What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2024-02-22 compared with 2023-02-23 · 724 added, 644 removed, 2140 unchanged (39% of the section changed)

28 unchanged sentences

Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business.

Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates.

Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered through rates.

The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital.

Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by the Company’s regulators.

Future decisions of the Commissions will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates, and any refunds that may be required.

While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve:

(1) full recovery of the costs of providing utility service, (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment or (3) timely recovery of costs incurred.

The Company had $3,306.9 million and $3,791.9 million of regulatory assets and liabilities, respectively, as of December 31, 2022.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the subjectivity involved in assessing the impact of future regulatory orders on the financial statements.

Given that management’s accounting judgments can be based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and/or (2) a refund to customers.

Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following procedures, among others:

• We tested the effectiveness of management’s controls over regulatory assets and liabilities, including management’s controls over the identification of costs recorded as regulatory assets and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates.

Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:

• We tested the effectiveness of management’s controls over regulatory assets and liabilities, including management’s controls over the identification of costs recorded as regulatory assets and liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates.

• We inquired of Company management and independently obtained and read:

(1) relevant regulatory orders issued by the Commissions for the Company and other public utilities in each respective state, (2) company filings, (3) filings made by intervenors and (4) other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

(1) relevant regulatory orders issued by the Commissions for the Company, (2) Company filings with the Commissions, (3) filings made by intervenors and (4) other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

To assess completeness, we evaluated the information obtained and compared it to management’s recorded regulatory asset and liability balances.

• For regulatory matters in process, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

• We obtained management’s analysis regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

• We evaluated management’s analysis regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

• We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

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Other operation and maintenance 2,100.5 1,938.0 2,005.5

Impairment related to ICC disallowances 178.9 — —

Depreciation and amortization 1,264.2 1,122.6 1,074.3

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Derivatives accounted for as cash flow hedges

Net derivative gain (loss), net of tax expense (benefit) of $ — , $ 0.2 , and $( 1.6 ), respectively

— 0.6 ( 4.3 )

Net derivative gain, net of tax — — 0.6

Reclassification of realized net derivative (gain) loss to net income, net of tax ( 0.3 ) ( 0.3 ) 0.9

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Current portion of long-term debt (December 31, 2023 and December 31, 2022 include $ 9.0 and $ 8.9 , respectively, related to WEPCo Environmental Trust)

1,264.2 881.2

Accounts payable 896.6 1,198.1

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Regulatory liabilities 3,697.7 3,735.5

Intangible liabilities 594.8 335.4

Environmental remediation liabilities 463.7 499.6

AROs 374.2 479.3

Pension and OPEB obligations 176.0 171.6

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Deferred income taxes and ITCs, net 219.4 280.1 151.1

Impairment related to ICC disallowances 178.9 — —

Contributions and payments related to pension and OPEB plans ( 16.7 ) ( 15.1 ) ( 66.3 )

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Capital expenditures ( 2,492.9 ) ( 2,314.9 ) ( 2,252.8 )

Acquisition of Whitewater ( 76.0 ) — —

Acquisition of Sapphire Sky, net of cash acquired of $ 0.3

( 442.6 ) — —

Acquisition of Samson I, net of cash acquired of $ 5.2

( 257.3 ) — —

Acquisition of Red Barn ( 143.8 ) — —

Acquisition of West Riverside ( 95.3 ) — —

Acquisition of Thunderhead, net of cash acquired of $ 0.5

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Acquisition of Jayhawk — — ( 119.9 )

Acquisition of Blooming Grove, net of restricted cash acquired of $ 24.1

— — ( 364.6 )

Acquisition of Tatanka Ridge — — ( 239.9 )

Acquisition of intangible assets ( 19.2 ) — —

Capital contributions to transmission affiliates ( 63.7 ) ( 45.5 ) —

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Proceeds from the sale of investments held in rabbi trust 10.4 15.4 18.7

Purchase of investments held in rabbi trust — — ( 37.8 )

Payments for ATC's construction costs that will be reimbursed ( 19.8 ) ( 24.8 ) ( 7.0 )

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Retirement of long-term debt ( 1,005.4 ) ( 92.1 ) ( 1,260.4 )

Issuance of short-term loan 2.7 0.9 340.0

Repayment of short-term loan ( 0.8 ) — ( 340.0 )

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Payments for debt extinguishment and issuance costs ( 14.2 ) ( 15.6 ) ( 67.2 )

Purchase of additional ownership interest in Upstream from noncontrolling interest — — ( 31.0 )

Other, net ( 6.0 ) ( 9.1 ) ( 9.2 )

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Net income attributed to common shareholders — — 1,300.3 — 1,300.3 — — 1,300.3

Net income attributed to noncontrolling interests — — — — — — 0.3 0.3

Other comprehensive loss — — — ( 2.7 ) ( 2.7 ) — — ( 2.7 )

Net loss attributed to noncontrolling interests — — — — — — ( 3.0 ) ( 3.0 )

Other comprehensive income — — — 3.6 3.6 — — 3.6

Common stock dividends of $ 2.71 per share

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Purchase of common stock — ( 33.1 ) — — ( 33.1 ) — — ( 33.1 )

Purchase of additional ownership interest in Upstream from noncontrolling interest — — — — — — ( 31.0 ) ( 31.0 )

Acquisition of noncontrolling interests — — — — — — 6.3 6.3

Capital contributions from noncontrolling interest — — — — — — 7.6 7.6

Distributions to noncontrolling interests — — — — — — ( 4.1 ) ( 4.1 )

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Net income attributed to common shareholders — — 1,408.1 — 1,408.1 — — 1,408.1

Net loss attributed to noncontrolling interests — — — — — — ( 3.0 ) ( 3.0 )

Other comprehensive income — — — 3.6 3.6 — — 3.6

Net income attributed to noncontrolling interests — — — — — — 0.4 0.4

Other comprehensive loss — — — ( 3.6 ) ( 3.6 ) — — ( 3.6 )

Common stock dividends of $ 2.91 per share

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Net income attributed to common shareholders — — 1,331.7 — 1,331.7 — — 1,331.7

Net income attributed to noncontrolling interests — — — — — — 0.4 0.4

Net loss attributed to noncontrolling interests — — — — — — ( 1.2 ) ( 1.2 )

Other comprehensive loss — — — ( 0.9 ) ( 0.9 ) — — ( 0.9 )

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Acquisition of noncontrolling interests — — — — — — 114.9 114.9

Capital contributions from noncontrolling interest — — — — — — 1.1 1.1

Distributions to noncontrolling interests — — — — — — ( 6.0 ) ( 6.0 )

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NOTE 1— SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of Operations — WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, owns approximately 60 % of ATC, and owns majority interests in multiple wind generating facilities as part of its non-utility energy infrastructure segment.

(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.

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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, 2022 related to the minority interests held by third parties in the wind generating facilities that are included in our non-utility energy infrastructure segment.

The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2023 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:

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• 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 ownership interests in several wind generating facilities, is also included in this segment.

See Note 2, Acquisitions, for more information on the 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, WBS, and also included the operations of PDL prior to the sale of its remaining solar facilities in the fourth quarter of 2020.

See Note 3, Dispositions, for more information on the sale of these solar facilities.

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.

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The deferred balance is returned to or recovered from customers at intervals throughout the year.

However, as a result of the extreme weather in the Midwest in February 2021, the cost of gas purchased for our natural gas customers was temporarily driven significantly higher than our normal winter weather expectations.

See Note 26, Regulatory Environment, for more information on the recovery of these high natural gas costs.

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The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs.

Finally, PGL's rates include a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs, and similarly, the rates of MERC and MGU include riders to recover costs incurred to replace or modify natural gas facilities.

Finally, through the end of 2023, PGL's rates included a rider for pass through of income tax expense changes resulting from the Tax Legislation and a cost recovery mechanism for SMP costs.

Similarly, 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.

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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.

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Other Non-Utility Operating Revenues

Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow in 2022.

Wind and solar generation revenues from WECI's ownership interests in renewable generation facilities continued to grow in 2023.

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

Most of these wind 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.

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.

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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 wind facility to produce electricity when needed by the customer.

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.

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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 wind generation and servicing revenues generally occur on a monthly basis, with payments typically due in full within 30 days.

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.

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These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

See Note 26, Regulatory Environment, for more information.

• PGL and NSG were authorized to implement a SPC rider for the recovery of incremental direct costs resulting from the COVID-19 pandemic, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs.

See Note 26, Regulatory Environment, for more information.

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

• 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

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cost of service was for the year.

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.

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(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.

Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326):

Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method.

This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables.

The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss.

The cumulative effect of adopting this standard was not significant to our financial statements.

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 wind generating facilities through agreements with several large high credit quality counterparties.

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.

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We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk.

(f) Materials, Supplies, and Inventories — Our inventory as of December 31 consisted of:

(f) Materials, Supplies, and Inventories — Our inventories as of December 31 consisted of:

(in millions) 2023 2022

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

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(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.

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Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.

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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.

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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.

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AFUDC-Debt is recorded as a reduction of interest expense, and AFUDC-Equity is recorded in other income, net.

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The majority of AFUDC is recorded at WE, WPS, WG, UMERC, and WBS.

8 unchanged sentences

WBS 7.46 % N/A

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

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(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, developing a centralized repository for data to improve analytics and reporting, targeted enterprise resource planning systems, a project management tool, and a power generation employee scheduling system.

These projects include, among other things, a centralized repository for data to improve analytics, reporting and asset management, targeted enterprise resource planning systems, human resources management, employee scheduling, geospatial information, 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.

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Interim impairment tests are performed when impairment indicators are present.

During the third quarter of each year, we perform an annual impairment test at all of our reporting units that carry a goodwill balance.

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 the fair value of the asset.

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 assets over its fair value.

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No impairment losses were recorded for our indefinite-lived intangible assets during the years ended December 31, 2023, 2022, and 2021.

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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 the fair value of the asset.

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 the fair value of the asset.

An impairment loss is measured as the excess of the carrying amount of the asset over its fair value.

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

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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.

In the fourth quarter of 2023, we recorded a non-cash impairment loss of $ 178.9 million related to the 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.

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.

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See Note 9, Asset Retirement Obligations, for more information.

(m) Intangible Liabilities — Our finite-lived intangible liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which were all obtained through the acquisitions of wind generation facilities by WECI in our non-utility energy infrastructure segment.

Intangible liabilities are amortized on a straight-line basis over their estimated useful life.

Amortization of revenue contracts is recorded within operating revenues in the income statements.

Amortization related to the interconnection agreements is recorded within other operation and maintenance in the income statements.

(m) Intangible Liabilities — Our finite-lived intangible 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 liabilities are amortized on a straight-line basis over their estimated useful lives, which is the term of the agreements.

Amortization of the revenue contract intangible liabilities is 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.

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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, 9.0 million shares are reserved for issuance under the plan.

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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.

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We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

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Stock Options

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Pursuant to the plan terms governing these awards, these percentages can be adjusted upwards or downwards by up to 10 % based on our performance against additional performance measures, if any, adopted by the Compensation Committee.

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The WEC Energy Group Performance Unit Plan was amended and restated, effective January 1, 2023.

In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023.

In accordance with the amended plan, the Compensation Committee selected multiple performance measures that will be weighted to determine the ultimate payout for the awards granted in 2023 and 2024.

The ultimate number of units awarded 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 addition, the Compensation

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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.

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(o) Earnings Per Share — We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period.

Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities.

Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities, as calculated using the treasury stock method.

Such dilutive securities include in-the-money stock options.

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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 associated with regulated operations are deferred and amortized over the life of the assets.

ITCs are deferred and amortized over the life of the assets.

PTCs are recognized in the period in which such credits are generated.

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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.

See Note 16, Income Taxes, for more information.

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 produced after December 31, 2022, to third parties.

In September 2023, under this transferability provision, we entered into an agreement to sell substantially all of our 2023 PTCs to a third party.

We elect to account for 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 will also include any expected proceeds from the sale of tax credits in the evaluation of the realizability of deferred tax assets related to PTCs.

The sale of tax credits is presented in the operating activities section of the statements of cash flows consistent with the presentation of cash taxes paid.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes.

We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

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).

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Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value.

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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.

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Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1.

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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.

On our balance sheets, cash collateral provided to others is reflected in other current assets.

See Note 18, Derivative Instruments, for more information.

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(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.

These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as

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Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP.

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During the year, the monthly installment amount is reviewed by comparing it to actual usage.

If necessary,

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an adjustment is made to the monthly amount.

If necessary, an adjustment is made to the monthly amount.

Annually, the budget plan is reconciled to actual annual usage.

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(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 coal combustion residual landfills and manufactured gas plant sites.

See Note 9, Asset Retirement Obligations, for more information regarding coal combustion residual landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

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.

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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 coal combustion residual landfills.

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.

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In accordance with Topic 805:

Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions (or disposals) of assets or businesses, and transaction costs are capitalized in asset acquisitions.

It was determined that all of the below acquisitions met the criteria of an asset acquisition.

The purchase price of certain acquisitions described below includes intangibles recorded as long-term liabilities related to PPAs.

Clarifying the Definition of a Business (ASU 2017-01), transactions are evaluated and are accounted for as acquisitions of assets or businesses, and transaction costs are capitalized in asset acquisitions.

It was determined that all of the below acquisitions met the criteria of asset acquisitions.

The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs.

See Note 10, Goodwill and Intangibles, for more information.

Acquisition of Wind Generation Facilities in Illinois

In February 2023, WECI completed the acquisition of a 90 % ownership interest in Sapphire Sky, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of approximately $ 442.9 million, which includes transaction costs.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years.

Sapphire Sky qualifies for PTCs and is included in the non-utility energy infrastructure segment.

In October 2022, WECI signed an agreement to acquire an 80 % ownership interest in Maple Flats, a 250 MW solar generating facility under construction in Clay County, Illinois, for approximately $ 360 million.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years.

The transaction is subject to FERC approval and commercial operation is expected to begin during the first half of 2024, at which time the transaction is expected to close.

Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

In December 2020, WECI completed the acquisition of a 90 % ownership interest in Blooming Grove, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of $ 364.6 million, which includes transaction costs and is net of restricted cash acquired of $ 24.1 million.

Blooming Grove has offtake agreements for all the energy produced with affiliates of two investment grade multinational companies for 12 years.

Blooming Grove qualifies for PTCs and is included in the non-utility energy infrastructure segment.

Acquisitions of Electric Generation Facilities in Wisconsin

In June 2023, WE completed the acquisition of 100 MWs of West Riverside's nameplate capacity, in the first of two potential option exercises.

West Riverside is a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin.

Prior to acquisition, WPS received approval to transfer its ownership interest rights to WE.

WE's investment was $ 95.3 million.

In addition, WPS filed a request with the PSCW in September 2023 to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity.

As it did with the first option, in October 2023, WPS filed for approval to assign its ownership interest pursuant to this second option to WE.

If these approvals are obtained, WE's incremental share of this investment is expected to be approximately $ 100 million, with the transaction expected to close in 2024.

2023 Form 10-K 103

WEC Energy Group, Inc.

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

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

The project is located in Grant County, Wisconsin and WPS owns 82 MWs of this project.

WPS's share of the cost of this project was $ 143.8 million.

Red Barn qualifies for PTCs.

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

Acquisition of a Solar Generation Facility in Texas

In February 2023, WECI completed the acquisition of an 80 % ownership interest in Samson I, a commercially operational 250 MW solar generating facility in Lamar County, Texas, for $ 257.3 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 15 years from the date of commercial operation.

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.

(in millions)

Accounts receivable $ 0.5

Other current assets 0.7

Net property, plant, and equipment 497.2

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Total purchase price $ 257.3

Acquisition of a Solar Generation Facility in Texas

In January 2023, WECI signed an agreement to acquire an 80 % ownership interest in Samson I, a 250 MW solar generating facility in Lamar County, Texas, for approximately $ 250 million.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 15 years.

Commercial operation was achieved in May 2022.

Samson I is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

Acquisition of Electric Generation Facilities in Wisconsin

Effective January 1, 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 electrical generation facility in Whitewater, Wisconsin, for $ 72.7 million, which excludes working capital and transaction costs.

See Note 15, Leases, for more information.

In January 2022, WPS, along with an unaffiliated utility, received PSCW approval to acquire Red Barn, a utility-scale wind-powered electric generating facility.

The project will be located in Grant County, Wisconsin and once constructed, WPS will own 82 MW of this project.

WPS's share of the cost of this project is estimated to be $ 160 million, with commercial operation expected to begin in the first half of 2023, at which time the transaction is expected to close.

Red Barn is expected to qualify for PTCs.

Acquisitions of Electric Generation Facilities in Illinois

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.

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

(in millions)

Accounts receivable $ 0.8

Net property, plant, and equipment 642.6

Other long-term assets 1.4

Accounts payable ( 1.0 )

Other long-term liabilities ( 152.0 )

Noncontrolling interest ( 49.2 )

Total purchase price $ 442.6

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.

The transaction is subject to FERC approval and commercial operation is expected to begin during the second half of 2024, at which time the transaction is expected to close.

Maple Flats is expected to qualify for PTCs and will be included in the non-utility energy infrastructure segment.

2023 Form 10-K 104

WEC Energy Group, Inc.

Acquisition of a Wind Generation Facility in Nebraska

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Thunderhead achieved commercial operation in November 2022.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 12 years.

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.

Thunderhead qualifies for PTCs and is included in the non-utility energy infrastructure segment.

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Total purchase price $ 382.0

2022 Form 10-K 101

WEC Energy Group, Inc.

Acquisition of a Wind Generation Facility in Kansas

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Subsequent to the acquisition, WECI incurred an additional $ 161.3 million of capital expenditures as of December 31, 2022 for the project for a total investment of $ 281.2 million.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 10 years.

The project has an offtake agreement for all of the energy to be produced by the facility for a period of 10 years from the date of commercial operation.

Jayhawk qualifies for PTCs.

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Total purchase price $ 119.9

Acquisition of a Wind Generation Facility in South Dakota

In December 2020, WECI completed the acquisition of an 85 % ownership interest in Tatanka Ridge, a 155 MW wind generating facility in Deuel County, South Dakota, that became commercially operational in January 2021.

WECI's total investment was $ 239.9 million, which included transaction costs.

Tatanka Ridge has offtake agreements for all the energy produced with an affiliate of an investment grade multinational company for 12 years and a well-established electric cooperative that serves utilities in multiple states for 10 years.

Tatanka Ridge qualifies for PTCs.

WECI is entitled to 99 % of the tax benefits related to this facility for the first 11 years of commercial operation, after which it will be entitled to tax benefits equal to its ownership interest.

Tatanka Ridge is included in the non-utility energy infrastructure segment.

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

(in millions)

Other current assets $ 37.3

Net property, plant, and equipment 301.2

Other current liabilities ( 37.3 )

Other long-term liabilities ( 19.3 )

Noncontrolling interest ( 42.0 )

Total purchase price $ 239.9

NOTE 3— DISPOSITIONS

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.

2023 Form 10-K 105

WEC Energy Group, Inc.

Illinois Segment

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

In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $ 55.1 million.

In May 2022, we sold approximately 11 acres of real estate owned by PGL that was no longer being utilized in its operations, for $ 55.1 million, which is net of closing costs.

The real estate was located in Chicago, Illinois.

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The book value of the real estate included in the sale was not material and, therefore, was not presented as held for sale.

2022 Form 10-K 102

WEC Energy Group, Inc.

Corporate and Other Segment

Sale of Certain WPS Power Development, LLC Solar Power Generation Facilities

In November 2020, we sold a portfolio of residential solar facilities owned by PDL for $ 10.5 million.

These solar facilities were located in California and Hawaii.

During the fourth quarter of 2020, we recorded an after-tax gain on the sale of $ 3.0 million primarily related to the recognition of deferred ITCs, which were included as a reduction of income tax expense on our income statements.

The assets included in the sale were not material and, therefore, were not presented as held for sale.

The results of operations of these facilities remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

NOTE 4— OPERATING REVENUES

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Total natural gas utility operating revenues $ 1,490.3 $ 1,630.3 $ 494.0 $ 3,614.6

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

(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) During 2022, we continued to recover natural gas costs we under-collected from our customers in 2021 related to the extreme weather experienced in February 2021, as well as higher natural gas costs incurred at the majority of our segments during 2022.

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See Note 26, Regulatory Environment, for more information.

Other Natural Gas Operating Revenues

We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment.

has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers.

All amounts associated with the service agreements with WE, WPS, and WG have been eliminated at the consolidated level.

Other Non-Utility Operating Revenues

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(in millions) 2023 2022 2021

Wind generation revenues $ 101.0 $ 60.3 $ 34.6

Renewable generation revenues $ 164.9 $ 101.0 $ 60.3

We Power revenues 23.5 23.4 23.3

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Total other non-utility operating revenues $ 208.1 $ 143.2 $ 101.5

2022 Form 10-K 105

WEC Energy Group, Inc.

Other Operating Revenues

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Late payment charges $ 56.5 $ 55.6 $ 54.9

$ 55.6 $ 54.9 $ 29.4

Alternative revenues (1)

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Total other operating revenues $ 107.7 $ 29.3 $ 80.3

(1) The increase in late payment charges during 2021, compared with 2020, was a result of the expiration of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which included the suspension of late payment charges during a designated time period.

See Note 26, Regulatory Environment, for more information.

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WEC Energy Group, Inc.

(1) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues.

Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges.

Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, and conservation improvement rider true-ups.

NOTE 5— CREDIT LOSSES

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As a result, at December 31, 2023, $ 914.6 million, or 60.8 %, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses.

2022 Form 10-K 106

WEC Energy Group, Inc.

A rollforward of the allowance for credit losses by reportable segment for the years ended December 31, 2023, 2022, and 2021, is included below:

(in millions)

Wisconsin Illinois Other States Total Utility

Operations Corporate

and Other WEC Energy Group Consolidated

Wisconsin Illinois Other States WEC Energy Group Consolidated

Balance at January 1, 2023 $ 82.0 $ 111.0 $ 6.3 $ 199.3

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Balance at December 31, 2023 $ 77.4 $ 109.7 $ 6.4 $ 193.5

On a consolidated basis, there was a $ 1.0 million increase in the allowance for credit losses during the year ended December 31, 2022.

We believe that the high energy costs that customers are seeing, which have been driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.

The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers.

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

2023 Form 10-K 109

WEC Energy Group, Inc.

the allowance for credit losses.

After a customer is disconnected for a period of time without payment on their account, we will write off that customer balance.

(in millions)

Wisconsin Illinois Other States Total Utility

Operations Corporate

and Other WEC Energy Group Consolidated

Wisconsin Illinois Other States WEC Energy Group Consolidated

Balance at January 1, 2022 $ 84.0 $ 105.5 $ 8.8 $ 198.3

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Balance at December 31, 2022 $ 82.0 $ 111.0 $ 6.3 $ 199.3

The allowance for credit losses decreased during the year ended December 31, 2021, primarily related to normal collection practices resuming in April 2021 for our Wisconsin utilities and in June 2021 for our Illinois utilities.

Across all of our reportable segments, higher year-over-year natural gas prices drove an increase in gross accounts receivable balances, partially offsetting the decrease in the allowance for credit losses attributed to collection efforts.

On a consolidated basis, there was a $ 1.0 million increase in the allowance for credit losses during the year ended December 31, 2022.

We believe that the high energy costs that customers were seeing, which were driven by high natural gas prices, contributed to higher past due accounts receivable balances and a related increase in the allowance for credit losses.

The increase was substantially offset by customer write-offs related to collection practices returning to pre-pandemic levels, including the restoration of our ability to disconnect customers.

(in millions)

Wisconsin Illinois Other States Total Utility

Operations Corporate

and Other WEC Energy Group Consolidated

Wisconsin Illinois Other States WEC Energy Group Consolidated

Balance at January 1, 2021 $ 102.1 $ 111.6 $ 6.4 $ 220.1

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Recoveries of amounts previously written off 26.9 17.3 1.2 45.4

Sale of PDL residential solar facilities — — — — ( 0.1 ) ( 0.1 )

Balance at December 31, 2021 $ 84.0 $ 105.5 $ 8.8 $ 198.3

The allowance for credit losses increased during the year ended December 31, 2020, driven by higher past due accounts receivable balances at our utility segments, primarily related to residential customers.

This increase in accounts receivable balances in arrears was driven by economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates.

Also, as a result of the COVID-19 pandemic and related regulatory orders we received, we were unable to disconnect any of our Wisconsin and Illinois customers during the year ended December 31, 2020.

2023 Form 10-K 110

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Derivatives 130.3 133.8 1(s)

Securitization 92.4 100.7 23

Uncollectible expense 127.7 69.3 5

MERC extraordinary natural gas costs (6)

Securitization 85.9 92.4 23

Bluewater (6)

Energy efficiency programs (7)

Energy costs recoverable through rate adjustments 3.2 26.9 1(d)

MERC extraordinary natural gas costs (8)

Other, net 147.8 125.9

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This allowance was $ 26.7 million and $ 27.3 million at December 31, 2023 and 2022, respectively.

(2) As of December 31, 2022, we had $ 237.9 million of regulatory assets not earning a return, $ 35.3 million of regulatory assets earning a return based on short-term interest rates, and $ 123.5 million of regulatory assets earning a return based on long-term interest rates.

The regulatory assets not earning a return primarily relate to certain environmental remediation costs, uncollectible expense, MERC's extraordinary natural gas costs, our invested capital tax rider, and unamortized loss on reacquired debt.

(2) As of December 31, 2023, we had $ 254.6 million of regulatory assets not earning a return, $ 5.4 million of regulatory assets earning a return based on short-term interest rates, $ 129.7 million of regulatory assets earning a return based on long-term interest rates, and $ 2.5 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, uncollectible expense, our invested capital tax rider, decoupling mechanisms, unamortized loss on reacquired debt, and rate case costs.

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.

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(5) 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 an 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.

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.

(6) Represents the extraordinary natural gas costs MERC incurred during February 2021 that are being recovered over 27 months, beginning in September 2021.

See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

(6) 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.

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

(8) Represents the extraordinary natural gas costs MERC incurred during February 2021 that were substantially recovered over 27 months, beginning in September 2021.

See Note 26, Regulatory Environment, for more information on our recovery efforts associated with these costs.

2023 Form 10-K 111

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299.2 340.5 20, 26

Derivatives 76.7 124.1 1(s)

Energy costs refundable through rate adjustments 72.4 53.4 1(d)

Uncollectible expense 24.0 37.1 5

Earnings sharing mechanisms 12.9 28.4 26

Electric transmission costs (3)

Uncollectible expense 21.2 24.0 5

Derivatives 19.2 76.7 1(s)

Energy efficiency programs (4)

Decoupling — 20.2 1(d)

Other, net 54.0 48.8

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(3) 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.

During 2022, WE and WPS amortized $ 81.0 million of their transmission regulatory liabilities to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases.

See Note 26, Regulatory Environment, for more information.

(4) Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards.

Pleasant Prairie Power Plant

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The net book value of the PIPP was $ 152.9 million at December 31, 2023, representing book value less cost of removal and accumulated depreciation.

In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $ 5.2 million as of December 31, 2022.

The net amount of $ 158.5 million was classified as a regulatory asset on

In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance

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our balance sheet at December 31, 2022 as a result of the retirement of the plant.

of these units were $ 4.8 million as of December 31, 2023.

The net amount of $ 148.1 million was classified as a regulatory asset on our balance sheet at December 31, 2023 as a result of the retirement of the plant.

This regulatory asset does not include certain other previously recorded deferred tax liabilities of $ 41.5 million related to the retired PIPP.

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Severance Liability for Plant Retirements

We have severance liabilities related to past and future plant retirements recorded in other current liabilities on our balance sheets.

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:

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Severance payments — — ( 0.4 )

Other — — ( 1.3 )

Total severance liability at December 31 $ 17.8 $ 16.2 $ 4.9

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Oak Creek Power Plant Units 5-8

As a result of a PSCW approval for the construction of a solar and battery project received in December 2022, retirement of the OCPP generating units 5 – 8 became probable.

OCPP units 5 and 6 are expected to be retired by May 2024, while units 7 and 8 are expected to be retired by late 2025.

The total net book value of WE's ownership share of units 5 – 8 was $ 812.5 million at December 31, 2022, which does not include deferred taxes.

These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheet.

As a result of a PSCW approval in December 2022 for the acquisition and construction of Darien, the retirement of OCPP Units 5-8 became probable.

In early 2023, we received additional approvals for electric generation facilities, including Koshkonong and 100 MWs of West Riverside.

See Note 2, Acquisitions, for more information on the West Riverside acquisition, which was completed in June 2023.

OCPP Units 5 and 6 are expected to be retired by May 2024, while OCPP Units 7 and 8 are expected to be retired by late 2025.

The total net book value of WE's ownership share of OCPP Units 5-8 was $ 783.7 million at December 31, 2023, which does not include deferred taxes.

This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet.

These units are included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

Columbia Units 1 and 2

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia generating units 1 and 2 became probable.

Columbia generating units 1 and 2 are expected to be retired by June 2026.

The net book value of WPS's ownership share of unit 1 and unit 2 was $ 84.0 million and $ 189.1 million, respectively, at December 31, 2022, which does not include deferred taxes.

As a result of a MISO ruling received in June 2021, retirement of the jointly-owned Columbia Units 1 and 2 became probable.

Columbia Units 1 and 2 are expected to be retired by June 2026.

The total net book value of WPS's ownership share of Columbia

2023 Form 10-K 114

WEC Energy Group, Inc.

These amounts were classified as plant to be retired within property, plant, and equipment on our balance sheet.

Units 1 and 2 was $ 259.8 million at December 31, 2023, which does not include deferred taxes.

This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet.

These units are included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW.

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

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 of our property, plant, and equipment in 2023.

We anticipate appealing the ICC’s disallowance of these capital costs to the Illinois circuit court.

See Note 26, Regulatory Environment, for more information.

Samson I Solar Energy Center LLC – Storm Damage

During wind storms in March and June 2023, certain sections of our Samson I solar facility incurred damage.

As of December 31, 2023, we recognized an impairment of $ 2.3 million related to storm damage, which was offset by a $ 2.3 million receivable for future insurance recoveries.

Although we may experience differences between periods in the timing of cash flows, we do not currently expect a significant impact to our long-term cash flows from this event.

Public Service Building and Steam Tunnel Assets

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As of December 31, 2023, WE had incurred $ 95.3 million of costs related to these repairs and restorations.

In 2020, WE received $ 20.0 million of insurance proceeds to cover a portion of these costs and wrote off $ 12.5 million of costs that we do not intend to seek recovery for through other operation and maintenance expense.

In the first quarter of 2022, WE received $ 41.0 million of insurance proceeds as a result of a settlement that was reached in February 2022.

The remaining $ 21.8 million of costs is expected to be recovered through rates.

In June 2021, we received approval from the PSCW to restore the PSB and adjacent steam tunnel assets and to defer the project costs, net of insurance proceeds, as a component of rate base.

As such, and in light of the agreement with insurers noted above, we do not currently expect a significant impact to our future results of operations.

As a result, we do not currently expect a significant impact to our future results of operations.

NOTE 8— JOINTLY OWNED UTILITY FACILITIES

We Power and WPS hold joint ownership interests in certain electric generating facilities.

They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest.

They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects.

We record We Power's and WPS's proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets.

We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units.

WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs.

WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.

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 at December 31, 2023 was as follows:

(in millions, except for percentages and MW) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1

Forward Wind Two Creeks Badger

Ownership 83.34 % 70.0 % 27.5 % 44.6 % 66.7 % 66.7 %

Share of capacity (MW) (1)

Company Jointly-Owned Utility Facilities Ownership Share of Capacity (MW)

In-Service /Acquisition Date

Operating Owner Property, Plant, and Equipment Accumulated Depreciation CWIP

(in millions, except for percentages and MW)

ER 1 & ER 2 (2)

83.34 % 1,082.1 2010 & 2011 WE $ 2,487.4 $ ( 520.0 ) $ 6.2

WPS Weston Unit 4 (2)

70.0 % 384.8 2008 WPS 613.3 ( 227.3 ) 0.5

WPS Columbia Energy Center Units 1 and 2 (2) (5)

27.5 % 312.3 1975 & 1978 WPL 433.1 ( 173.8 ) 3.5

WPS Forward Wind (3)

44.6 % 61.5 2008 WPS 119.3 ( 56.8 ) —

WPS Two Creeks (4)

66.7 % 100.0 2020 WPS 136.9 ( 14.1 ) —

WPS Badger Hollow I (4)

66.7 % 100.0 2021 WPS 146.2 ( 9.7 ) 0.1

WPS Red Barn (3)

90.0 % 82.4 2023 WPS 150.0 ( 3.2 ) —

WE West Riverside (2) (6)

13.8 % 84.9 2023

In-service date 2010 and 2011 2008 1975 and 1978 2008 2020 2021

Property, plant, and equipment $ 2,425.1 $ 612.1 $ 426.1 $ 119.3 $ 136.8 $ 146.2

Accumulated depreciation $ ( 505.7 ) $ ( 213.0 ) $ ( 159.7 ) $ ( 53.9 ) $ ( 9.7 ) $ ( 4.9 )

CWIP $ 64.1 $ 1.2 $ 6.8 $ 0.2 $ 0.1 $ —

(1) Capacity for our jointly-owned electric generation facilities, other than Forward Wind, Two Creeks, and Badger Hollow I, 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.

WE 108.7 ( 11.3 ) 0.9

WE Badger Hollow II (4)

66.7 % 100.0 2023 WE 170.1 ( 0.3 ) 0.1

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

2023 Form 10-K 115

WEC Energy Group, Inc.

(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 2024 established by tests and may change slightly from year to year.

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This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

Capacity for Forward Wind is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds.

Capacity for Two Creeks and Badger Hollow I is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.

(2) Commercial operation was achieved in November 2021 for Badger Hollow I.

WE, along with an unaffiliated utility, received PSCW approval to construct Badger Hollow II, a solar project that will be located in Iowa County, Wisconsin.

Once constructed, WE will own 66.7 %, or 100 MW, of Badger Hollow II.

Commercial operation is targeted for 2023.

The CWIP balance for Badger Hollow II was $ 107.5 million as of December 31, 2022.

2022 Form 10-K 112

WEC Energy Group, Inc.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system.

The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 90 %, or 180 MW of solar generation and 99 MW of battery storage, of this project.

(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) These units are expected to be retired by June 2026.

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

(6 WE acquired its ownership interest in June 2023.

In September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of West Riverside's nameplate capacity.

WPS subsequently filed for approval to assign its ownership interest pursuant to this second option to WE.

See Note 2, Acquisitions, for more information.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Koshkonong, a utility-scale solar-powered electric generating facility.

The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will c ollectively own 90 %, or 270 MWs of solar generation of this project.

Commercial operation of the solar facility is targeted for 2026.

The CWIP balance for Paris was $ 207.6 million as of December 31, 2022.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility with a battery energy storage system.

The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 90 %, or 225 MW of solar generation and 68 MW of battery storage of this project.

Our CWIP balance for Koshkonong was not significant as of December 31, 2023.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Paris, a utility-scale solar-powered electric generating facility with a battery energy storage system.

The project will be located in Kenosha County, Wisconsin and once fully constructed, WE and WPS will collectively own 90 %, or 180 MWs of solar generation and 99 MWs of battery storage of this project.

Commercial operation of the solar facility is targeted for 2024 and construction of the battery storage is expected to be completed in 2025.

Our CWIP balance for Paris was $ 334.3 million as of December 31, 2023.

WE and WPS, along with an unaffiliated utility, received PSCW approval to construct Darien, a utility-scale solar-powered electric generating facility.

The project will be located in Rock and Walworth counties, Wisconsin and once constructed, WE and WPS will collectively own 90 %, or 225 MWs of solar generation of this project.

Commercial operation of the solar facility is targeted for 2024.

The CWIP balance for Darien was $ 9.4 million as of December 31, 2022.

Our CWIP balance for Darien was $ 220.4 million as of December 31, 2023.

NOTE 9— ASSET RETIREMENT OBLIGATIONS

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the removal and dismantlement of a biomass generation facility;

the dismantling of wind generation projects;

the dismantling of solar generation projects;

the dismantling of wind and solar generation projects;

the disposal of PCB-contaminated transformers;

the closure of coal combustion residual landfills at certain generation facilities;

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 wind generation projects.

On our balance sheets, AROs are recorded within other long-term liabilities.

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:

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Accretion 17.2 16.1 21.2

Additions and revisions to estimated cash flows 15.0 (1)

Additions 24.0 (1)

Revisions to estimated cash flows ( 133.5 ) (2)

2.2 ( 84.9 ) (5)

Liabilities settled ( 12.8 ) ( 13.8 ) ( 18.8 )

Balance as of December 31 $ 374.2 $ 479.3 $ 462.0

(1) AROs increased $ 12.1 million in 2022, as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project.

Also in 2022, AROs increased $ 1.9 million due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution mains and service pipes at PGL and NSG.

(2) AROs decreased $ 152.0 million in 2021, due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG.

Also in 2021, AROs increased $ 50.7 million due to new natural gas distribution lines being placed into service at PGL and NSG.

AROs increased by $ 26.3 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility wind generation projects.

AROs increased $ 7.8 million due to revisions made to removal estimates for wind generation projects at WE and WPS.

AROs increased $ 6.8 million due to revisions made to the removal estimates for fly ash landfills and ash ponds at WPS.

(3) AROs increased $ 39.3 million in 2020, primarily due to new natural gas distribution lines being placed into service at PGL.

Also in 2020, AROs increased by $ 8.5 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Two Creeks solar generation project.

AROs decreased $ 9.2 million due to revisions made to estimated cash flows for the abatement of asbestos at WE.

(1) AROs increased primarily as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Red Barn wind-powered generation project, the Badger Hollow II solar generation project, and the Sapphire Sky and Samson I non-utility renewable generation projects.

2023 Form 10-K 116

WEC Energy Group, Inc.

(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.

(3) AROs increased primarily as a result of an ARO being recorded for the legal requirement to dismantle, at retirement, the Thunderhead non-utility wind generation project.

(4) AROs increased as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Badger Hollow I solar generation project and the Tatanka Ridge and Jayhawk non-utility renewable generation projects.

(5) AROs decreased due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution lines at PGL and NSG.

Partially offsetting this decrease were revisions made to removal estimates for wind generation projects at WE and WPS and for fly ash landfills and ash ponds at WPS.

NOTE 10— GOODWILL AND INTANGIBLES

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Intangible Assets

At December 31, 2022 and 2021, we had $ 24.9 million and $ 5.7 million, respectively, of indefinite-lived intangible assets.

At December 31, 2023 and 2022, we had $ 29.3 million and $ 24.9 million, respectively, of indefinite-lived intangible assets, largely consisting of spectrum frequencies.

During 2023, we purchased additional spectrum frequencies for $ 4.4 million.

The spectrum frequencies enable the utilities to transmit data and voice communications over a wavelength dedicated to us throughout our service territories.

We also have $ 5.7 million of other indefinite-lived intangible assets, primarily related to a MGU trade name from a previous acquisition.

We also have $ 5.2 million of other indefinite-lived intangible assets, consisting of a MGU trade name from a previous acquisition.

These indefinite-lived intangible assets are included in other long-term assets on our balance sheets.

Intangible Liabilities

The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets.

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

December 31, 2023 December 31, 2022

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Total intangible liabilities $ 665.8 $ ( 71.0 ) $ 594.8 $ 355.8 $ ( 20.4 ) $ 335.4

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, and Thunderhead expiring between 2030 and 2034.

(1) Represents PPAs related to the acquisition of Blooming Grove, Tatanka Ridge, Jayhawk, Thunderhead, Samson I, and Sapphire Sky expiring between 2030 and 2037.

The weighted-average remaining useful life of the PPAs is 11 years.

See Note 2, Acquisitions, for more information on the acquisitions of Samson I and Sapphire Sky in 2023.

(2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029.

The remaining useful life of the proxy revenue swap is six years .

The remaining useful life of the proxy revenue swap is five years .

2023 Form 10-K 117

WEC Energy Group, Inc.

(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively.

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Amortization to be recorded as a decrease to other operation and maintenance 0.2 0.2 0.2 0.2 0.2

2022 Form 10-K 114

WEC Energy Group, Inc.

NOTE 11— COMMON EQUITY

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Related tax benefit $ 2.7 $ 9.6 $ 4.3

(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 2023, 2022, and 2021 were not significant.

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Forfeited ( 17,053 ) 93.34

Expired ( 5,172 ) 91.49

Outstanding as of December 31, 2023 3,015,751 79.57 5.7 $ 28.7

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The intrinsic value of options exercised during the years ended December 31, 2023, 2022, and 2021 was $ 5.2 million, $ 29.2 million, and $ 12.9 million, respectively.

The actual tax benefit from option exercises for the same periods was approximately $ 8.0 million, $ 3.5 million, and $ 12.9 million, respectively.

The actual tax benefit from option exercises for the same years was approximately $ 1.4 million, $ 8.0 million, and $ 3.5 million, respectively.

As of December 31, 2023, approximately $ 1.7 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.5 years on a weighted-average basis.

2023 Form 10-K 118

WEC Energy Group, Inc.

During the first quarter of 2024, the Compensation Committee awarded 283,869 non-qualified stock options with a weighted-average exercise price of $ 85.05 and a weighted-average grant date fair value of $ 16.20 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

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Outstanding and unvested as of December 31, 2023 100,398 93.95

2022 Form 10-K 115

WEC Energy Group, Inc.

The intrinsic value of restricted stock released was $ 5.8 million, $ 7.5 million, and $ 6.5 million for the years ended December 31, 2023, 2022, and 2021, respectively.

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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 %.

2023 Form 10-K 119

WEC Energy Group, Inc.

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.

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Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater for the 12 -month period prior to the distribution.

2022 Form 10-K 116

WEC Energy Group, Inc.

WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period.

During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock.

WEC Energy Group has the option to defer interest payments on its 2007 Junior Notes, from time to time, for one 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.

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Share Purchases

We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

As a result, no new shares of common stock were issued in 2022, 2021, or 2020.

During the years ended December 31, 2023, 2022, and 2021, we instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan.

As a result, no new shares of common stock were issued during these years.

As of January 1, 2024, we began issuing new shares of common stock to fulfill our obligations under these plans.

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

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October 19, 2023 December 1, 2023 $ 0.78 Fourth quarter

2023 Form 10-K 120

WEC Energy Group, Inc.

On January 18, 2024, our Board of Directors declared a quarterly cash dividend of $ 0.835 per share, which equates to an annual dividend of $ 3.34 per share.

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In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65 - 70 % of earnings.

2022 Form 10-K 117

WEC Energy Group, Inc.

NOTE 12— PREFERRED STOCK

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Amount outstanding at December 31 (1)

(1) Coyote Ridge, Tatanka Ridge, and Jayhawk entered into operating expense loans.

(1) Coyote Ridge, Tatanka Ridge, and Jayhawk have entered into operating expense loans.

In accordance with their limited liability company operating agreements, they r eceived 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 2023, was $ 1,196.8 million with a weighted-average interest rate during the period of 5.29 %.

In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $ 340.0 million 364 -day term loan.

In March 2021, we repaid the term loan using the net proceeds from the issuance of our $ 600.0 million aggregate principal amount of 0.80 % Senior Notes due March 15, 2024.

WEC Energy Group, WE, WPS, WG, and PGL 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.

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(in millions) Maturity 2023

Revolving credit facility (WEC Energy Group) September 2026 $ 1,500.0

Revolving credit facility (WE) September 2026 500.0

Revolving credit facility (WPS) September 2026 400.0

Revolving credit facility (WG) September 2026 350.0

Revolving credit facility (PGL) September 2026 350.0

Revolving credit facility (WEC Energy Group) (1)

September 2026 $ 1,500.0

Revolving credit facility (WEC Energy Group) October 2024 200.0

Revolving credit facility (WE) (1)

September 2026 500.0

Revolving credit facility (WPS) (1)

September 2026 400.0

Revolving credit facility (WG) (1)

September 2026 350.0

Revolving credit facility (PGL) (1)

September 2026 350.0

Total short-term credit capacity $ 3,300.0

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Available capacity under existing facilities $ 1,280.5

Each of the revolving credit facilities has a renewal provision for two extensions, subject to lender approval.

(1) These revolving credit facilities have a renewal provision for two extensions, subject to lender approval.

Each extension is for a period of one year .

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Integrys Junior Notes (unsecured) 2073 — % — 6.00 % 221.4

2073 6.00 % 221.4 6.00 % 221.4

PGL First and Refunding Mortgage Bonds (secured) (3)

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The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities.

(2) Variable interest rate reset quarterly.

The terms of the RCC have been previously satisfied.

(2) Variable interest rates reset quarterly.

The rates were 7.75 % and 6.72 % as of December 31, 2023 and 2022, respectively.

Until their expiration on November 15, 2021, we had two interest rate swaps with a combined notional value of $ 250.0 million.

The swaps provided a fixed interest rate of 4.9765 % on $ 250.0 million of the outstanding notes.

See Note 18, Derivative Instruments, for more information on the two interest rate swaps.

(3) The terms of Integrys's 2013 6.00 % Junior Notes, due August 1, 2073, provide that, effective August 2023, they will bear interest at a variable rate, which we expect to based off of SOFR, and will reset quarterly.

(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.

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Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

2022 Form 10-K 120

WEC Energy Group, Inc.

(5) The long-term debt of Bluewater, WECI Wind Holding I, WECI Wind Holding II, 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.

2023 Form 10-K 123

WEC Energy Group, Inc.

(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.

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

In March 2022, President Biden signed into law the Adjustable Interest Rate (LIBOR) Act.

This Act established a uniform process, on a nationwide basis, for replacing LIBOR in certain contracts that did not provide a clearly defined or practicable replacement benchmark rate.

Under the LIBOR Act, the Federal Reserve Board was required to determine an appropriate benchmark replacement based on SOFR, with applicable credit spread adjustments.

In December 2022, the Federal Reserve Board adopted the final rule to implement the LIBOR Act and established the SOFR-based benchmark replacements.

No contract modifications were required for qualifying contracts under the LIBOR Act as the benchmark replacement automatically overrode the existing contract language and became the applicable benchmark after June 30, 2023.

For our $ 500 million of 2007 Junior Notes, starting August 15, 2023, the benchmark replacement rate is the applicable tenor of three-month CME Term SOFR, as administered by the CME Group Benchmark Administration, and includes a credit spread adjustment of 0.26161 % per annum.

In accordance with the LIBOR Act, no contract modifications were required for our 2007 Junior Notes as the references to LIBOR were replaced by operation of law.

WEC Energy Group, Inc.

In September 2022, we issued $ 500.0 million of 5.00 % Senior Notes due September 27, 2025, and $ 400.0 million of 5.15 % Senior Notes due October 1, 2027, and used the net proceeds to repay short-term debt and for other corporate purposes.

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

Wisconsin Electric Power Company

In September 2022, WE issued $ 500.0 million of 4.75 % Debentures due September 30, 2032, and intends to allocate an amount equal to the net proceeds for the construction and development of eligible green expenditures, which include existing and new expenditures for the acquisition, construction and development of wind and solar electric generating facilities and related energy storage assets.

Wisconsin Public Service Corporation

In November 2022, WPS issued $ 300.0 million of 5.35 % Senior Notes due November 10, 2025, and used the net proceeds to repay short-term debt and for other corporate purposes.

The Peoples Gas Light and Coke Company

In December 2022, PGL issued $ 100.0 million of 5.23 % Bonds, Series MMM due December 1, 2027, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

WEC Infrastructure Wind Holding II LLC

In December 2022, WECI Wind Holding II issued $ 199.3 million of 6.38 % Senior Notes due December 31, 2031, and used the net proceeds to return a portion of WECI's previously invested capital in the subsidiaries of WECI Wind Holding II.

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

In September 2023, we issued $ 600.0 million of 5.60 % Senior Notes due September 12, 2026, and used the net proceeds to repay short-term debt and for other corporate purposes.

Subsequently, we repaid the outstanding principal and accrued interest on our $ 700.0 million of 0.55 % Senior Notes that matured on September 15, 2023.

In January and February, 2024, pursuant to a tender offer, we purchased $ 122.1 million aggregate principal amount of the $ 500.0 million outstanding of our 2007 Junior Notes for $ 115.2 million with proceeds from issuing commercial paper.

We recorded a $ 6.9 million gain related to the early settlement.

Integrys Holding, Inc.

In March 2023, Integrys repurchased $ 18.9 million of the $ 221.4 million outstanding of its 6.00 % 2013 Junior Notes, prior to maturity for $ 18.6 million.

Integrys recognized an insignificant gain on the early extinguishment of debt due to the debt being repurchased at a discount.

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

2023 Form 10-K 124

WEC Energy Group, Inc.

The Peoples Gas Light and Coke Company

In November 2023, PGL issued $ 100.0 million of 5.82 % First and Refunding Mortgage Bonds, Series NNN due April 1, 2029, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

North Shore Gas Company

In November 2023, NSG issued $ 20.0 million of 5.82 % First Mortgage Bonds, Series T due April 1, 2029, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.

Maturities of Long-Term Debt Outstanding

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Principal Amount

WEC Energy Group Senior Notes (unsecured) 0.55 % September $ 700.0

WEC Energy Group Senior Notes (unsecured) 0.80 % March $ 600.0

WG Debentures (unsecured) 2.38 % November 150.0

PGL Bonds (secured) 2.64 % November 75.0

WE Debentures (unsecured) 2.05 % December 300.0

WEPCo Environmental Trust (secured, nonrecourse) 1.58 % Semi-annually 9.0

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(in millions) Payments

2024 $ 1,264.2

Thereafter 8,509.9

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Obligations Under Operating Leases

We have recorded right of use assets and lease liabilities 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, though April 2029.

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 2029.

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

• Land we are leasing related to our Solar Now projects.

2023 Form 10-K 125

WEC Energy Group, Inc.

• 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 2073.

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 not included in our calculation of the lease obligations, as it is not reasonably certain that they will be exercised.

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

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases, the expense recognition pattern of our finance leases at our regulated entities resembles that of an operating lease.

The difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842.

2022 Form 10-K 122

WEC Energy Group, Inc.

Power Purchase Commitment

In 1997, WE entered into a 25 -year PPA with LSP-Whitewater Limited Partnership.

The contract, for 236.5 MW of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements.

The PPA expired on May 31, 2022;

however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022.

Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility for $ 72.7 million, which excludes working capital and transaction costs.

This asset purchase agreement was approved by the PSCW in December 2022, and the acquisition closed effective January 1, 2023.

In accordance with ASC Subtopic 980-842, Regulated Operations – Leases (Subtopic 980-842), the timing of expense recognition associated with our finance leases is modified to conform to the rate treatment.

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.

The difference between this lease expense and the sum of imputed interest and unadjusted amortization costs calculated under Topic 842 is deferred as a regulatory asset on our balance sheets in accordance with Subtopic 980-842.

Land Leases – Utility Solar Generation

WE and WPS, along with an unaffiliated utility, have entered into various land leases related to their investment in utility-scale solar generation.

We have various land leases related to our investments in utility solar generation.

Each lease has an initial term and one or more optional extensions.

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Our payments related to these leases are being recovered through rates.

Power Purchase Commitment

In 1997, WE entered into a 25 -year PPA with LSP-Whitewater Limited Partnership.

The contract, for 236.5 MWs of firm capacity from a natural gas-fired cogeneration facility, included zero minimum energy requirements.

The PPA expired on May 31, 2022;

however, in November 2021, WE entered into a tolling agreement with LSP-Whitewater Limited Partnership that commenced on June 1, 2022.

Concurrent with the execution of the tolling agreement, WE and WPS entered into an asset purchase agreement to acquire the natural gas-fired cogeneration facility and the acquisition closed effective January 1, 2023.

See Note 2, Acquisitions, for more information.

Both the PPA and the tolling agreement were accounted for as a finance lease prior to the acquisition.

2023 Form 10-K 126

WEC Energy Group, Inc.

Amounts Recognized in the Financial Statements and Other Information

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Right of use assets obtained in exchange for finance lease liabilities (4)

$ 32.8 $ 57.6 $ 73.6

Right of use assets obtained in exchange for operating lease liabilities 18.3 — 0.5

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(2) Interest on lease liabilities was included as a component of interest expense.

(3) Operating and short-term lease expense were included as a component of operation and maintenance expense.

(3) Operating and short-term lease expense were included as a component of other operation and maintenance expense.

(4) Amounts are net of any reductions to right of use assets and finance lease liabilities resulting from remeasurements.

(5) Because our leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.

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Current finance lease liabilities

Power purchase commitment $ 72.7 $ 78.4 Current portion of long-term debt

Power purchase commitment (1)

$ — $ 72.7 Current portion of long-term debt

Long-term finance lease liabilities

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Total long-term finance lease liabilities $ 145.9 $ 110.5 Long-term debt

(1) Effective January 1, 2023, WE and WPS closed on the acquisition of Whitewater.

See discussion above for more information.

(2) Amounts are net of accumulated amortization of $ 6.1 million and $ 146.3 million at December 31, 2023 and 2022, respectively.

Future minimum lease payments under our operating and finance leases and the present value of our net minimum lease payments as of December 31, 2023, were as follows:

(in millions) Total Operating Leases Power Purchase Commitment Land Leases - Utility Solar Generation Other Total Finance Leases

(in millions) Total Operating Leases Land Leases - Utility Solar Generation Other Total Finance Leases

2024 $ 6.4 $ 4.7 $ 0.1 $ 4.8

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(in millions) 2023 2022 2021

Current tax expense $ 50.2 $ 93.9 $ 49.2

Current tax expense (benefit) $ ( 14.8 ) $ 50.2 $ 93.9

Deferred income taxes, net 229.9 278.5 111.0

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State income taxes net of federal tax benefit 94.3 6.1 % 109.7 6.3 % 96.1 6.4 %

Wind PTCs ( 107.6 ) ( 6.2 ) % ( 81.3 ) ( 5.4 ) % ( 51.5 ) ( 3.6 ) %

PTCs, net ( 168.2 ) ( 10.9 ) % ( 107.6 ) ( 6.2 ) % ( 81.3 ) ( 5.4 ) %

Federal excess deferred tax amortization (1)

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AFUDC-Equity ( 12.4 ) ( 0.8 ) % ( 6.2 ) ( 0.4 ) % ( 3.8 ) ( 0.3 ) %

( 6.2 ) ( 0.4 ) % ( 3.8 ) ( 0.3 ) % ( 4.4 ) ( 0.3 ) %

ITC restored ( 5.8 ) ( 0.3 ) % ( 4.6 ) ( 0.3 ) % ( 3.5 ) ( 0.2 ) %

Federal excess deferred tax amortization – Wisconsin unprotected (2)

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The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.

(2) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years , to reduce near-term rate impacts to their customers.

(2) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities amortized these unprotected deferred tax benefits over periods ranging from two years to four years , to reduce near-term rate impacts to their customers.

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Natural gas contracts $ 2.2 $ 8.3 $ — $ 10.5

FTRs — — 7.8 7.8

FTRs and TCRs — — 7.2 7.2

Coal contracts — 0.3 — 0.3

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Natural gas contracts $ 70.1 $ 16.0 $ — $ 86.1

Coal contracts — 20.3 — 20.3

Total derivative liabilities $ 70.1 $ 36.3 $ — $ 106.4

2023 Form 10-K 131

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The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices.

They also include FTRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets.

During 2022, we also held TCRs, which were used at certain of our non-utility wind parks to manage electric transmission congestion costs in the SPP Integrated Marketplace, but these TCRs settled prior to December 31, 2022.

They also include FTRs and TCRs, which are used at our electric utilities and certain of our non-utility wind parks to manage electric transmission congestion costs in the MISO Energy Markets and the SPP Integrated Marketplace, respectively.

We hold investments in the Integrys rabbi trust.

These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans.

These investments are used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans.

These investments are included in other long-term assets on our balance sheets.

We recorded $ 12.7 million of net unrealized losses in earnings related to the investments held at the end of the period during the year ended December 31, 2022.

For the years ended December 31, 2021 and 2020, the net unrealized gains included in earnings related to the investments held at the end of the period were $ 16.0 million and $ 6.3 million, respectively.

During the years ended December 31, 2023 and 2021, the net unrealized gains included in earnings related to the investments held at the end of the period were $ 10.0 million and $ 16.0 million, respectively.

For the year ended December 31, 2022, we recorded $ 12.7 million of net unrealized losses in earnings related to the investments held at the end of the period.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:

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Purchases 21.0 23.7 6.1

Realized and unrealized gains included in earnings (1)

Realized and unrealized net gains (losses) included in earnings (1)

( 0.5 ) 0.5 —

Settlements ( 21.1 ) ( 18.8 ) ( 6.1 )

Balance at the end of the period $ 7.2 $ 7.8 $ 2.4

Losses included in earnings attributable to the change in unrealized losses of Level 3 derivatives held at the end of the reporting period (1)

Unrealized net gains (losses) included in earnings attributable to Level 3 derivatives held at the end of the reporting period (1)

$ 0.5 $ ( 0.4 ) $ —

(1) Amounts relate to FTRs and TCRs acquired by certain wind generating facilities included in our non-utility energy infrastructure segment.

These realized and unrealized gains and losses are recorded in operating revenues on our income statements.

(1) Amounts relate to FTRs and TCRs included in our non-utility energy infrastructure segment.

These realized and unrealized net gains and losses are recorded in operating revenues on our income statements.

Fair Value of Financial Instruments

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NOTE 18— DERIVATIVE INSTRUMENTS

Derivative assets and liabilities not shown separately on our balance sheets are included in the other current and other long-term line items.

Derivative assets and liabilities are included in the other current and other long-term line items on our balance sheets.

The following table shows our derivative assets and derivative liabilities.

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Natural gas contracts $ 10.4 $ 78.1 $ 32.5 $ 88.2

FTRs 7.8 — 2.4 —

FTRs and TCRs 7.2 — 7.8 —

Coal contracts 0.3 10.9 18.9 —

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December 31, 2023 December 31, 2022 December 31, 2021

(in millions) Volumes Gains Volumes Gains Volumes Gains (Losses)

(in millions) Volumes Gains (Losses) Volumes Gains Volumes Gains

Natural gas contracts 198.0 Dth

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At December 31, 2023 and 2022, we had posted cash collateral of $ 100.3 million and $ 122.4 million, respectively.

We had also received cash collateral of $ 13.2 million at December 31, 2021.

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

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Gross amount not offset on the balance sheet ( 3.1 ) ( 71.0 ) (1)

( 17.5 ) ( 82.5 ) (2)

Net amount $ 14.9 $ 35.4 $ 57.3 $ 14.1

(1) Includes cash collateral posted of $ 67.9 million.

(2) Includes cash collateral received of $ 6.4 million.

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

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As these swaps qualified for cash flow hedge accounting treatment, the related gains and losses were deferred in accumulated other comprehensive loss and were amortized to interest expense as interest was accrued on the 2007 Junior Notes.

We also previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys.

These swap agreements were settled in 2015, and we continue to

2023 Form 10-K 133

WEC Energy Group, Inc.

We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys.

These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The table below shows the amounts related to these cash flow hedges recorded in other comprehensive income (loss) and in earnings, along with our total interest expense on the income statements, for the years ended December 31:

(in millions) 2022 2021 2020

Derivative gain (loss) recognized in other comprehensive income / loss $ — $ 0.8 $ ( 5.9 )

Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense 0.4 ( 1.3 ) ( 2.1 )

Total interest expense line item on the income statements 515.1 471.1 493.7

We estimate that during the next twelve months $ 0.4 million will be reclassified from accumulated other comprehensive loss as a reduction to interest expense.

amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.

The derivative gains and losses related to these swap agreements recognized in other comprehensive income and reclassified from accumulated other comprehensive loss to interest expense during the years ended December 31, 2023, 2022, and 2021 were not significant.

At December 31, 2023, the amount expected to be reclassified from accumulated other comprehensive loss to interest expense over the next twelve months was also not significant.

NOTE 19— GUARANTEES

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Other guarantees (3)

11.6 — — 11.6

Total guarantees $ 167.6 $ 58.3 $ — $ 109.3

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These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.

2022 Form 10-K 130

WEC Energy Group, Inc.

We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans.

Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.

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WEC Energy Group, Inc.

The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:

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Plan amendments — — — 0.2

Actuarial gain ( 682.3 ) ( 101.3 ) ( 127.9 ) ( 20.3 )

Actuarial (gain) loss 81.9 ( 682.3 ) 45.9 ( 127.9 )

Benefit payments ( 191.7 ) ( 281.0 ) ( 46.0 ) ( 45.7 )

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Actual return on plan assets 214.9 ( 431.3 ) 76.4 ( 135.4 )

Employer contributions 11.4 62.4 3.7 3.9

Employer contributions net of plan transfer (1)

14.6 11.4 ( 47.9 ) 3.7

Participant contributions — — 11.8 12.5

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Funded status at December 31 $ 313.4 $ 312.1 $ 381.5 $ 433.0

In 2022 and 2021, we had actuarial gains related to our pension benefit obligations of $ 682.3 million and $ 101.3 million, respectively, both of which were primarily driven by changes in our discount rates.

(1) Employer contribution includes a $ 50.0 million transfer out of the WEC Energy Group Retiree Welfare Plan, in 2023, associated with the overfunded position of this plan.

In 2023, we had actuarial losses related to our pension benefit obligations of $ 81.9 million and actuarial gains in 2022 of $ 682.3 million.

The primary driver for the actuarial loss was a lower discount rate in 2023.

Partially offsetting the loss in 2023, was higher than expected asset returns.

The discount rate for our pension benefits was 5.19 %, 5.49 %, and 2.96 % in 2023, 2022, and 2021, respectively.

In 2022, we had an actuarial gain related to our OPEB benefit obligation of $ 127.9 million, which was primarily driven by an increase in our discount rate.

In 2023, we had actuarial losses related to our OPEB benefit obligation of $ 45.9 million and actuarial gains in 2022 of $ 127.9 million.

The primary driver for the actuarial loss was changes to medical trend assumptions and a lower discount rate in 2023.

Partially offsetting the loss in 2023, was higher than expected asset returns.

The discount rate for our OPEB benefits was 5.16 %, 5.50 %, and 2.92 % in 2023, 2022, and 2021, respectively.

The 2021 actuarial gain related to our OPEB benefit obligations was not significant.

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:

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Net periodic benefit cost (credit) $ ( 6.8 ) $ 17.7 $ 55.8 $ ( 48.7 ) $ ( 79.8 ) $ ( 82.5 )

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs.

As a result, as of December 31, 2023, we recorded a $ 6.0 million regulatory asset for pension costs and a $ 14.8 million regulatory asset for OPEB costs.

The above table does not reflect any adjustments for the creation of these regulatory assets.

2023 Form 10-K 136

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We also own approximately 75 % of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint.

ATC's corporate manager has an eleven -member board of directors, and ATC Holdco's corporate manager has a four -member board of directors.

ATC's corporate manager has a ten -member board of directors, and ATC Holdco's corporate manager has a four -member board of directors.

We have one representative on each board.

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Balance at January 1 $ 1,766.9 $ 22.5 $ 1,789.4

Earnings (loss) from equity method investment 166.4 ( 8.3 ) 158.1

Earnings from equity method investment 192.6 2.1 194.7

Capital contributions 45.5 — 45.5

Distributions 120.4 — 120.4

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Balance at January 1 $ 1,733.5 $ 30.8 $ 1,764.3

Earnings from equity method investment 174.3 1.5 175.8

Capital contributions 21.2 — 21.2

Earnings (loss) from equity method investment 166.4 ( 8.3 ) 158.1

Distributions 133.0 — 133.0

Return of capital — 6.8 6.8

Balance at December 31 $ 1,766.9 $ 22.5 $ 1,789.4

In November 2019 and May 2020, the FERC issued orders that addressed complaints related to ATC's allowed ROE.

Due to the various petitions related to the complaint filed in February 2015, our financials at December 31, 2021 and 2020, included a

Due to the various petitions related to the complaint filed in February 2015, our financials at December 31, 2021 and 2020, included a $ 39.1 million liability for potential future refunds that ATC may have been required to provide.

In August 2022, a decision issued by

2023 Form 10-K 139

WEC Energy Group, Inc.

$ 39.1 million liability for potential future refunds that ATC may have been required to provide.

In August 2022, a decision issued by the D.C.

Circuit Court of Appeals affirmed the FERC’s previous orders related to the February 2015 complaint.

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WEC Energy Group, Inc.

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

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

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

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

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and also included the operations of PDL prior to the sale of its remaining solar facilities in the fourth quarter of 2020.

See Note 3, Dispositions, for more information on the sale of these solar facilities.

• The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, and WBS.

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

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Other operation and maintenance 1,531.3 397.9 94.5 2,023.7 — 80.1 5.8 ( 9.1 ) 2,100.5

Impairment related to ICC disallowances — 178.9 — 178.9 — — — — 178.9

Depreciation and amortization 851.5 237.3 43.3 1,132.1 — 188.7 20.9 ( 77.5 ) 1,264.2

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Interest expense 555.9 73.8 13.9 643.6 19.4 68.9 119.4 ( 336.2 ) 515.1

Loss on debt extinguishment — — — — — — 36.3 — 36.3

Income tax expense (benefit) 247.5 83.1 13.1 343.7 45.8 ( 20.9 ) ( 45.7 ) — 322.9

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Cash collections from the environmental control charge and funds on deposit in trust accounts are the sole sources of funds to satisfy the debt obligation.

The bondholders have no recourse to WE or any of WE's affiliates.

The bondholders do not have any recourse to WE or any of WE's affiliates.

WE acts as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and is responsible for metering, calculating, billing, and collecting the environmental control charge.

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Purchased power 2063 333.5 56.7 56.4 57.5 52.1 48.4 62.4

Other 2043 100.6 13.9 13.3 12.9 11.6 10.2 38.7

Natural gas utility:

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We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:

• the development of additional sources of renewable electric energy supply;

• the development of additional sources of renewable electric energy supply, battery storage, and natural gas and LNG storage facilities;

• the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;

• the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;

• the protection of wetlands and waterways, biodiversity including threatened and endangered species, and cultural resources associated with utility construction projects;

• the protection of wetlands and waterways, biodiversity including threatened and endangered species, and cultural resources associated with construction projects;

• the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;

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Cross State Air Pollution Rule – Good Neighbor Plan

The proposed rule to address the 2015 ozone NAAQS, resulting in more stringent regulation of ozone-season NOx emissions from electric utility generating units in 26 states, is expected to take effect in 2023.

Based on a review of our existing units' 2020 and 2021 actual ozone season emissions and projected future emissions versus proposed NOx ozone season allocations, we anticipate that we should be able to comply with the expanded rule requirements without procuring additional allowances on the open market.

Our RICE units in the Upper Peninsula of Michigan and planned RICE units in Wisconsin are not subject to this rule as proposed as each unit is less than 25 MW.

We note that, to the extent we use RICE engines for natural gas distribution operations, those engines may be subject to the emission limits and operational requirements of the rule beginning in 2026.

In June 2022, we submitted comments on this proposed rule seeking clarification of its applicability, as well as other items, and we will closely monitor the final rule for any changes from the proposed rule.

In March 2023, the EPA issued its final Good Neighbor Plan, which became effective in August 2023 and requires significant reductions in ozone-forming emissions of NOx from power plants and industrial facilities.

After review of the final rule, we believe that we are well positioned to meet the requirements.

Our RICE units in the Upper Peninsula of Michigan and Wisconsin are not currently subject to the final rule as each unit is less than 25 MWs.

To the extent we use RICE engines for natural gas distribution operations, those engines not part of an LDC are subject to the emission limits and operational requirements of the rule beginning in 2026.

The EPA has exempted LDCs from the final rule.

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WEC Energy Group, Inc.

Mercury and Air Toxics Standards

In 2012, the EPA issued the MATS to limit emissions of mercury, acid gases, and other hazardous air pollutants.

In April 2023, the EPA issued the pre-publication version of a proposed rule to strengthen and update MATS to reflect recent developments in control technologies and performance of coal and oil-fired units.

The EPA proposed three revisions including a proposal to lower the PM limit from 0.03 lb/MMBtu to 0.01 lb/MMBtu.

The EPA also sought comments on an even lower limit of 0.006 lb/MMBtu.

Adoption of either of these lower limits could have an adverse effect on our operations.

National Ambient Air Quality Standards

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The 2015 ozone standard lowered the 8-hour limit for ground-level ozone.

In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting a previously issued EPA staff-written Integrated Science Assessment for ozone which supported the reconsideration of the 2015 standard.

The EPA had planned a proposed rule in April 2023, but the CASAC review is expected to slow the process.

In June 2021, the EPA published its final action to revise the nonattainment area designations and/or boundaries for 13 counties associated with six nonattainment areas, including several in Illinois and Wisconsin.

Under the new designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the "Milwaukee" nonattainment area.

Additionally, the Chicago, IL-IN-WI nonattainment area now includes an expanded portion of Kenosha County, and the partial nonattainment areas of Sheboygan, Door, and Manitowoc counties were also expanded.

In November 2022, the EPA's 2022 CASAC Ozone Review Panel issued a draft report supporting the reconsideration of the 2015 standard.

The EPA staff initially issued a draft Policy Assessment in March 2023 that supported the reconsideration, however, in August 2023 it announced that it is instead restarting its ozone standard evaluation.

The EPA has indicated it plans to release its Integrated Review Plan in fall 2024.

This new review is anticipated to take 3 to 5 years to complete.

In February 2022, revisions to the Wisconsin Administrative Code to adopt the 2015 standard were finalized.

The amended regulations adopted the standard and incorporated by reference the federal air pollution monitoring requirements related to the standard.

The WDNR submitted the rule updates as a SIP revision to the EPA in April 2022, which the EPA proposed to approve in August 2022.

In April 2022, the EPA proposed to find that the Milwaukee and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and will be adjusted to "moderate" nonattainment status for the 2015 standard.

The amended regulations incorporated by reference the federal air pollution monitoring requirements related to the standard.

The WDNR submitted the rule updates as a SIP revision to the EPA, which the EPA approved in February 2023.

In April 2022, the EPA proposed to find that the Milwaukee, Sheboygan, and Chicago, IL-IN-WI nonattainment areas did not meet the marginal attainment deadline of August 2021 and should be adjusted to "moderate" nonattainment status for the 2015 standard.

In October 2022, the EPA published its final reclassifications from "marginal" to "moderate" for these areas, effective November 7, 2022.

Accordingly, the WDNR must submit a SIP revision to address the moderate nonattainment status.

We also expect the moderate nonattainment designation to impact emission offset ratios for major construction permitting in these areas.

Accordingly, the WDNR submitted a SIP revision to the EPA in December 2022 to address the moderate nonattainment status.

In October 2023, the EPA found that 11 states, including Wisconsin, failed to submit timely SIP revisions to address nonattainment areas classified as "moderate" for the 2015 standard.

This action triggered a 24-month deadline for states to get their SIP approved or the EPA will issue a federal implementation plan.

Additionally, offset sanctions will take effect in 18 months if the SIP is not approved.

The offset sanctions impact volatile organic compound and NOx emissions from new or modified sources in the nonattainment areas.

We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply with the associated state and federal rules.

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In December 2020, the EPA completed its 5-year review of the 2012 annual and 24-hour standards for fine PM and determined that no revisions were necessary to the current annual standard of 12 µg/m 3 or the 24-hour standard of 35 µg/m 3 .

All counties within our service territories are in attainment with the current 2012 standards.

Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the PM NAAQS to below the current level of 12 µg/m 3 , while retaining the 24-hour standard.

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The EPA also proposed not to change the current secondary (welfare-based) annual PM2.5 standard, primary and secondary 24-hour PM2.5 standards, and primary and secondary PM10 standards.

The EPA is also taking comments on the full range (between 8 and 11 µg/m 3 ) included in the CASAC's latest report.

We anticipate the final rule to be released in late 2023.

All counties within our service territories are in attainment with the current 2012 standards.

If the EPA lowers the annual standard to 10 or 11 µg/m 3 , our generating facilities within our service territories should remain in attainment.

If the EPA lowers it to below 10 µg/m 3 , there could be some nonattainment areas that may affect permitting of some smaller ancillary equipment located at our facilities.

After finalization of the rule, the WDNR will need to draft a SIP and submit for the EPA's approval.

The EPA did, however, take comments on the full range (between 8 and 11 µg/m 3 ) included in the CASAC's latest report.

The EPA finalized the rule on February 7, 2024 and lowered the primary annual PM2.5 level to 9 µg/m 3 , which could cause some nonattainment areas that may affect permitting at our facilities.

The secondary and 24-hour standards remain unchanged.

The EPA will designate areas as attainment and nonattainment with the new standard by early 2026.

The WDNR will need to draft and submit a SIP for the EPA's approval.

Climate Change

The ACE rule, which replaced the Clean Power Plan, was vacated by the D.C.

Circuit Court of Appeals in January 2021.

In October 2021, the Supreme Court agreed to review the D.C.

Circuit Court's ruling vacating the EPA's ACE rule and in June 2022, the Supreme Court issued its decision.

The Supreme Court found that the EPA may regulate GHGs under section 111 of the CAA but cannot rely on generation shifting to lower carbon emitting sources to do so.

We expect a new GHG replacement rule for existing sources to be proposed in March 2023.

In January 2021, the EPA finalized a rule to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants;

however, it was vacated by the D.C.

Circuit Court of Appeals in April 2021.

Based on an updated EPA regulatory

In May 2023, the EPA proposed GHG performance standards for existing fossil-fired steam generating and gas combustion units and also proposed to repeal the Affordable Clean Energy rule, which had replaced the Clean Power Plan.

For coal plants, no standards

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WEC Energy Group, Inc.

timeline, we expect a new rule to be proposed in March 2023.

We continue to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.

The EPA released proposed regulations for the Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022.

The proposed revisions could impact the reporting required of our local natural gas distribution companies and underground natural gas storage facilities with updates to emission factors for equipment counts and increased disclosure for large release events.

We expect the final rule in 2023, pending the EPA's review and consideration of public comments.

would apply under the proposed version of the rule until 2032, and after 2032 the applicable standard would depend on the unit's retirement date.

For combined cycle natural gas plants above a 50 % capacity factor, the proposed rule is highly dependent on the use of hydrogen as an alternative fuel, and on carbon capture technology.

For simple cycle natural gas-fired combustion turbines, the proposed version of the rule does not include applicable limits as long as the capacity factor is less than 20 %.

Our RICE units in Michigan and the new Weston RICE project are not affected under the rule because each RICE unit is less than 25 MWs.

We continue to evaluate the proposed rule to understand the impacts to our operations.

A final rule is expected in the second quarter of 2024.

In May 2023, the EPA proposed to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants.

The EPA is proposing two distinct 111(b) rules – one for natural gas-fired stationary combustion turbines and the other for coal-fired units.

New stationary combustion turbine units would be divided into three subcategories based on their annual capacity factor – low load, intermediate load, and base load.

Our RICE units are not affected by this rule since each unit is below 25 MWs.

Our ESG Progress Plan is heavily focused on reducing GHG emissions.

The EPA has indicated that it anticipates a final rule in the second quarter of 2024.

The EPA released proposed regulations for the Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98, in June 2022.

In May 2023, the EPA released a supplementary proposal, which includes updates of the global warming potentials to determine CO 2 equivalency for threshold reporting and the addition of a new section regarding energy consumption.

The proposed revisions could impact the reporting required for our electric generation facilities, local natural gas distribution companies, and underground natural gas storage facilities.

In August 2023, the EPA also issued its proposed updates to amend reporting requirements for petroleum and natural gas systems, with an anticipated final rule to be issued in early 2024.

We are currently evaluating the potential impact of the proposed rule, if any, on our operations.

Our ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation.

We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018.

Through our ESG Progress Plan, we expect to retire approximately 1,600 MW of additional fossil-fueled generation by the end of 2026, which includes the planned retirements in 2024-2025 of OCPP Units 5-8 and the planned retirement by June 2026 of jointly-owned Columbia Units 1-2.

See Note 7, Property, Plant, and Equipment, for more information on the timing of the retirements.

We have already retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018.

We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirements in 2024-2025 of OCPP Units 5-8, the planned retirement by June 2026 of jointly-owned Columbia Units 1 and 2, and the planned retirement in 2031 of Weston Unit 3.

See Note 7, Property, Plant, and Equipment, for more information related to these planned power plant retirements.

In May 2021, we announced goals to achieve reductions in carbon emissions from our electric generation fleet by 60 % by the end of 2025 and by 80 % by the end of 2030, both from a 2005 baseline.

We expect to achieve these goals by making operating refinements, retiring less efficient generating units, and executing our capital plan.

Over the longer term, the target for our generation fleet is net-zero CO 2 emissions by 2050.

We also continue to reduce methane emissions by improving our natural gas distribution system and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

We expect to achieve these goals by continuing to make operating refinements, retiring less efficient generating units, and executing our capital plan.

Over the longer term, the target for our generation fleet is to be net carbon neutral by 2050.

We also continue to reduce methane emissions by improving our natural gas distribution systems, and have set a target across our natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.

We plan to achieve our net-zero goal through an effort that includes both continuous operational improvements and equipment upgrades, as well as the use of RNG throughout our utility systems.

We are required to report our CO 2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program.

Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 19.5 million metric tonnes to the EPA for 2022.

The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO 2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell.

Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 29.3 million metric tonnes to the EPA for 2022.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts.

The federal rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.

In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code.

This new state rule, NR 111, became effective in June 2020, and the WDNR will apply it when establishing BTA requirements for cooling water intake structures at existing facilities.

The EPA issued a final regulation under Section 316(b) of the CWA that became effective in October 2014 and requires the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the BTA for minimizing adverse environmental impacts.

The rule applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted and received a final BTA determination under the rules governing new facilities.

Pursuant to a WDNR rule, which became effective in June 2020, the requirements of federal Section 316(b) of the CWA were incorporated into the Wisconsin Administrative Code.

The WDNR applies this rule when establishing BTA requirements for cooling water intake structures at existing facilities.

These BTA requirements are incorporated into WPDES permits for WE and WPS facilities.

We have received a final BTA determination for VAPP.

We have received interim BTA determinations for PWGS, OCPP Units 5-8 and Weston Units 2, 3, and 4.

Existing technology at the PWGS may satisfy the BTA requirements;

however, a final determination will not be made until the WPDES permit is renewed for this facility, which is expected in the first half of 2023.

We have received interim BTA determinations for OCPP Units 5-8 and Weston Units 3 and 4.

We believe that existing technology installed at the OCPP facility meets the BTA requirements;

however, depending on the timing of the permit reissuance, all four generating units may be retired prior to the WDNR making a final BTA decision anticipated in 2025.

In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance in 2023.

however, depending on the timing of the permit reissuance, all four generating units at the OCPP may be retired prior to the WDNR making a final BTA decision, anticipated in 2025.

In addition, we believe that existing technology installed at the Weston facility will result in a final BTA determination during the WPDES permit reissuance expected in the first quarter of 2024.

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As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to continue to meet this regulation and do not expect to incur significant additional compliance costs.

The WDNR reissued the WPDES permit for PWGS effective October 2023.

This reissued permit includes a conditional BTA determination with conditions for the existing PWGS porous dike (rock breakwater) cooling water intake structure.

We do not anticipate compliance with these conditions will result in a material impact on our financial condition or the efficiency of power plant operations.

Steam Electric Effluent Limitation Guidelines

The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities.

This rule created new requirements for several types of power plant wastewaters.

The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater.

Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule.

There will, however, need to be facility modifications to meet water permit requirements for the BATW system at Weston Unit 3, which is expected to be completed by December 2023.

Modifications to OC 7 and OC 8 BATW systems were completed and placed in-service in mid-2021.

Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the ERGS units.

Based on existing contracts and engineering cost estimates, we expect that compliance with the ELG rule will require $ 100 million in capital investment.

In December 2021, the PSCW issued a Certificate of Authority approving the ERGS FGD wastewater treatment system modification.

The BATW modifications do not require PSCW approval prior to construction.

All of these ELG required projects are either in-service or are on track for completion by the WPDES permit deadline in December 2023.

In July 2021, the EPA announced its intention to initiate a "supplemental rulemaking" to revise the ELG Reconsideration Rule that was finalized in late 2020.

The EPA has stated that the 2020 ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process.

As part of their regulatory agenda, the EPA Office of Water included plans to issue a direct final rule reopening the NOPP deadline to enter the cessation of the coal subcategory (i.e.

unit retirements or conversions to natural gas by the end of December 2028 instead of making capital investments to add more treatment technology) established in the 2020 ELG Rule.

The new NOPP deadline will be 90 days after publication in the Federal Register , which is anticipated during the first quarter of 2023.

The EPA will publish the direct final rule at the same time as the proposed ELG supplemental rulemaking.

The EPA's ELG rule, effective January 2016 and modified in 2020, revised the treatment technology requirements related to BATW and wet FGD wastewaters at existing coal-fueled facilities and created new requirements for several types of power plant wastewaters.

The two new requirements that affect WE and WPS facilities relate to discharge limits for BATW and wet FGD wastewater.

Although our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule, certain facility modifications are necessary to meet the ELG rule requirements.

Through 2023, compliance costs associated with the ELG rule required $ 105 million in capital investment.

An $ 8 million BATW modification to OCPP Units 7 and 8 was completed and placed in-service in mid-2021, and in December 2021, the PSCW issued a Certificate of Authority approving the $ 89 million ERGS FGD wastewater treatment system modification.

The BATW modifications, including $ 8 million of modifications at Weston Unit 3 completed in June 2023, did not require PSCW approval prior to construction.

All of these ELG required projects were placed in-service ahead of WPDES permit deadlines.

In March 2023, the EPA issued the proposed "supplemental ELG rule." The rule would replace the existing 2020 ELG rule and, as proposed, would establish stricter limitations on:

2) FGD wastewater;

3) CCR leachate;

and 4) legacy wastewaters.

The most significant proposed ELG rule change is a ZLD requirement for FGD wastewater.

Under the proposed rule, this new ZLD requirement must be met by a date determined by the permitting authority (the WDNR for WE) that is as soon as possible beginning 60 days following publication of the final rule, but no later than December 31, 2029.

The proposed rule would also create a subcategory for "early adopters" that have already installed a compliant biological treatment system by the date of the proposed rule.

Early adopters would not be required to install further FGD wastewater treatment, provided the facility owner also agrees to permanently cease combustion of coal by December 31, 2032.

Although the $ 89 million biological treatment system at ERGS is complete and was placed in service in December 2023 to meet the WPDES permit deadline, the timing of the project's completion did not comply with the deadline proposed by the EPA to qualify for the early adopter status.

In addition, we do not believe that the biological treatment system would be compliant with the additional ZLD FGD wastewater treatment requirements as proposed.

In May 2023, we submitted written comments to the EPA articulating these concerns, including the cost impact to our customers.

The EPA has indicated that it anticipates issuing the final rule in the second quarter of 2024.

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

The EPA also proposed requirements for legacy wastewaters and landfill leachate.

We have reviewed the proposed requirements to determine potential costs and actions required for our facilities.

We submitted comments to the EPA regarding these proposed requirements.

Waters of the United States

In January 2023, the EPA and the United States Army Corps of Engineers together released a final rule revising the definition of WOTUS.

This rule will be effective March 20, 2023.

The final rule states that it is based on the pre-2015 definition of "waters of the United States." The pre-2015 approach involves applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

The recent rulemaking could be affected by a significant pending Supreme Court case involving WOTUS determination.

In January 2022, the Supreme Court granted certiorari in a case, Sackett v.

Environmental Protection Agency , to evaluate the proper test for determining whether wetlands are WOTUS.

A decision by the Supreme Court is expected in spring 2023.

At this point, our projects requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts.

The Sackett case, once decided, should provide some clarity regarding the definition of WOTUS.

We will continue to monitor this litigation and any subsequent agency action.

In January 2023, the EPA and the Army Corps (the agencies) together released a final rule effective in March 2023 that established standards for identifying which wetland or surface drainage features qualify as WOTUS based on its pre-2015 definition.

The pre-2015 approach involved applying factors established through case law and agency precedents to determine whether a wetland or surface drainage feature is subject to federal jurisdiction.

In May 2023, in Sackett v.

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

In August 2023, the agencies revised the final rule to conform the definition of WOTUS to the Supreme Court's May 2023 Sackett decision.

The conforming rule became effective upon publication in the Federal Register on September 8, 2023.

We anticipate this final rule revision based on the Sackett decision may lead to a decreased number of projects that require Army Corps federal wetland permits.

This decision also may affect the administration of some state programs.

At this point, our projects

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requiring federal permits are moving ahead, but we are monitoring these recent developments to better understand potential future impacts.

Manufactured Gas Plant Remediation

7 unchanged sentences

At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

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WEC Energy Group, Inc.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation.

5 unchanged sentences

Reserves for future environmental remediation 463.7 499.6

Coal Combustion Residuals Rule

The EPA issued a pre-publication proposed rule for CCR in May 2023 that would apply to landfills, historic fill sites, and projects where CCR was placed at a power plant site.

As proposed, the rule would regulate previously exempt closed landfills.

We are actively engaged with our trade organizations and provided them information to include in their comments to the EPA.

The EPA has indicated that it anticipates issuing a final rule in the second quarter of 2024.

As proposed, the rule could have a material adverse impact on our coal ash landfills and require additional remediation that has not been required under the current state programs.

Renewables, Efficiency, and Conservation

8 unchanged sentences

UMERC was in compliance with its requirements under this statute as of December 31, 2023.

The legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

The legislation continues

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WEC Energy Group, Inc.

to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

In November 2023, Michigan enacted Acts 229, 231 and 235.

The acts require electric providers to file a renewable energy plan every two years and to set renewable energy portfolio targets from now until 2040.

The proposed renewable energy targets include 15 % through 2029, 50 % from 2030 through 2034, and 60 % renewable energy by 2035 and thereafter.

The bill also sets clean energy standards of 80 % for 2035-2039 and 100 % after 2040.

The bill only allows natural gas to count as clean energy if it is accompanied with carbon capture and storage.

The MPSC has indicated that it will complete a study by December 2024 on the unique conditions influencing electric generation, transmission, and demand in the Upper Peninsula of Michigan, which includes the unique role of RICE units placed in service to facilitate the retirement of coal-fired generation in the Upper Peninsula of Michigan.

The new acts also revise the requirement a utility must meet in filing its energy waste reduction plans.

They require a utility to file a plan every two years until 2025, then every three years thereafter.

Enforcement and Litigation Matters

10 unchanged sentences

Joint Ownership Power Plants – Columbia and Edgewater

In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric Company, WE (former co-owner of an Edgewater unit), and WPS.

In December 2009, the EPA issued an NOV to WPL, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including MG&E, WE (former co-owner of an Edgewater unit), and WPS.

The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants.

WPS, along with Wisconsin Power and Light Company, Madison Gas and Electric Company, and WE,

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WEC Energy Group, Inc.

entered into a Consent Decree with the EPA resolving this NOV.

WPS, along with WPL, MG&E, and WE, entered into a Consent Decree with the EPA resolving this NOV.

This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013.

1 unchanged sentence

See Note 6, Regulatory Assets and Liabilities, for more information about the retirement.

Wisconsin Power and Light Company started the process to close out this Consent Decree in early 2023.

WPL started the process to close out this Consent Decree.

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WEC Energy Group, Inc.

NOTE 25— SUPPLEMENTAL CASH FLOW INFORMATION

Non-Cash Transactions

Year Ended December 31

1 unchanged sentence

Cash paid for interest, net of amount capitalized $ 653.4 $ 485.2 $ 473.8

Cash paid for income taxes, net 52.4 33.8 27.9

Cash paid (received) for income taxes, net (1)

( 58.9 ) 52.4 33.8

Significant non-cash investing and financing transactions:

Accounts payable related to construction costs 171.3 197.4 127.8

Increase in receivable related to insurance proceeds — 41.7 2.7

Increase in receivables related to insurance proceeds 3.5 — 41.7

Liabilities accrued for software licensing agreement — 7.4 —

(1) Cash received for income taxes in 2023 includes $ 75 million related to PTCs that were sold to a third party.

Restricted Cash

The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash.

Our restricted cash consists of the following:

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

All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments.

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

• Cash we received when WECI acquired ownership interests in certain wind generation projects.

This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the wind generation facilities.

• Cash used by WE and WPS for the purchase of a natural gas-fired cogeneration facility located in Whitewater, Wisconsin.

This cash was included in other long-term assets at December 31, 2022.

See Note 2, Acquisitions, for more information on the purchase of this facility.

The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows:

4 unchanged sentences

Cash, cash equivalents, and restricted cash $ 165.2 $ 182.2 $ 87.5

Our restricted cash consisted of the following:

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

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

• Cash we received when WECI acquired ownership interests in certain renewable generation projects.

This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of the renewable generation facilities.

• Cash used by WE and WPS during January 2023 to purchase a natural gas-fired cogeneration facility located in Whitewater, Wisconsin.

This cash was included in other long-term assets at December 31, 2022.

See Note 2, Acquisitions, for more information on the purchase of this facility.

NOTE 26— REGULATORY ENVIRONMENT

Recovery of Natural Gas Costs

Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations.

All of our utilities have regulatory mechanisms in place for recovering all prudently incurred gas costs.

In March 2021, WE and WG received approval from the PSCW to recover approximately $ 54 million and $ 24 million, respectively, of natural gas costs in excess of the benchmark set in their GCRMs over a period of three months , beginning in April 2021.

In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $ 28 million of natural gas costs in excess of the benchmark set in its GCRM.

WPS also recovered these excess costs over a period of three months , beginning in April 2021.

PGL and NSG incurred approximately $ 131 million and $ 10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates.

These costs were recovered over a period of 12 months, which started on April 1, 2021.

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NSG's natural gas costs were reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation.

On January 5, 2023, the ICC issued written orders approving each company's 2021 reconciliation.

In February 2021, MERC incurred approximately $ 75 million of natural gas costs in excess of the benchmark set in its GCRM.

In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs.

In accordance with the order, MERC recovered $ 10 million of these costs through its annual natural gas true-up process over a period of 12 months, and the remaining $ 65 million was to be recovered over a period of 27 months, both beginning in September 2021.

Recovery of these costs and the issue of prudence was referred to a contested-case proceeding.

In October 2022, the MPUC issued a written order approving a settlement agreement entered into by MERC and various parties related to the recovery of the extraordinary natural gas costs incurred in February 2021.

Under the settlement agreement, MERC agreed to not seek recovery of $ 3 million of these costs.

MERC will continue to recover the remaining $ 62 million of extraordinary natural gas costs over the previously approved 27 -month recovery period.

Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant.

Coronavirus Disease – 2019

In response to the COVID-19 pandemic, the PSCW, the ICC, the MPUC, and the MPSC all issued written orders requiring certain actions to ensure that essential utility services were available to customers in their respective jurisdictions.

A summary of these orders is included below.

In March 2020, the PSCW issued two orders in response to the COVID-19 pandemic.

The first order required all public utilities in the state of Wisconsin, including WE, WPS, and WG, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes.

In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.

In the second order issued in March 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency.

In December 2021, the PSCW approved a motion to end all COVID-related deferrals as of December 31, 2021.

At December 31, 2022, our Wisconsin utilities did not have any amounts deferred related to the COVID-19 pandemic as the rate orders received from the PSCW in December 2022 did not allow recovery of these costs.

In June 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 2020 order.

Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively.

After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers.

Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order.

Our Wisconsin utilities resumed charging late payment fees in late August 2020.

Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020.

Subsequent to the June 2020 order, the PSCW extended the moratorium on disconnections of residential customers until November 1, 2020.

In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which customarily begins on November 1 and ends on April 15 of each year.

Utilities were allowed to continue assessing late payment fees during the winter moratorium.

On April 5, 2021, the PSCW issued a written order indicating that it would not extend the moratorium on disconnections further;

therefore, utilities could begin disconnecting residential customers for non-payment after April 15, 2021.

The order also allowed our Wisconsin utilities to resume charging late payment fees on the full balance of all outstanding arrears, regardless of the associated dates the service was provided, after April 15, 2021.

We continue to offer flexible payment arrangements to low-income residential customers prior to disconnecting service.

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WEC Energy Group, Inc.

In March 2020, the ICC issued an order to all Illinois utilities, including PGL and NSG, requiring, among other things, a moratorium on disconnections of utility service and a suspension of late fees and penalties during the declared public health emergency.

These provisions applied to all utility customer classes.

Illinois utilities were also required to temporarily enact more flexible credit and collections procedures.

In June 2020, the ICC issued a written order approving a settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors.

The key terms of the settlement agreement included the following:

• The moratorium on disconnections and the suspension of late fees and penalties were extended until July 26, 2020.

• Customers disconnected after June 18, 2019 could be reconnected without being assessed a reconnection fee if reconnection was requested prior to August 25, 2020.

• Flexible deferred payment arrangements were required to be offered to residential and commercial and industrial customers for an extended period of time and with reduced down payment requirements.

• Deposit requirements were waived until August 25, 2020 for all residential customers, and were waived for an additional four months for residential customers that verbally expressed financial hardship.

• PGL and NSG were required to establish a bill payment assistance program with approximately $ 12.0 million and $ 1.2 million, respectively, available for eligible residential customers to provide relief from high arrearages.

In addition to the above, the settlement agreement approved in June 2020 authorized PGL and NSG to implement a SPC rider for certain costs incurred between March 1, 2020 and December 31, 2021.

The SPC rider allows for recovery of incremental direct costs resulting from COVID-19, foregone late fees and reconnection charges, and the costs associated with the bill payment assistance programs.

PGL and NSG began recovering costs under the SPC rider on October 1, 2020.

Amounts deferred under the SPC rider are being recovered over 36 months and will be subject to review and reconciliation by the ICC.

As of December 31, 2022, PGL's and NSG's remaining regulatory assets related to the COVID-19 pandemic were $ 9.5 million, collectively.

Subsequent to the approval of the June 2020 settlement agreement, and at the request of the ICC, PGL and NSG agreed to extend the moratorium on disconnections for qualified low-income residential customers and residential customers expressing financial hardship through March 31, 2021.

The annual winter moratorium in Illinois that generally prohibits PGL and NSG from disconnecting residential customers for non-payment customarily begins on December 1 and ends on March 31 of each year.

In March 2021, the ICC issued a written order approving a second settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors.

The key terms of this new settlement agreement were as follows:

• Utilities could start sending disconnection notices, on a staggered basis, as of April 1, 2021.

Disconnections were done on a staggered schedule based on customer arrears and income levels.

Utilities were not allowed to disconnect customers for non-payment prior to June 30, 2021 if the customer's household income was below 300 % of the federal poverty level and the customer was on a deferred payment plan.

• Utilities were required to continue offering flexible deferred payment arrangements with reduced down payment requirements to residential customers through June 30, 2021.

• Reconnection fees were waived for eligible low income customers through June 30, 2021.

In addition, utilities will continue to exempt eligible low income customers from late payment fees and deposits.

• Each utility was required to continue, or renew, its bill payment assistance program through 2021.

In addition to the $ 12.0 million PGL initially funded, PGL was required to fund an additional $ 6.0 million to its bill payment assistance program.

No additional funding was required for NSG due to the amount still available for assistance from its initial funding.

PGL's and NSG's bill payment assistance programs ended in April 2021 and August 2021, respectively, as all of their respective funds were exhausted.

• Costs related to the provisions in the settlement agreement, including costs related to the bill payment assistance programs, were recoverable through the SPC rider.

In May 2020, the MPUC issued a written order authorizing Minnesota utilities, including MERC, to track and defer COVID-19 related expenses and certain foregone revenues.

Costs incurred at MERC related to the COVID-19 pandemic were not significant, and at December 31, 2022, MERC did not have any amounts deferred.

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

2024 Limited Rate Case Re-Opener

In accordance with their rate orders approved by the PSCW in December 2022, WE, WPS, and WG filed requests for limited electric and natural gas rate case re-openers, as applicable, with the PSCW in May 2023.

The WE and WPS limited electric rate case re-openers included updated fuel costs and revenue requirements for the generation projects that were previously approved by the PSCW and were placed into service in 2023 or are expected to be placed into service in 2024.

WE's limited electric re-opener also included the projected savings from the retirement of the OCPP Units 5 and 6, which are expected to be retired in May 2024.

WE and WG also filed a request for a limited natural gas rate case re-opener to reflect the additional revenue requirements associated with their previously approved LNG projects.

WE's LNG project was placed into service in November 2023, and WG's LNG project is expected to be placed into service in 2024.

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In June 2020, the MPUC verbally ordered Minnesota utilities to temporarily suspend disconnections and waive reconnection fees, service deposits, late fees, interest, and penalties for all residential customers.

In addition, utilities were required to immediately reconnect residential customers that were previously disconnected.

In August 2020, the MPUC issued a written order affirming these temporary provisions.

Prior to the June 2020 verbal order issued by the MPUC, MERC had voluntarily taken actions to ensure its customers continued to receive utility services during the pandemic.

These actions included, but were not limited to, temporarily suspending disconnections and waiving late payment fees for residential and small commercial and industrial customers that entered into payment plans.

In March 2021, the MPUC issued an order requiring Minnesota utilities to file a transition plan to resume collections and disconnections.

MERC filed its transition plan in April 2021, and it was subsequently deemed complete by the Executive Secretary.

In accordance with the transition plan, MERC resumed disconnections on August 2, 2021.

MERC will not disconnect residential customers with past due balances if the customer has a pending application or has been deemed eligible for a financial assistance program.

In addition, MERC continues to offer flexible deferred payment arrangements to residential customers.

For customers who enter, or are complying with, a payment arrangement, MERC did not impose any service deposits, down payments, interest, late payment fees, or reconnections fees through April 30, 2022.

In April 2020, the MPSC issued a written order requiring Michigan utilities, including MGU and UMERC, to put certain minimum protections in place during the COVID-19 pandemic.

The minimum protections required by the order included the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers.

In addition, utilities were required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19.

As required in the MPSC order, MGU and UMERC filed responses with the MPSC in April 2020 affirming the actions being taken to protect customers.

These actions provided protections to more customers than required by the MPSC order, and included suspending disconnections for all residential customers, waiving deposit requirements for new service, suspending the assessment of late fees for customers that entered into payment plans, and enhancing payment plan options for all customers.

The April 2020 MPSC order also authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeded the amounts being recovered in rates.

MGU and UMERC did not record any deferrals related to the COVID-19 pandemic as they did not experience any significant COVID-19 related expenses.

In June 2021, MGU and UMERC worked with MPSC staff to develop a transition plan to resume collections and disconnections, while continuing to assist customers in managing their arrears balances.

In accordance with the agreed upon transition plan, MGU and UMERC resumed pre-pandemic collection activities and residential service disconnections on August 2, 2021.

Flexible deferred payment arrangements continue to be available to customers.

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

On December 20, 2023, the PSCW issued final written orders approving electric and natural gas rate increases and decreases, effective January 1, 2024.

The final orders reflected the following:

2024 incremental rate increases (decreases)

$ 82.2 million / 2.5 % $ ( 32.7 ) million / ( 2.6 )% N/A

Gas $ 23.9 million / 4.5 % N/A $ 21.6 million / 2.8 %

(1) Amounts reflect the impact to our Wisconsin retail electric operations and include any incremental increases (WE) or decreases (WPS) resulting from updated fuel costs.

The utilities' ROE and common equity component averages were not addressed in the limited rate case re-openers.

2023 and 2024 Rates

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and changes in wholesale business with other utilities.

Many of these investments have already been approved by the PSCW.

Many of these investments had already been approved by the PSCW.

The requested increases in natural gas rates primarily related to capital investments previously approved by the PSCW, including LNG storage for our natural gas distribution system.

2022 Form 10-K 149

WEC Energy Group, Inc.

In September 2022, WE, WPS, and WG entered into settlement agreements with certain intervenors to resolve most of the outstanding issues in each utility's respective rate case;

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In December 2022, the PSCW issued final written orders approving electric, natural gas, and steam base rate increases, effective January 1, 2023.

The final orders reflect the following:

The final orders reflected the following:

2023 base rate increase

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Common equity component average on a financial basis 53.0 % 53.0 % 53.0 %

In addition to the above, the final orders include the following terms:

In addition to the above, the final orders included the following terms:

• The utilities will keep their current earnings sharing mechanisms, under which, if a utility earns above its authorized ROE:

(i) the utility will retain 100.0 % of earnings for the first 15 basis points above the authorized ROE;

(ii) 50.0 % of the next 60 basis points will be required to be refunded to ratepayers;

and (iii) 100.0 % of any remaining excess earnings will be required to be refunded to ratepayers.

• WE and WPS are required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life.

(i) the utility retains 100.0 % of earnings for the first 15 basis points above the authorized ROE;

(ii) 50.0 % of the next 60 basis points is refunded to ratepayers;

and (iii) 100.0 % of any remaining excess earnings is required to be refunded to ratepayers.

• WE and WPS were required to complete an analysis of alternative recovery scenarios for generating units that will be retired prior to the end of their useful life.

• WE and WPS will not propose any changes to their real time pricing rates for large commercial and industrial electric customers through the end of 2024.

• WE and WPS will lower monthly residential and small commercial electric customer fixed charges by $ 1.00 and $ 3.33 , respectively, from currently authorized rates.

• WE and WPS will offer an additional voluntary renewable energy pilot for commercial and industrial customers.

• WE and WPS will work with PSCW staff and other interested parties to develop alternative low income assistance programs.

WE and WPS will also collectively contribute $ 4.0 million to the Keep Wisconsin Warm Fund.

• WE, WPS, and WG are required to implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024.

• WE and WPS are authorized to file a limited electric rate case re-opener for 2024 to address changes to revenue requirements associated with generation projects that are expected to be placed into service in 2023 and 2024 and future plant retirements.

WE and WG are also authorized to file a limited natural gas rate case re-opener for 2024 to address additional revenue requirements associated with LNG projects that are expected to be placed into service in 2023 and 2024, respectively.

• WE and WPS were required to lower monthly residential and small commercial electric customer fixed charges by $ 1.00 and $ 3.33 , respectively, from previously authorized rates.

• WE and WPS were required to offer an additional voluntary renewable energy pilot for commercial and industrial customers.

• WE and WPS will continue to work with PSCW staff and other interested parties to develop alternative low income assistance programs.

WE and WPS also collectively contributed $ 4.0 million to the Keep Wisconsin Warm Fund.

• WE, WPS, and WG were required to implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024.

• As discussed above, WE and WPS were authorized to file a limited electric rate case re-opener for 2024, and WE and WG were authorized to file a limited natural gas rate case re-opener for 2024.

2023 Form 10-K 152

WEC Energy Group, Inc.

In March 2021, WE, WPS, and WG filed an application with the PSCW for the approval of certain accounting treatments that allowed them to maintain their electric, natural gas, and steam base rates through 2022 and forego filing a rate case for one year .

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• WE, WPS, and WG maintained their earnings sharing mechanisms for 2022, with modification.

The earnings sharing mechanisms were modified to authorize the utility to retain 100.0 % of the first 15 basis points of earnings above its currently authorized ROE.

The earnings sharing mechanisms were modified to authorize the utility to retain 100.0 % of the first 15 basis points of earnings above its then authorized ROE.

The earnings sharing mechanisms otherwise remained as previously authorized.

2022 Form 10-K 150

WEC Energy Group, Inc.

2020 and 2021 Rates

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The rate orders for all three gas utilities reflected all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years .

For WE, approximately $ 5 million of previously deferred tax expense is being amortized each year.

For WPS and WG, approximately $ 5 million and $ 3 million, respectively, of previously deferred tax benefits are being amortized each year.

For WE, approximately $ 5 million of previously deferred tax expense was amortized each year.

For WPS and WG, approximately $ 5 million and $ 3 million, respectively, of previously deferred tax benefits was amortized each year.

Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.

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The financing order also authorized WE to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for the sole purpose of issuing ETBs to recover the approved costs.

In May 2021, WEPCo Environmental Trust issued $ 118.8 million of 1.578 % ETBs due December 15, 2035.

In May 2021, WEPCo Environmental Trust issued $ 118.8 million of

2023 Form 10-K 153

WEC Energy Group, Inc.

1.578 % ETBs due December 15, 2035.

See Note 23, Variable Interest Entities, for more information regarding WEPCo Environmental Trust.

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In addition, the rate orders also required WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.

2022 Form 10-K 151

WEC Energy Group, Inc.

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

2023 Rate Case

2023 Rate Order

On January 6, 2023, PGL and NSG filed requests with the ICC to increase their natural gas base rates.

They are requesting incremental rate increases of $ 194.7 million ( 13.0 %) and $ 18.7 million ( 7.8 %), respectively.

The requested rate increases are primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system.

PGL is also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service.

Both companies are requesting an ROE of 9.90 % and a common equity component average of 54.0 %.

PGL is not seeking an extension of the QIP rider.

Instead, PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements.

See the Qualifying Infrastructure Plant Rider section below for more information on the QIP rider.

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

The requested rate increases were primarily driven by capital investments made to strengthen the safety and reliability of each utility’s natural gas distribution system.

PGL was also seeking to recover costs incurred to upgrade its natural gas storage field and operations facilities and to continue improving customer service.

PGL did not request an extension of the QIP rider as PGL will return to the traditional rate making process to recover the costs of necessary infrastructure improvements.

On November 16, 2023, the ICC issued final written orders approving base rate increases for PGL and NSG.

The written orders were subsequently amended for various technical corrections.

The amended written orders approved the following base rate increases:

• A $ 304.6 million ( 43.5 %) base rate increase for PGL’s natural gas customers.

This amount includes the recovery of costs related to PGL’s SMP that were previously being recovered under its QIP rider.

PGL's new rates were effective December 1, 2023.

• An $ 11.0 million ( 11.6 %) base rate increase for NSG’s natural gas customers.

The new rates at NSG were not effective until February 1, 2024 as changes were required to NSG's billing system as a result of the final rate order.

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

As part of its decisions, the ICC, among other things, disallowed $ 236.2 million of capital costs related to the construction and improvement of PGL’s shops and facilities and $ 1.7 million of capital costs related to NSG's construction of a gas infrastructure project.

In addition, the ICC ordered PGL to pause spending on its SMP until the ICC has a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

In accordance with the written order, the ICC initiated the proceeding on January 31, 2024.

On December 15, 2023, PGL and NSG filed an application for rehearing with the ICC requesting reconsideration of various issues in the ICC's November 16, 2023 written orders.

On January 3, 2024, the ICC granted PGL and NSG a limited-scope rehearing.

The rehearing will be limited to:

• the authorized spending for the completion of SMP projects that started in 2023,

• the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system, and

• the timing of changes required to NSG's billing system.

As the ICC did not grant a rehearing on the disallowance of PGL's and NSG's capital costs, we recorded a $ 178.9 million non-cash impairment of our property, plant, and equipment in 2023.

This amount includes $ 177.2 million of previously incurred disallowed costs at PGL related to its shops and facilities, and the $ 1.7 million of capital costs disallowed at NSG.

The remaining disallowance of capital costs at PGL related to expected future spend.

We anticipate appealing the ICC’s disallowance of PGL's and NSG's capital costs to the Illinois circuit court after the rehearing process is complete.

2023 Form 10-K 154

WEC Energy Group, Inc.

An ICC decision on our limited-scope rehearing is expected in the second quarter of 2024.

Third-Party Transaction Fee Adjustment Rider

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In December 2021, the ICC approved the use of a TPTFA rider for PGL.

The TPTFA rider allows PGL to recover the costs incurred for these third-party transaction fees.

The TPTFA rider allowed PGL to recover the costs incurred for these third-party transaction fees prior to them being included in base rates.

PGL began recovering costs under the rider on February 1, 2022.

Amounts deferred under the rider will be recovered over a period of 12 months and will be subject to an annual reconciliation whereby costs will be reviewed by the ICC for accuracy and prudency.

NSG recovers costs related to these third-party transaction fees through its base rates, effective September 15, 2021.

Amounts deferred under the rider were being recovered over a period of 12 months and are subject to an annual reconciliation whereby costs are reviewed by the ICC for accuracy and prudency.

Effective December 1, 2023, PGL discontinued its use of the TPTFA rider and began recovering costs related to these third-party transaction fees through its base rates.

NSG began recovering these costs through its base rates, effective September 15, 2021.

North Shore Gas Company 2021 Rate Order

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In September 2021, the ICC issued a written order authorizing a rate increase of $ 4.1 million ( 4.5 %).

The rate increase reflects a 9.67 % ROE and a common equity component average of 51.58 %.

The rate increase reflected a 9.67 % ROE and a common equity component average of 51.58 %.

The natural gas rate increase was primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 28, 2015.

3 unchanged sentences

This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure.

In January 2014, the ICC approved a QIP rider for PGL, which is in effect through 2023.

PGL will not seek an extension of the rider beyond 2023.

PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency.

In March 2022, PGL filed its 2021 reconciliation with the ICC, which, along with the 2020, 2019, 2018, 2017, and 2016 reconciliations, are still pending.

In addition, costs incurred during 2022 under the QIP rider are also still subject to reconciliation and review.

In January 2014, the ICC approved a QIP rider for PGL, which was in effect until December 1, 2023.

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

Costs previously incurred under PGL's QIP rider are still subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency.

In March 2023, PGL filed its 2022 reconciliation with the ICC, which, along with the reconciliations from 2016 through 2021, are still pending.

Annual costs included in the rider have ranged from $ 192 million to $ 348 million.

As of December 31, 2023, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC.

2022 Form 10-K 152

WEC Energy Group, Inc.

Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Minnesota Energy Resources Corporation

2023 Rate Case

On November 1, 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates by $ 40.3 million ( 9.9 %).

MERC's request reflects a 10.3 % ROE and a common equity component average of 53.0 %.

The proposed retail natural gas rate increase is primarily driven by increased capital investments as well as inflationary pressure on operating costs.

2023 Rate Order

In November 2022, MERC initiated a rate proceeding with the MPUC to increase its retail natural gas base rates.

In December 2022, the MPUC approved MERC's request for interim rates totaling $ 37.0 million, subject to refund.

The interim rates went into effect on January 1, 2023.

On November 14, 2023, the MPUC issued a written order approving a settlement agreement MERC reached with certain intervenors.

The settlement agreement reflects a natural gas base rate increase of $ 28.8 million ( 7.1 %), along with a 9.65 % ROE and a common equity component average of 53.0 %.

The natural gas rate increase was primarily driven by increased capital investments as well as inflationary pressure on operating costs.

Under the terms of the settlement agreement, MERC will continue the use of its decoupling mechanism for residential customers, and it will be expanded to include certain small commercial and industrial customers.

Final rates will be effective March 1, 2024.

MERC’s customers are entitled to a refund to the extent the interim rate increase exceeded the final approved rate increase.

As of December 31, 2023, MERC had recorded a regulatory liability of $ 8.5 million for refunds due to customers.

These amounts will be refunded to customers during the second quarter of 2024.

2023 Form 10-K 155

WEC Energy Group, Inc.

Michigan Gas Utilities Corporation

2024 Rate Application

On December 28, 2023, MGU provided notification to the MPSC of its intent to file an application requesting an increase to its natural gas rates.

The application is expected to be filed in March 2024 and to request new rates be effective January 1, 2025.

MGU is currently in the process of evaluating its rate request.

2023 Rate Order

In March 2023, MGU filed a request with the MPSC to increase its retail natural gas base rates.

In August 2023, the MPSC issued a written order approving a comprehensive settlement that resolved all issues in MGU's rate case.

The key terms of the settlement agreement include:

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

• an ROE of 9.8 %;

• a common equity component average of 51.0 %;

• a continuation of the existing MRP rider, effective January 1, 2025 through 2027, including forecasted increased costs for those projects.

MRP costs are being recovered in base rates in 2024.

The rate increase was primarily driven by capital investments made to strengthen the safety and reliability of MGU's natural gas distribution system and to provide service to additional customers.

Inflationary pressure on operating costs also contributed to the rate increase.

The new rates were effective January 1, 2024.

2021 Rate Order

In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021.

However, MGU decided that it would delay its filing of the rate case as a result of the COVID-19 pandemic.

However, MGU decided that it would delay its filing of the rate case as a result of the Coronavirus Disease – 2019 pandemic.

In May 2020, MGU filed an application with the MPSC requesting approval to defer $ 5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case.

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In March 2021, MGU filed its request with the MPSC to increase its natural gas rates.

In July 2021, MGU filed with the MPSC, a settlement agreement it reached with certain intervenors, which the MPSC approved in a written order in September 2021.

The order authorizes a rate increase of $ 9.3 million ( 6.35 %) and reflects a 9.85 % ROE and a common equity component average of 51.5 %.

The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its last rate review that resulted in revised base rates effective January 1, 2016.

The order also allows MGU to implement a rider for its Main Replacement Program that will support recovery of planned capital investment related to pipeline replacements to maintain system safety and reliability between 2023 and 2027, without having to file a rate case.

We expect approximately $ 31.7 million of costs to be recovered through this rider.

In September 2021, the MPSC issued a written order approving a settlement agreement MGU reached with certain intervenors.

The order authorized a rate increase of $ 9.3 million ( 6.35 %) and reflected a 9.85 % ROE and a common equity component average of 51.5 %.

The natural gas rate increase was primarily driven by MGU's significant investment in capital infrastructure since its previous rate review that resulted in revised base rates effective January 1, 2016.

The order also allowed MGU to implement a rider for its MRP, which supports recovery of planned capital investment related to pipeline replacements to maintain system safety and reliability between 2023 and 2027, without having to file a rate case.

All costs recovered through the rider are subject to a prudence review by the MPSC.

The new rates became effective January 1, 2022.

The new rates were effective January 1, 2022.

Upper Michigan Energy Resources Corporation

2024 Rate Application

On December 28, 2023, UMERC provided notification to the MPSC of its intent to file an application requesting an increase to its electric rates.

The application is expected to be filed in March 2024 and to request new rates be effective January 1, 2025.

UMERC is currently in the process of evaluating its rate request.

2023 Form 10-K 156

WEC Energy Group, Inc.

Recovery of Natural Gas Costs

All of our utilities have regulatory mechanisms in place for recovering all prudently incurred natural gas costs.

In March 2021, WPS also filed its revised natural gas rate sheets with the PSCW reflecting approximately $ 28 million of natural gas costs in excess of the benchmark set in its GCRM.

WPS also recovered these excess costs over a period of three months , beginning in April 2021.

PGL and NSG incurred approximately $ 131 million and $ 10 million, respectively, of natural gas costs in February 2021 in excess of the amounts included in their rates.

These costs were recovered over a period of 12 months, which started on April 1, 2021.

PGL's and NSG's natural gas costs were reviewed for prudency by the ICC as part of their annual natural gas cost reconciliation.

In January 2023, the ICC issued written orders approving each company's 2021 reconciliation.

In February 2021, MERC incurred approximately $ 75 million of natural gas costs in excess of the benchmark set in its GCRM.

In August 2021, the MPUC issued a written order approving a joint proposal filed by MERC and four other Minnesota utilities to recover their respective excess natural gas costs.

Recovery of these costs and the issue of prudence was referred to a contested-case proceeding.

Under the settlement agreement, MERC agreed to not seek recovery of $ 3 million of these costs.

MERC substantially recovered the remaining $ 62 million of extraordinary natural gas costs over the previously approved 27 -month recovery period.

Natural gas costs incurred at MGU and UMERC in excess of the amount included in their respective rates were not significant.

NOTE 27— OTHER INCOME, NET

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AFUDC-Equity 59.1 29.4 18.0

Earnings from equity method investments (1)

Gains (losses) from investments held in rabbi trust 13.7 ( 12.6 ) 18.6

Earnings (losses) from equity method investments (1)

( 1.1 ) 9.3 19.9

Other, net 8.3 ( 1.7 ) 4.5

Other income, net $ 177.7 $ 128.8 $ 133.2

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

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

NOTE 28— NEW ACCOUNTING PRONOUNCEMENTS

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No.

2023-09, Income Taxes (Topic 740):

Improvements to Income Tax Disclosures.

The amendments require additional disclosures, primarily related to income taxes paid and the rate reconciliation table.

The amendments require disclosures on specific categories in the rate reconciliation table, as well as additional information for reconciling items that meet a quantitative threshold.

For income taxes paid, additional disclosures are required to disaggregate federal, state, and foreign income taxes paid, with additional disclosures for income taxes paid that meet a quantitative threshold.

The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted.

2023 Form 10-K 157

WEC Energy Group, Inc.

adopt these amendments beginning with our fiscal year ending on December 31, 2025, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued ASU No.

2023-07, Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures.

The amendments require additional disclosures about reportable segments on an annual and interim basis.

The amendments require disclosure of significant segment expenses that are (1) regularly provided to the chief operating decision maker and (2) included in the reported measure of segment profit or loss.

The amendments also require disclosure of an amount for other segment items and a description of its composition.

The new standard also allows companies to disclose multiple measures of segment profit or loss if those measures are used to assess performance and allocate resources.

The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted.

We plan to adopt these amendments beginning with our fiscal year ending on December 31, 2024, and are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Reference Rate Reform

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2020-04, Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to provide relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met.

The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform.

Under ASU No.

2020-04, this relief was effective for all entities beginning March 12,

2022 Form 10-K 153

WEC Energy Group, Inc.

2020 through December 31, 2022.

Facilitation of the Effects of Reference Rate Reform on Financial Reporting and in January 2021, the FASB issued ASU No.

2021-01, Reference Rate Reform (Topic 848):

These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the market transition from LIBOR and other interbank offered rates to alternative reference rates.

These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022.

In December 2022, the FASB issued ASU No.

2022-06, Reference Rate Reform (Topic 848):

Deferral of the Sunset Date of Topic 848, which extends the relief for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform to December 31, 2024.

We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.

Government Assistance

In November 2021, the FASB issued ASU No.

2021-10, Government Assistance (Topic 832).

The amendments in this update increase the transparency surrounding government assistance by requiring disclosure of:

(i) the types of assistance received;

(ii) an entity’s accounting for the assistance;

and (iii) the effect of the assistance on the entity’s financial statements.

The update was effective for annual periods beginning after December 15, 2021.

The adoption of ASU No.

2021-10, effective for our fiscal year ending on December 31, 2022, did not have a significant impact on our financial statements and related disclosures.

Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848.

An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2024 by accounting topic.

Our $ 500.0 million 2007 Junior Notes, which were previously subject to a variable rate based on U.S.

dollar LIBOR, became subject to a variable rate based on SOFR beginning July 1, 2023.

No contract modifications were required as the references to LIBOR were replaced by operation of law.

See Note 14, Long-Term Debt, for more information.

We do not anticipate this guidance having a significant impact on our financial statements and related disclosures.

2023 Form 10-K 158

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data