

Finite-Lived Intangible Asset

At December 31, 2025 and 2024, we had a finite-lived intangible asset with a gross carrying amount of $18.8 million and $13.0 million, respectively, related to a PPA for Maple Flats acquired by WECI in November 2024. The PPA will be amortized over a useful life of 15 years and expires in 2039. At December 31, 2025 and 2024, accumulated amortization related to the intangible asset was not material. This finite-lived intangible asset is included in other long-term assets on our balance sheet. Amortization expense related to the intangible asset was not material for the year ended December 31, 2025 and 2024. Amortization expense to be recorded as a decrease to operating revenues is expected to be $1.3 million in each of the next five years. See Note 2, Acquisitions, for more information on the acquisition of Maple Flats.

Intangible Liabilities

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

(1)Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, Sapphire Sky, Delilah I, and Hardin III expiring between 2030 and 2040. The weighted-average remaining useful life of the PPAs is 10 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's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap isthree years.

(3)Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 15 years.

Amortization related to these intangible liabilities for the years ended December 31, 2025, 2024, and 2023 was $58.1 million, $53.7 million, and $50.6 million, respectively. Amortization for the next five years is estimated to be:

NOTE 11—COMMON EQUITY

Stock-Based Compensation

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31:

(1)The reduction in expense was due to a decrease in the fair value of the outstanding performance units.

Stock-based compensation costs capitalized during 2025, 2024, and 2023 were not significant.

Stock Options

The following is a summary of our stock option activity during 2025:

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2025. This is calculated as the difference between our closing stock price on December 31, 2025, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2025, 2024, and 2023 was $22.8 million, $11.2 million, and $5.2 million, respectively. The tax benefit from option exercises for the same years was approximately $6.3 million, $3.1 million, and $1.4 million, respectively. These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, approximately $1.4 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, the Compensation Committee awarded 269,085 non-qualified stock options with a weighted-average exercise price of $106.09 and a weighted-average grant date fair value of $21.20 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following restricted stock activity occurred during 2025:

The intrinsic value of restricted stock released was $5.7 million, $8.6 million, and $5.8 million for the years ended December 31, 2025, 2024, and 2023, respectively. The tax benefit from released restricted shares for the same years was $1.6 million, $2.4 million, and $1.6 million, respectively. These amounts do not account for the compensation limitations under Internal Revenue Code Section 162(m).

As of December 31, 2025, approximately $4.9 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, the Compensation Committee awarded 75,222 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $106.09 per share.

Performance Units

During 2025, 2024, and 2023, the Compensation Committee awarded 185,945;205,051; and 157,035 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.

Performance units with an intrinsic value of $15.4 million, $2.4 million, and $10.2 million were settled during 2025, 2024, and 2023, respectively. The tax benefit from the distribution of performance units for the same years was $3.8 million, $0.6 million, and $2.6 million, respectively.

At December 31, 2025, we had 502,733 performance units outstanding, including dividend equivalents. A liability of $57.1 million was recorded on our balance sheet at December 31, 2025 related to these outstanding units. As of December 31, 2025, approximately $31.3 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.7 years on a weighted-average basis.

During the first quarter of 2026, we settled performance units with an intrinsic value of $25.2 million. The tax benefit from the distribution of these awards was $5.7 million. This amount and the tax benefits disclosed above do not account for the compensation limitations under Internal Revenue Code Section 162(m). In January 2026, the Compensation Committee also awarded 182,146 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

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, 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. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly.

In accordance with their most recent rate orders, WE, WPS, and WG may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized level of 53.0%. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level.

WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a 12-month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

The long-term debt obligations of UMERC, Bluewater Gas Storage, and ATC Holding contain a provision requiring them to maintain a total funded debt to capitalization ratio of 65% or less.

The long-term debt obligations of WECI Wind Holding I, WECI Wind Holding II, and WECI Energy Holding III contain various conditions that must be met prior to them making any cash distributions. Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater prior to the distribution.

WEC Energy Group has the option to defer interest payments on its 2024A Junior Notes, 2024B Junior Notes, and 2025 Junior Notes, from time to time, forone or more periods of up to 10 consecutive years per period. During any period in which it defers interest payments, it may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, its common stock.

See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2025, restricted net assets of our consolidated subsidiaries totaled approximately $14 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $615 million.

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

Common Stock

As of January 1, 2024, we began issuing 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. During 2023, we instructed our independent agents to purchase shares on the open market to fulfill obligations under these plans. As such, no new shares of common stock were issued during the year ended December 31, 2023.

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, which included an equity forward sales component. This EDA was terminated on October 31, 2025. Prior to its termination, we issued 7,610,457 shares of common stock under this EDA and received proceeds of $797.3 million, which was net of $9.2 million of commissions and other fees. We did not enter into any forward sales agreements under the August 2024 EDA.

In connection with our termination of the August 2024 EDA, we entered into a new EDA on October 31, 2025, 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, which 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. As of December 31, 2025, we had not issued any shares of common stock under the October 2025 EDA.

In November 2025, we entered into a forward sales contract pursuant to our October 2025 EDA. Pursuant to the terms of the contract,58,533 shares were sold with an initial forward price of $110.7748 per share. 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 this contract until actual settlement occurs. The contract requires us to, at our election on or before June 30, 2027, 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. As of December 31, 2025, no shares were settled under this contract. At December 31, 2025, we could have settled this forward sales contract with physical delivery of 58,533 shares of common stock to the counterparties in exchange for cash proceeds of $6.5 million. The forward sales contract could have alternatively been settled with delivery of approximately $0.3 million of cash or approximately 3,084 shares of common stock to us, if we had elected to net cash or net share settle, respectively, at December 31, 2025.

Any shares offered and sold under our EDAs were done pursuant to our registration statement on Form S-3 filed with the SEC on August 5, 2024 and the related prospectus supplements.

We had the following changes to our outstanding common stock during the years ended December 31, 2025 and 2024:

The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31:

During the year ended December 31, 2025, our Board of Directors declared common stock dividends which are summarized below:

On January 22, 2026, our Board of Directors declared a quarterly cash dividend of $0.9525 per share, which equates to an annual dividend of $3.81 per share. The dividend is payable on March 1, 2026, to shareholders of record on February 13, 2026.

Earnings Per Share

The following table shows the computation of our basic and diluted EPS for the years ended December 31:

NOTE 12—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2025 and 2024:

NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:

(1)Coyote Ridge, Tatanka Ridge, Samson I, 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 2025, was $1,124.2 million with a weighted-average interest rate during the period of 4.43%.

WEC Energy Group, WE, PGL, WPS, and WG have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0%,65.0%,65.0%,65.0%, and 65.0% or less, respectively. As of December 31, 2025, all companies were in compliance with their respective ratio.

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 as of December 31:

(1)These revolving credit facilities have a renewal provision fortwo extensions, subject to lender approval. Each extension is for a period ofone year.

(2)In August 2025, the capacity of the credit facilities for each of WEC Energy Group, WE, PGL, and WPS was increased to $1,700.0 million, $800.0 million, $600.0 million, and $450.0 million, respectively, and the maturity for each facility was extended to August 2030.

(3)In August 2025, WEC Energy Group terminated its $200.0 million bilateral credit facility.

(4)In August 2025, WG extended the maturity of its credit facility to August 2030.

The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of WEC Energy Group's credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.

NOTE 14—LONG-TERM DEBT

The following table is a summary of our long-term debt outstanding as of December 31:

(1)In November 2025, we issued our 2025 Junior Notes. Our 2025 Junior Notes are fixed-to-fixed reset rate junior subordinated notes. The rate for our 2025 Junior Notes was 5.625% as of December 31, 2025. The rate for our 2025 Junior Notes will reset on May 15, 2031; provided the reset rate will not be less than 5.625%.

(2)In December 2024, we issued our 2024A Junior Notes and 2024B Junior Notes. Our 2024A Junior Notes and 2024B Junior Notes are fixed-to-fixed reset rate junior subordinated notes. The rate for our 2024A Junior Notes was 6.69% as of December 31, 2025. The rate for our 2024A Junior Notes will reset on June 15, 2030. The rate for our 2024B Junior Notes was 6.74% as of December 31, 2025. The rate for our 2024B Junior Notes will reset on June 15, 2035.

(3)PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.

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 million of collateralized First Mortgage Bonds.

(4)NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

(5)The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, WECI Energy Holding III, WEPCo Environmental Trust, and We Power's subsidiaries requires periodic principal payments.

(6)We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable.

(7)WECI Wind Holding I's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Wind Holding I.

(8)WECI Wind Holding II's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Wind Holding II.

(9)WECI Energy Holding III's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries, as well as a pledge of equity in WECI Energy Holding III.

(10)WEPCo Environmental Trust’s ETBs are secured by a pledge of and lien on environmental control property, which includes the right to impose, collect and receive a non-bypassable environmental control charge paid by all of WE's retail electric distribution customers, the right to obtain true-up adjustments of the environmental control charges, and all revenues or other proceeds arising from those rights and interests. See Note 23, Variable Interest Entities, for more information.

We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.

In December 2024, the DOE issued to WE a conditional commitment for a federal loan guarantee for up to $2.5 billion of borrowings that would be used by WE to fund a portion of the costs to construct certain utility-scale renewable generation projects. The conditional commitment was issued pursuant to provisions of the IRA. Under the conditional commitment, the guaranteed borrowings would be senior, unsecured borrowings of WE made through the Federal Financing Bank and reduce WE's issuance of senior, unsecured obligations in the capital markets. Final approval and issuance of a loan guarantee by the DOE is subject to numerous conditions, including negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and the satisfaction of other conditions. While we continue to work with the DOE, there can be no assurance that the DOE will issue the loan guarantee for WE.

WEC Energy Group, Inc.

In June 2025, the remaining $120.0 million outstanding of our 3.55% Senior Notes, due June 15, 2025, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In September 2025, our $500.0 million of 5.00% Senior Notes due September 27, 2025, matured, and principal and accrued interest were paid with proceeds received from issuing commercial paper.

In November 2025, we issued $600.0 million of 5.625% 2025 Junior Notes due May 15, 2056, and used the net proceeds to repay short-term debt and for other general corporate purposes.

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.

Convertible Senior Notes

2028 Notes

In June 2025, we issued $900.0 million of 2028 Notes. The 2028 Notes are senior unsecured obligations and bear interest at an annual rate of 3.375%, payable semiannually beginning on December 1, 2025. Proceeds from the offering were used to repay short-term debt and for other general corporate purposes.

The 2028 Notes will mature on June 1, 2028, unless earlier converted or repurchased in accordance with their terms. No sinking fund is provided for the 2028 Notes. Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2028 Notes. We may not redeem the 2028 Notes prior to their maturity date. Any fundamental change repurchases of the 2028 Notes will be at a price equal to 100% of the principal amount, plus accrued and unpaid interest.

Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2028, only under the following circumstances:

•During any calendar quarter commencing after the calendar quarter ending on September 30, 2025, (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price of such series of notes on each applicable trading day;

•During thefive consecutive business day period immediately after anyten consecutive trading day period (measurement period) in which the trading price per $1,000 principal amount of notes, as determined following a request by a holder or holders, for each trading day of the measurement period was less than 98% of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day; or

•Upon the occurrence of specified corporate events, as defined in the related indenture.

Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2028, until the close of business on the second scheduled trading day immediately preceding the maturity date.

Upon conversion, we will pay cash up to the aggregate principal amount of the notes to be converted and pay or deliver cash, shares of our common stock, or a combination of cash and shares of our common stock, at our election, in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted.

The initial conversion rate for the 2028 Notes is 7.7901 shares of common stock per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $128.37 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for any accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

2027 Notes and 2029 Notes

In the second quarter of 2024, we issued $862.5 million of 2027 Notes and $862.5 million of 2029 Notes. The 2027 Notes and 2029 Notes are senior unsecured obligations and bear interest at an annual rate of 4.375%, payable semiannually beginning on December 1, 2024. Proceeds from the offerings were used to repay short-term debt and for general corporate purposes.

The 2027 Notes will mature on June 1, 2027, and the 2029 Notes will mature on June 1, 2029, unless earlier converted or repurchased in accordance with their terms, or in the case of the 2029 Notes, redeemed by us. No sinking fund is provided for either series of the notes. Upon the occurrence of a fundamental change, as defined in the related indenture, holders may require us to repurchase for cash all or any portion of their 2027 or 2029 Notes. We may not redeem the 2027 Notes prior to their maturity date. We may redeem for cash all or part of the 2029 Notes, at our option, on or after June 1, 2027 and on or before the 41 st scheduled trading day immediately preceding their maturity date, if the last reported sale price per share of our common stock has been at least 130% of the conversion price of the 2029 Notes then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period. Any redemptions or fundamental change repurchases of the 2027 Notes or 2029 Notes will be at a price equal to 100% of the principal amount, plus accrued and unpaid interest.

Holders may convert all or any portion of their notes at their option at any time prior to the close of business on the business day immediately preceding March 1, 2027, in the case of the 2027 Notes, and March 1, 2029, in the case of the 2029 Notes, only under the following circumstances:

•During any calendar quarter commencing after the calendar quarter ending on September 30, 2024 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price of such series of notes on each applicable trading day;

•During thefive consecutive business day period immediately after anyten consecutive trading day period (measurement period) in which the trading price per $1,000 principal amount of notes of such series for each trading day of the measurement period was less than 98% of the product of the last reported sale price of our common stock and the conversion rate of such series of notes on each such trading day;

•Upon the occurrence of specified corporate events, as defined in the related indenture;

•In the case of the 2029 Notes only, if we call any of the 2029 Notes for redemption, at any time prior to the close of business on the second scheduled trading day prior to the redemption date, but only with respect to the 2029 Notes called (or deemed called) for redemption.

Holders may convert all or any portion of their notes at any time, regardless of the foregoing circumstances, on or after March 1, 2027, in the case of the 2027 Notes, or March 1, 2029, in the case of the 2029 Notes, until the close of business on the second scheduled trading day immediately preceding the maturity date of such series of notes.

Upon conversion, we will pay cash up to the aggregate principal amount of the notes to be converted and pay or deliver cash, shares of our common stock, or a combination of cash and shares of our common stock, at our election, in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted.

The initial conversion rate for both the 2027 Notes and 2029 Notes is 10.1243 shares of common stock per $1,000 principal amount, which is equivalent to an initial conversion price of approximately $98.77 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events, as defined in the related indenture, but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change, as defined in the related indenture, we will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

As of December 31, 2025, 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 December 31, 2025:

(1)The fair values are categorized in Level 2 of the fair value hierarchy. See Note 1(r), 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 for the year ended December 31:

Wisconsin Electric Power Company

In June 2025, WE's $250.0 million of 3.10% Debentures, due June 1, 2025, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

In September 2025, WE issued $500.0 million of 4.15% Debentures, due October 15, 2030, and used the net proceeds to repay short-term debt and for other general corporate purposes.

In December 2025, WE issued $300.0 million of 3.95% Debentures, due March 1, 2029, and used the net proceeds to repay short-term debt and for other general corporate purposes.

Wisconsin Public Service Corporation

In November 2025, WPS's $300.0 million of 5.35% Senior Notes, due November 10, 2025, matured, and outstanding principal and accrued interest were paid with proceeds received from issuing commercial paper.

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.

Wisconsin Gas LLC

In September 2025, WG issued $175.0 million of 4.70% Debentures, due October 1, 2030, and $125.0 million of 5.39% Debentures, due October 1, 2035, and used the net proceeds to repay $200.0 million of WG's 3.53% Debentures that matured on September 30, 2025, and to repay short-term debt and for other general limited liability company purposes.

Minnesota Energy Resources Corporation

In April 2025, MERC issued $50.0 million of 5.20% Senior Notes, due May 1, 2030, and used the net proceeds to repay MERC's $50.0 million of 2.69% Senior Notes that matured on May 1, 2025.

Michigan Gas Utilities Corporation

In April 2025, MGU issued $75.0 million of 5.20% Senior Notes, due May 1, 2030, and used the net proceeds to repay MGU's $60.0 million of 2.69% Senior Notes that matured on May 1, 2025 and intercompany short-term debt to its parent, Integrys.

Upper Michigan Energy Resources Corporation

In August 2025, UMERC issued $80.0 million of 5.31% Senior Notes, due August 14, 2030, and $40.0 million of 5.93% Senior Notes, due August 14, 2035, and used the net proceeds to repay intercompany short-term debt to its parent, WEC Energy Group, and for other general corporate purposes.

ATC Holding LLC

In December 2025, ATC's $85.0 million of 4.18% Debentures, due December 20, 2025, matured, and outstanding principal and accrued interest were paid with a contribution received from WEC Energy Group.

Maturities of Long-Term Debt Outstanding

The following table shows the long-term debt securities maturing within one year of December 31, 2025:

(1)Maturity dates listed as semi-annually and monthly are associated with debt that requires periodic principal payments.

The following table shows the future maturities of our long-term debt outstanding as of December 31, 2025:

Certain long-term debt obligations contain financial and other covenants related to payment of principal and interest when due, maintaining certain total funded debt to capitalization ratios, and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

NOTE 15—LEASES

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our leases is modified to conform to the rate treatment. The difference between the lease expense that is allowed for rate-making purposes and the unadjusted lease expense calculated under Topic 842 is deferred as a regulatory asset on our balance sheets. For our finance leases, amortization of the right-of-use asset is modified so that the total of the imputed interest and amortization costs equals the lease expense that is allowed for rate-making purposes in accordance with Subtopic 980-842.

Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities primarily associated with the following operating leases:

•Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, through April 2039.

•Land we are leasing related to our Rothschild biomass plant through June 2051.

•Rail cars we are leasing to transport coal to various generating facilities through June 2027.

•Land we are leasing related to our utility and non-utility solar generation projects through May 2075.

The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Certain of our leases contain options for early termination or to renew past the initial term, as set forth in the lease agreements. These options are included in our calculation of the lease obligations if it is reasonably certain that they will be exercised.

Obligations Under Finance Leases

Land Leases – Utility Solar Generation

We have 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 which can range from 40 to 50 years. Once a solar project achieves commercial operation, the lease liability is remeasured to reflect the final total acres being leased. Our payments related to these leases are being recovered through rates.

Land Leases – Non-Utility Energy Infrastructure Solar Generation

We have various land leases related to our investments in non-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 of approximately 50 years.

Amounts Recognized in the Financial Statements and Other Information

The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows: