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Item 7. Management’s Discussion and Analysis

2025-02-21 compared with 2024-02-22 · 723 added, 422 removed, 829 unchanged (58% of the section changed)

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exceptional customer care;

Our capital investment plan for efficiency, sustainability and growth, referred to as our ESG Progress Plan, provides a roadmap for us to achieve this goal.

Our capital plan provides a roadmap for us to achieve this goal.

It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow our investment in the future of energy.

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Creating a Sustainable Future

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

The retirements will contribute to meeting our goals to reduce CO 2 emissions from our electric generation.

When taken together, the retirements and new investments in renewables and clean generation should better balance our supply with our demand, while maintaining reliable, affordable energy for our customers.

Our capital plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and reliable, efficient natural gas-fired generation.

The retirements are intended to address compliance with the EPA Clean Air rules as well as contribute to meeting our goals to reduce CO 2 emissions from our electric generation.

When taken together, the retirements and new investments in renewables and reliable, efficient natural gas generation should better balance our supply with our demand, while helping to address compliance and maintaining reliable, affordable energy for our customers.

We have 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.

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

As part of our path toward these goals, we have started implementing co-firing with natural gas at the ERGS coal-fired units.

By the end of 2030, we expect to use coal as a backup fuel only, and we believe we will be in a position to eliminate coal as an energy source by the end of 2032.

We already have retired more than 1,900 MWs of fossil-fueled generation since the beginning of 2018, which included the 2019 retirement of the PIPP as well as the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating units.

See Note 6, Regulatory Assets and Liabilities, for more information related to these power plant retirements.

We expect to retire approximately 1,800 MWs of additional fossil-fueled generation by the end of 2031, which includes the planned retirement 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.

As part of our path toward these goals, we have started implementing co-firing with natural gas at the ERGS coal-fired units and plan to co-fire with natural gas at Weston Unit 4.

By the end of 2030, we expect to use coal as a backup fuel only and to be in a position to eliminate coal as an energy source by the end of 2032.

We have already retired nearly 2,500 MWs of fossil-fueled generation since the beginning of 2018, which includes the retirement of OCPP Units 5 and 6 in May 2024, the 2019 retirement of the PIPP, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Unit 4 generating unit.

We expect to retire approximately 1,200 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8, the jointly-owned Columbia Units 1 and 2, and Weston Unit 3.

For more information on the retirement of OCPP Units 5 and 6, see Note 6, Regulatory Assets and Liabilities.

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

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We also plan on investing in a combination of clean, natural gas-fired generation, including:

• 1,125 MWs of combustion turbines;

• 132 MWs of RICE natural gas-fueled generation;

• the purchase of 100 MWs of additional capacity in West Riverside.

For more details, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

• 1,100 MWs of combustion turbines to be constructed at our OCPP site (we plan on constructing a new natural gas lateral pipeline to support this generation);

• An additional 675 MWs of combustion turbines planned;

• 128 MWs of RICE natural gas-fueled generation to be constructed in Kenosha County;

• An additional 114 MWs of RICE natural gas-fueled generation planned.

In May 2024, WE completed the acquisition of an additional 100 MWs of West Riverside's nameplate capacity, a commercially operational dual fueled combined cycle generation facility in Beloit, Wisconsin operated by an unaffiliated utility.

See Note 2, Acquisitions, for more information.

For more details on the projects discussed above, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

In December 2018, WE received approval from the PSCW for two renewable energy pilot programs.

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This program allows WE and WPS commercial and industrial customers to subscribe to a portion of a utility-scale, Wisconsin-based renewable energy generating facility for up to 125 MWs at WE and 40 MWs at WPS.

Under this program, WE has signed up seven customers for a total of 59 MWs of generation capacity.

In August 2021, the PSCW approved pilot programs for WE and WPS to install and maintain EV charging equipment for customers at their homes or businesses.

We proposed modifications to these pilot programs, which were approved by the PSCW and implemented on January 1, 2025.

The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment.

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The coalition we joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.

We also continue to reduce methane emissions by improving our natural gas distribution system.

We also continue to focus on methane emission reductions by improving our natural gas distribution system.

We 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 natural gas utility systems.

In 2022, we received approval from the PSCW for our RNG pilots.

We have since signed contracts for RNG for our natural gas distribution business in Wisconsin, which will be transporting the output of local dairy farms onto our gas distribution systems.

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

In 2022, we received approval from the PSCW for our RNG pilots and in 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin.

The RNG supplied will directly replace higher-emission methane from natural gas that would have entered our pipes.

These contracts bring us to 1.8 Bcf of RNG planned to enter our systems.

RNG began flowing in 2023.

In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer, to test a new form of long-duration energy storage on the U.S.

electric grid.

We currently have contracts in place for 2.1 Bcf of RNG.

In addition, subject to regulatory approval and market conditions, we expect to procure RTCs.

In December 2023, we started a pilot program with Electric Power Research Institute and CMBlu Energy, a Germany-based designer and manufacturer of an organic solid flow battery, to test this new form of long-duration energy storage on the U.S.

electric grid at our VAPP.

The program will test battery system performance, including the ability to store and discharge energy for up to twice as long as the typical lithium-ion batteries in use today.

We expect the full pilot to be completed in 2024.

We have made significant reliability-related investments in recent years, and in accordance with our ESG Progress Plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.

Below are a few examples of reliability projects that are proposed, currently underway, or recently completed.

• Included in the capital plan are additional proposed LNG storage facilities providing approximately four Bcf of natural gas supply, which is needed to ensure gas supply for winter reliability.

• WE and WG have received approval to each construct their own LNG facility to meet anticipated peak demand.

Each facility would provide approximately one Bcf of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity.

The WE LNG facility was commercially operational at the end of 2023 and the WG LNG facility is targeted for 2024.

• Through the SMP, PGL had been working to replace old iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.

In November 2023, the ICC ordered

We expect the pilot activities to continue into 2025.

We have made significant reliability-related investments in recent years, and in accordance with our capital plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.

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PGL to pause spending on the SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months.

For more information, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Future Illinois Proceedings.

On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which is limited to the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system.

As a result, PGL has suspended neighborhood work, pending the results of the limited rehearing.

See Note 26, Regulatory Environment, for more information.

Below are a few examples of reliability projects that are proposed, currently underway, or recently completed.

• WE and WG have completed the construction of their respective LNG facilities.

Each facility provides approximately one Bcf of natural gas supply to meet anticipated peak demand, without requiring the construction of additional interstate pipeline capacity.

The WE LNG facility was commercially operational in November 2023 and the WG LNG facility was commercially operational in February 2024.

• In April 2024, WE filed a request with the PSCW to construct an LNG facility with a storage capacity of two Bcf, which would be located on the OCPP site.

In addition, the construction of additional LNG facilities in Wisconsin has been proposed as part of the 2025-2029 capital plan and would provide another approximately four Bcf of natural gas supply.

The LNG facilities are expected to reduce the likelihood of constraints on our natural gas distribution system during the highest demand days of winter.

In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC completed a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

The ICC granted PGL a limited-scope rehearing related to authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of PGL's delivery system.

On May 30, 2024, the ICC issued a written order on the rehearing, approving $28.5 million of additional spending for emergency work, which represents a $1.6 million increase to PGL's annual revenue requirement.

On February 20, 2025, the ICC issued an order setting expectations for PGL's prospective operations under its SMP.

For more information, see Note 26, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Future Illinois Proceedings.

• Our utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability and storm hardening.

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Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under the ESG Progress Plan.

We continually look for ways to optimize the operating efficiency of our company and will continue to do so under our capital plan.

For example, we are making progress on our AMI program, replacing aging meter-reading equipment on both our network and customer property.

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We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.

See Note 3, Dispositions, for information on recent transactions.

Our planned investment focus from 2024 to 2028 is in our regulated utilities and non-utility energy infrastructure business, as well as our investment in ATC.

Our planned investment focus from 2025 to 2029 is in our regulated utilities and our investment in ATC.

We expect total capital expenditures for our regulated utility businesses to be approximately $24.4 billion from 2025 to 2029.

In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $3.2 billion.

We expect to invest approximately $1.2 billion in our non-utility energy infrastructure business over the same period, which includes our previously announced investment in Maple Flats and the purchase of an additional 10% ownership interest in Samson I.

Specific projects included in the $23.7 billion ESG Progress Plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Also, see Note 2, Acquisitions, for information on recent and pending transactions.

In February 2025, we invested approximately $405.9 million in our non-utility energy infrastructure business with the acquisition of Hardin III.

Specific projects included in the $28.0 billion capital plan are discussed in more detail below under Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

Also, see Note 2, Acquisitions, for additional information on the acquisition of Hardin III and other recent and pending transactions.

See Note 3, Disposition, for more information on the disposal of real estate.

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Exceptional Customer Care

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Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service to customers.

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Safety is one of our core values and a critical component of our culture.

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RESULTS OF OPERATIONS

The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2023 with the year ended December 31, 2022.

For a similar discussion that compares our results for the year ended December 31, 2022 with the year ended December 31, 2021, see Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations in Part II of our 2022 Annual Report on Form 10-K, which was filed with the SEC on February 23, 2023.

The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2024 with the year ended December 31, 2023, and for the year ended December 31, 2023 with the year ended December 31, 2022.

Consolidated Earnings

The following table compares our consolidated results for the year ended December 31, 2023 with the year ended December 31, 2022, including favorable or better, "B," and unfavorable or worse, "W," variances:

The following table compares our consolidated results, including favorable or better, "B," and unfavorable or worse, "W," variances:

Year Ended December 31

(in millions, except per share data) 2023 2022 B (W)

(in millions, except per share data) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Wisconsin $ 863.1 $ 851.3 $ 758.4 $ 11.8 $ 92.9

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$ 4.83 $ 4.22 $ 4.45 $ 0.61 $ (0.23)

2024 Compared with 2023

Earnings increased $195.5 million during 2024, compared with 2023.

The significant factors impacting the $195.5 million increase in earnings were:

• A $112.1 million increase in net income attributed to common shareholders at the Illinois segment, primarily due to a $178.9 million impairment recorded in 2023 associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG.

An increase in margins related to the impacts of the November 2023 rate orders,

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effective December 1, 2023 for PGL, and February 1, 2024 for NSG, also contributed to the higher net income.

SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates.

Partially offsetting these increases were higher property and revenue taxes, depreciation and amortization, and natural gas distribution and maintenance costs, along with a $25.3 million pre-tax charge to income related to the ICC's disallowance of certain capital costs in PGL's 2016 rider QIP reconciliation.

See Note 26, Regulatory Environment, for more information on the PGL and NSG rate orders and the ICC's disallowance.

• A $44.8 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by higher operating income at WECI and an increase in PTCs from our non-utility renewable generating facilities in 2024.

• A $21.9 million increase in net income attributed to common shareholders at the electric transmission segment, driven by higher equity earnings from ATC primarily due to the positive impact of a FERC order issued in October 2024 addressing complaints related to ATC's ROE.

For information on this FERC order, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

Continued capital investment by ATC also contributed to the year-over-year increase in equity earnings.

• An $11.8 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in margins due to the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024, and a positive impact from collections of fuel and purchased power costs.

These increases were partially offset by higher operating expenses, primarily driven by higher depreciation and amortization.

See Note 26, Regulatory Environment, for more information on the limited rate case re-openers.

2023 Compared with 2022

Earnings decreased $76.4 million during 2023, compared with 2022.

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See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

• An $86.9 million decrease in net income attributed to common shareholders at the Illinois segment, driven by higher operating expenses, primarily due to an impairment associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG, and the year-over-year impact of a gain recorded in 2022 on the sale of certain real estate by PGL.

• An $86.9 million decrease in net income attributed to common shareholders at the Illinois segment, driven by higher operating expenses, primarily due to a $178.9 million pre-tax impairment associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG, and the year-over-year impact of a gain recorded in 2022 on the sale of certain real estate by PGL.

Partially offsetting these increases in operating expenses were lower natural gas distribution and maintenance costs and a decrease in expenses related to charitable contributions.

Higher natural gas margins, due to a positive impact from PGL's rate order, effective December 1, 2023, and continued capital investment in the SMP project in 2023 under PGL's QIP rider, also

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partially offset the net increase in operating expenses.

See Note 26, Regulatory Environment, for more information on the PGL and NSG rate orders.

Higher margins, due to a positive impact from PGL's rate order, effective December 1, 2023, and continued capital investment in the SMP project in 2023 under PGL's former QIP rider, also partially offset the net increase in operating expenses.

• A $10.4 million decrease in net income attributed to common shareholders at the electric transmission segment, driven by the positive impact in 2022 related to the D.C.

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For information on this D.C.

Circuit Court of Appeals opinion, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints.

These decreases in earnings were partially offset by:

• A $92.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive year-over-year impact from collections of fuel and purchased power costs.

These positive impacts were partially offset by a decrease in electric and natural gas margins due to lower sales volumes, and higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, and regulatory amortizations.

• A $92.9 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by an increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive year-over-year impact from collections of fuel and purchased power costs.

These positive impacts were partially offset by a decrease in margins due to lower sales volumes, and higher operating expenses, including increases in expenses related to transmission, depreciation and amortization, and regulatory amortizations.

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• An $11.6 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, primarily due to an increase in PTCs driven by the acquisition of additional renewable generation facilities in the second half of 2022 and the first quarter of 2023, partially offset by higher interest expense.

• An $8.4 million increase in net income attributed to common shareholders at the other states segment, driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023.

• An $8.4 million increase in net income attributed to common shareholders at the other states segment, driven by higher margins due to an interim rate increase at MERC, effective January 1, 2023.

See Note 26, Regulatory Environment, for more information.

This positive impact was partially offset by a decrease in natural gas margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

This positive impact was partially offset by a decrease in margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

Non-GAAP Financial Measures

The discussions below address the contribution of each of our segments to net income attributed to common shareholders.

The discussions include financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP.

Electric margins (electric revenues less fuel and purchased power costs) and natural gas margins (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates.

As a result, management uses electric and natural gas margins internally when assessing the operating performance of our segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses.

Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies.

Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

The following table shows operating income by segment for our utility operations during years ended December 31, 2023 and 2022:

Year Ended December 31

(in millions) 2023 2022

Wisconsin $ 1,553.3 $ 1,463.1

Illinois 270.8 369.7

Other states 79.7 64.2

Each applicable segment discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to the most directly comparable GAAP measure, operating income.

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders.

The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP.

Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

We believe that utility margin provides a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates.

As a result, management uses utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses.

Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Our utility margin may not be comparable to similar measures presented by other companies.

Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance.

Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 2024 was $863.1 million, representing an $11.8 million, or 1.4%, increase over the prior year.

The higher earnings were driven by an increase in margins due to the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024, and a positive impact from collections of fuel and purchased power costs.

These increases were partially offset by higher operating expenses, primarily driven by higher depreciation and amortization.

See Note 26, Regulatory Environment, for more information on the limited rate case re-openers.

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Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 2023 was $851.3 million, representing a $92.9 million, or 12.2%, increase over the prior year.

The higher earnings were driven by an increase in electric and natural gas margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive year-over-year impact from collections of fuel and purchased power costs.

The higher earnings were driven by an increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023, and a positive year-over-year impact from collections of fuel and purchased power costs.

Year Ended December 31

(in millions) 2023 2022 B (W)

Electric revenues $ 5,010.8 $ 4,971.8 $ 39.0

Fuel and purchased power 1,615.9 1,881.4 265.5

Total electric margins 3,394.9 3,090.4 304.5

Natural gas revenues 1,615.1 1,988.7 (373.6)

Cost of natural gas sold 894.7 1,327.4 432.7

Total natural gas margins 720.4 661.3 59.1

Total electric and natural gas margins 4,115.3 3,751.7 363.6

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating revenues $ 6,330.5 $ 6,625.9 $ 6,960.5 $ (295.4) $ (334.6)

Operating expenses

Cost of sales (1)

2,117.6 2,510.6 3,208.8 393.0 698.2

Other operation and maintenance 1,547.9 1,531.3 1,351.3 (16.6) (180.0)

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Net income attributed to common shareholders $ 863.1 $ 851.3 $ 758.4 $ 11.8 $ 92.9

(1) Cost of sales includes fuel and purchased power and cost of natural gas sold.

The following table shows a breakdown of other operation and maintenance:

Year Ended December 31

(in millions) 2023 2022 B (W)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operation and maintenance not included in line items below $ 659.6 $ 635.1 $ 655.8 $ (24.5) $ 20.7

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As a result, 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 2023 and 2022, $520.4 million and $516.7 million, respectively, of costs were billed to our electric utilities by transmission providers.

During 2024, 2023, and 2022, $565.3 million, $520.4 million, and $516.7 million, respectively, of costs were billed to our electric utilities by transmission providers.

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

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(2) Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs, as well as certain costs associated

Effective January 1, 2023, the PSCW approved escrow accounting for pension and OPEB costs, as well as certain costs associated with our jointly-owned Columbia plant.

As a result, our Wisconsin utilities defer as a regulatory asset or liability, the difference between these actual costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

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with our jointly-owned Columbia plant.

(3) Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE.

During 2023 and 2022, $124.5 million and $121.7 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

During 2024, 2023, and 2022, $115.8 million, $124.5 million, and $121.7 million, respectively, of costs were billed to or incurred by WE related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(4) Represents operation and maintenance associated with the earnings mechanisms we have in place.

In 2022, this amount was reduced by the $21.6 million amortization of certain regulatory liability balances associated with WPS's 2020 earnings sharing mechanism to offset certain 2022 revenue deficiencies, as approved by the PSCW in order to forego filing for 2022 base rate increases.

In 2024, earnings sharing was reduced by the impact of the deferral of amounts collected in rates related to Badger Hollow II prior to its in-service date, which was delayed, as approved by the PSCW in the Wisconsin limited rate case reopener effective January 1, 2024.

Additionally, in 2022, earnings sharing was reduced by amortization related to certain regulatory liability balances associated with WPS's 2020 earnings sharing mechanism 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.

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Electric Sales Volumes (MWh - in thousands)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

Customer class

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Natural Gas Sales Volumes (Therms - in millions)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

Customer class

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Weather (Degree Days)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

WE and WG (1)

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(2) Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station.

(3) Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.

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(3) Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP).

See "Non-GAAP Financial Measures" above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

Year Ended December 31

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Electric revenues $ 4,921.6 $ 5,010.8 $ 4,971.8 $ (89.2) $ 39.0

Electric revenues increased $39.0 million during 2023, compared with 2022.

To the extent that changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in revenues.

See the discussion of electric utility margins below for more information related to the recovery of fuel and purchased power costs and the remaining drivers of the changes in electric revenues.

Electric Utility Margins

Electric utility margins at the Wisconsin segment increased $304.5 million during 2023, compared with 2022.

The significant factors impacting the higher electric utility margins were:

Natural gas revenues 1,408.9 1,615.1 1,988.7 (206.2) (373.6)

Operating revenues 6,330.5 6,625.9 6,960.5 (295.4) (334.6)

Operating expenses

Fuel and purchased power (1,455.7) (1,615.9) (1,881.4) 160.2 265.5

Cost of natural gas sold (661.9) (894.7) (1,327.4) 232.8 432.7

Other operation and maintenance (1)

(1,095.1) (1,133.8) (978.2) 38.7 (155.6)

Depreciation and amortization (919.9) (851.5) (754.7) (68.4) (96.8)

Property and revenue taxes (169.6) (179.2) (182.6) 9.6 3.4

Gross margin (GAAP) 2,028.3 1,950.8 1,836.2 77.5 114.6

Other operation and maintenance (1)

1,095.1 1,133.8 978.2 (38.7) 155.6

Depreciation and amortization 919.9 851.5 754.7 68.4 96.8

Property and revenue taxes 169.6 179.2 182.6 (9.6) (3.4)

Utility margin (non-GAAP) $ 4,212.9 $ 4,115.3 $ 3,751.7 $ 97.6 $ 363.6

(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units;

costs associated with the We Power generating units;

and transmission, distribution and customer service expenses.

These expenses are included in the above table to calculate gross margin as defined under GAAP.

2024 Compared with 2023

Gross margin (GAAP) at the Wisconsin segment increased $77.5 million during 2024, compared to 2023 and utility margin (non-GAAP) increased $97.6 million during 2024, compared to 2023.

Both measures were driven by:

• A $48.7 million increase in margins related to the impact of the Wisconsin limited rate case re-openers approved by the PSCW, effective January 1, 2024.

• A $38.5 million year-over-year positive impact from collections of fuel and purchased power costs.

Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under- or over-collections of certain fuel and purchased power costs that are within a 2% price variance from the costs included in rates, and the remaining variance above or below the 2% is generally deferred for future recovery or refund to customers.

• A $9.1 million increase in revenues primarily related to third-party use of our assets.

These increases in margins were partially offset by a $3.6 million decrease in margins related to lower retail sales volumes, driven by the impact of warmer winter weather during 2024, compared with 2023.

As measured by heating degree days, 2024 was 4.0% and 8.1% warmer than 2023 in the Milwaukee area and Green Bay area, respectively.

Additionally, the smaller increase in gross margin (GAAP) as compared with the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

• A $68.4 million increase in depreciation and amortization;

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• A $10.5 million increase in electric and natural gas distribution expenses.

These increases were partially offset by:

• A $34.9 million decrease in other operation and maintenance related to our power plants;

• A $10.0 million decrease in other operation and maintenance expense related to the We Power leases;

• A $10.0 million decrease in expense related to the settlement of certain items in our rate orders;

• A $9.6 million decrease in property and revenue taxes.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Wisconsin segment increased $75.4 million during 2024, compared with 2023.

The significant factors impacting the increase in other operating expenses were:

• A $68.4 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $24.9 million increase in benefit costs, primarily driven by higher stock-based compensation expense.

• A $22.1 million decrease in pre-tax gains on the sales of land, primarily related to the land sale at the site of our former Pleasant Prairie power plant in 2023.

See Note 3, Dispositions, for more information.

• A $10.9 million increase in expenses associated with legal matters.

• A $10.5 million increase in electric and natural gas distribution expenses, primarily driven by storm restoration and higher costs to maintain the distribution systems.

• A $7.7 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

These increases in other operating expenses were partially offset by:

• A $34.9 million decrease in other operating and maintenance related to our power plants, driven by the resolution of certain items as a result of the December 2024 Wisconsin rate orders approved by the PSCW, as well as lower severance expense during 2024.

• A $10.0 million decrease in other operation and maintenance expense related to the We Power leases, as discussed in the notes under the other operation and maintenance table above.

• A $10.0 million decrease in expense, driven by the resolution of certain items as a result of the December 2024 Wisconsin rate order approved by the PSCW, as well as the October 2024 UMERC rate order approved by the MPSC.

• A $9.9 million decrease in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above.

See Note 26, Regulatory Environment, for more information.

• A $9.6 million decrease in property and revenue taxes driven by a favorable adjustment related to a sales tax audit at WE.

Other Income, Net

Other income, net at the Wisconsin segment increased $9.0 million during 2024, compared with 2023, driven by higher interest income primarily due to interest earned on amounts due from ATC for the construction of transmission infrastructure upgrades needed for new generation projects.

We are required to initially fund these expenditures, and ATC reimburses us when the new

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generation is placed in service.

See Note 21, Investment in Transmission Affiliates, for more information.

Higher interest income on cash balances also contributed to the increase.

Interest Expense

Interest expense at the Wisconsin segment increased $36.3 million during 2024, compared with 2023.

The increase was primarily due to the impact of WE issuing long-term debt in 2024.

See Note 14, Long-Term Debt, for more information.

Also contributing to the increase were higher average short-term debt balances and higher average short-term debt interest rates.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $16.9 million during 2024, compared with 2023.

The decrease was primarily due to a $10.2 million increase in PTCs and lower pre-tax income.

See Note 16, Income Taxes, for more information.

2023 Compared with 2022

Gross margin (GAAP) at the Wisconsin segment increased $114.6 million during 2023, compared to 2022 and utility margin (non-GAAP) increased $363.6 million during 2023, compared to 2022.

Both measures were driven by:

• A $447.1 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023.

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In 2022, WPS was unable to defer a portion of its under-collected fuel and purchased power costs due to earning an ROE in excess of the PSCW authorized amount.

• A $15.7 million increase in margins during 2023, related to the expiration of a capacity purchase contract driven by the acquisition of the Whitewater facility, effective January 1, 2023.

• A $15.7 million increase in margins during 2023, related to the expiration of a capacity purchase contract in connection with the acquisition of the Whitewater facility, effective January 1, 2023.

These increases in margins were partially offset by:

• A $67.9 million decrease in margins related to lower retail electric sales volumes, including steam operations, driven by the impact of unfavorable weather during 2023, compared with 2022.

• A $125.3 million decrease in margins related to lower retail sales volumes, driven by the impact of unfavorable weather during 2023, compared with 2022.

As measured by cooling degree days, 2023 was 7.2% and 17.0% cooler than 2022 in the Milwaukee area and Green Bay area, respectively.

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• Lower margins of $8.0 million driven by the expiration of a wholesale contract in May 2022.

Natural Gas Revenues

Natural gas revenues decreased $373.6 million during 2023, compared with 2022.

Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues.

The average per-unit cost of natural gas decreased approximately 25% during 2023, compared with 2022.

The remaining drivers of changes in natural gas revenues are described in the discussion of natural gas utility margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Wisconsin segment increased $59.1 million during 2023, compared with 2022.

The most significant factor impacting the higher natural gas utility margins was a $116.6 million increase in margins related to the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2023.

This increase in margins was partially offset by a $57.4 million decrease in margins from lower sales volumes, driven by the impact of unfavorable weather during 2023, compared with 2022.

Additionally, the smaller increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

• A $109.5 million increase in transmission expense;

• A $96.8 million increase in depreciation and amortization;

• A $33.3 million increase in other operation and maintenance expense related to the We Power leases;

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• A $29.4 million increase in other operation and maintenance related to our power plants;

partially offset by

• A $15.6 million decrease in electric and natural gas distribution expenses.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

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See the notes under the other operation and maintenance table above for more information.

This amount is net of a deferral of $11.9 million approved by the PSCW in June 2023, retroactive to December 1, 2022, in response to a FERC order eliminating reactive power compensation to our utilities, as discussed in electric margins above.

• A $96.8 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

2 unchanged sentences

• A $29.4 million increase in other operating and maintenance related to our power plants, driven by increases to certain plant-related regulatory assets in 2022 as a result of the December 2022 Wisconsin rate orders as well as operating costs associated with Whitewater, which we purchased in January 2023.

These increases were partially offset by lower severance during 2023.

These increases were partially offset by lower severance expense during 2023.

• A $19.1 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities, as discussed in the notes under the other operation and maintenance table above.

See Note 26, Regulatory Environment, for more information.

These increases in other operating expenses were partially offset by:

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Also contributing to the increase was the 2022 deferral of $8.2 million of interest expense related to capital investments made by WG since its 2020 rate case, as approved by the PSCW in an order that allowed our Wisconsin utilities to offset certain 2022 revenue deficiencies in order to forego filing for 2022 base rate increases.

This deferred interest expense is now being amortized over a two-year period.

During 2023, WG amortized $4.1 million of interest expense.

See Note 26, Regulatory Environment, for more information.

These increases were partially offset by higher AFUDC-Debt due to continued capital investment and lower interest expense on finance lease liabilities, primarily related to the We Power leases, as finance lease liabilities decrease each year as payments are made.

This deferred interest expense was amortized over a two-year period.

During 2023, WG amortized $4.1 million

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of interest expense.

See Note 26, Regulatory Environment, for more information.

Income Tax Expense

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These decreases in income tax expense were partially offset by higher pre-tax income.

See Note 16, Income Taxes, for more information.

Illinois Segment Contribution to Net Income Attributed to Common Shareholders

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2024 was $252.1 million, representing a $112.1 million, or 80.1%, increase from the prior year.

The increase was primarily due to a $178.9 million impairment recorded in 2023 associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG.

An increase in margins related to the impacts of the November 2023 rate orders, effective December 1, 2023 for PGL, and February 1, 2024 for NSG, also contributed to the higher net income.

SMP costs that were previously being recovered under PGL's QIP rider are now included in PGL's base rates.

See Note 26, Regulatory Environment, for more information on the PGL and NSG rate orders and the ICC's disallowance.

The Illinois segment's contribution to net income attributed to common shareholders for the year ended December 31, 2023 was $140.0 million, representing an $86.9 million, or 38.3%, decrease from the prior year.

The decrease was driven by higher operating expenses, primarily due to an impairment associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG, and the year-over-year impact of a gain recorded in 2022 on the sale of certain real estate by PGL.

The decrease was driven by higher operating expenses, primarily due to a $178.9 million pre-tax impairment associated with the ICC's disallowance of certain incurred capital costs in its November 2023 rate orders for PGL and NSG, and the year-over-year impact of a gain recorded in 2022 on the sale of certain real estate by PGL.

Partially offsetting these increases in operating expenses were lower natural gas distribution and maintenance costs and a decrease in expenses related to charitable contributions.

Higher natural gas margins, due to a positive impact from PGL's rate order, effective December 1, 2023, and continued capital investment in the SMP project in 2023 under PGL's QIP rider, also partially offset the net increase in operating expenses.

See Note 26, Regulatory Environment, for more information on the PGL and NSG rate orders.

Since the majority of PGL and NSG customers use natural gas for heating, net income attributed to common shareholders at the Illinois segment is sensitive to weather and is generally higher during the winter months.

Year Ended December 31

(in millions) 2023 2022 B (W)

Natural gas revenues $ 1,557.8 $ 1,890.9 $ (333.1)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating revenues $ 1,602.4 $ 1,557.8 $ 1,890.9 $ 44.6 $ (333.1)

Operating expenses

Cost of natural gas sold 376.7 443.0 792.5 66.3 349.5

Total natural gas margins 1,114.8 1,098.4 16.4

Other operation and maintenance 461.5 397.9 459.2 (63.6) 61.3

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Net income attributed to common shareholders $ 252.1 $ 140.0 $ 226.9 $ 112.1 $ (86.9)

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The following table shows a breakdown of other operation and maintenance:

Year Ended December 31

(in millions) 2023 2022 B (W)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operation and maintenance not included in the line items below $ 318.5 $ 303.4 $ 319.4 $ (15.1) $ 16.0

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(1) These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on net income.

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The following tables provide information on delivered sales volumes by customer class and weather statistics:

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Natural Gas Sales Volumes (Therms - in millions)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

Customer Class

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Weather (Degree Days) (1)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

Heating (5,944 Normal) 4,848 5,097 6,140 (4.9) % (17.0) %

(1) Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.

Natural Gas Revenues

Natural gas revenues decreased $333.1 million during 2023, compared with 2022.

Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues.

The average per-unit cost of natural gas sold decreased approximately 35% during 2023, compared with 2022.

The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins at the Illinois segment, net of the $32.9 million impact of the riders referenced in the table above, increased $49.3 million during 2023, compared with 2022.

The increase in margins was primarily driven by:

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP).

See "Non-GAAP Financial Measures" above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

Year Ended December 31

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating revenues $ 1,602.4 $ 1,557.8 $ 1,890.9 $ 44.6 $ (333.1)

Operating expenses

Cost of natural gas sold (376.7) (443.0) (792.5) 66.3 349.5

Other operation and maintenance (1)

(227.2) (206.2) (255.8) (21.0) 49.6

Depreciation and amortization (255.4) (237.3) (230.9) (18.1) (6.4)

Property and revenue taxes (59.9) (29.9) (38.6) (30.0) 8.7

Gross margin (GAAP) 683.2 641.4 573.1 41.8 68.3

Other operation and maintenance (1)

227.2 206.2 255.8 21.0 (49.6)

Depreciation and amortization 255.4 237.3 230.9 18.1 6.4

Property and revenue taxes 59.9 29.9 38.6 30.0 (8.7)

Utility margin (non-GAAP) $ 1,225.7 $ 1,114.8 $ 1,098.4 $ 110.9 $ 16.4

(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses.

These expenses are included in the above table to calculate gross margin as defined under GAAP.

2024 Compared with 2023

Gross margin (GAAP) at the Illinois segment increased $41.8 million during 2024, compared with 2023, and utility margin (non-GAAP) increased $110.9 million during 2024, compared with 2023.

Both measures were driven by:

• An $84.0 million increase in margins related to the impacts of the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.

PGL’s rate order includes the recovery of costs related to PGL’s SMP in base rates.

Previously, these costs were being recovered under its QIP rider.

See Note 26, Regulatory Environment, for more information on the rate orders.

• A $45.4 million increase in revenues associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

These increases in gross margin (GAAP) and utility margin (non-GAAP) were partially offset by a $12.9 million decrease in revenues driven by an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which requires refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 26, Regulatory Environment, for more information on the ICC disallowance.

• A $30.0 million increase in property and revenue taxes;

• An $18.1 million increase in depreciation and amortization;

• A $14.6 million increase in natural gas distribution and maintenance costs;

• A $7.3 million increase in customer service expense.

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Other Operating Expenses (includes other operation and maintenance, impairment related to ICC disallowances, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the Illinois segment decreased $100.5 million, net of the $45.4 million impact of the riders referenced in the table above, during 2024, compared with 2023.

The significant factors impacting the decrease in other operating expenses were:

• A $178.9 million impairment associated with the ICC orders received in November 2023 related to PGL's and NSG's rate reviews, which included the disallowance of previously incurred capital costs at PGL and NSG, in the amount of $177.2 million and $1.7 million, respectively.

See Note 26, Regulatory Environment, for more information on the ICC disallowances.

• An $11.1 million decrease in expense driven by an ICC order received in May 2023 related to an annual prudency review of PGL's and NSG's UEA riders, which required refunds to ratepayers starting in September 2023.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery and Note 26, Regulatory Environment, for more information.

These decreases in operating expenses were partially offset by:

• A $30.0 million increase in property and revenue taxes, driven by an increase in the invested capital tax.

This increase was related to an increase in regulatory amortizations as approved in the PGL and NSG rate orders issued by the ICC, effective December 1, 2023 and February 1, 2024, respectively.

• An $18.1 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan.

• A $14.6 million increase in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure during 2024, compared with 2023.

• A $12.1 million impairment driven by an ICC order received in August 2024 related to the 2016 annual prudency review of PGL's 2016 Rider QIP, which included a disallowance of certain capital costs.

See Note 26, Regulatory Environment, for more information on the ICC disallowances.

• A $7.3 million increase in customer service expense due to higher call center expense and metering costs.

Interest Expense

Interest expense at the Illinois segment increased $5.8 million during 2024, compared with 2023, driven by the impact of PGL and NSG issuing long-term debt in November 2023.

Income Tax Expense

Income tax expense at the Illinois segment increased $49.0 million during 2024, compared with 2023, driven by an increase in pre-tax income.

2023 Compared with 2022

Gross margin (GAAP) at the Illinois segment increased $68.3 million during 2023, compared with 2022, and utility margin (non-GAAP) increased $16.4 million during 2023, compared with 2022.

Both measures were driven by:

• A $29.5 million increase in margins related to the impact of the PGL rate order issued by the ICC, effective December 1, 2023.

1 unchanged sentence

PGL recovered the costs related to the SMP through a surcharge on customer bills pursuant to the QIP rider, which was in effect for most of 2023.

For information on PGL's rate order, the QIP rider, PGL's plan to recover SMP costs after 2023, and the pause in spending on the SMP, see Note 26, Regulatory Environment.

These increases in margins were partially offset by a $32.9 million decrease in margins associated with certain riders that are offset in other operation and maintenance and therefore do not have a significant impact on net income.

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For information on the QIP rider and PGL's recovery of SMP costs after 2023, as well as the pause in spending on the SMP, see Note 26, Regulatory Environment.

Additionally, the larger increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items:

• A $43.8 million decrease in natural gas distribution and maintenance costs;

• An $8.7 million decrease in property and revenue taxes;

• A $3.7 million decrease in customer service expense, partially offset by

• A $6.4 million increase in depreciation and amortization.

Other Operating Expenses (includes other operation and maintenance, impairment related to ICC disallowances, depreciation and amortization, and property and revenue taxes)

2 unchanged sentences

See Note 26, Regulatory Environment, for more information on the ICC disallowances.

• A $54.5 million pre-tax gain on the sale of certain real estate in Chicago during 2022.

1 unchanged sentence

• An $11.1 million increase in expense driven by an ICC order received in May 2023 related to an annual prudency review of PGL's and NSG's UEA riders, which required refunds to ratepayers starting in September 2023.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Regulatory Recovery for more information.

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These increases in operating expenses were partially offset by:

8 unchanged sentences

See Note 20, Employee Benefits, for more information on our benefit costs.

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Interest Expense

4 unchanged sentences

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2023 was $48.1 million, representing an $8.4 million, or 21.2%, increase over the prior year.

The increase was driven by higher natural gas margins due to an interim rate increase at MERC, effective January 1, 2023.

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2024 was $54.5 million, representing a $6.4 million, or 13.3%, increase over the prior year.

The increase was driven by higher margins due to MGU's rate increase approved by the MPSC that was effective January 1, 2024 and MERC's final rate increase approved by the MPUC in November 2023.

See Note 26, Regulatory Environment, for more information.

This positive impact was partially offset by a decrease in natural gas margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

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The increase was driven by higher margins due to an interim rate increase at MERC, effective January 1, 2023.

This positive impact was partially offset by a decrease in margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

Since the majority of MERC and MGU customers use natural gas for heating, net income attributed to common shareholders is sensitive to weather and is generally higher during the winter months.

Year Ended December 31

(in millions) 2023 2022 B (W)

Natural gas revenues $ 519.1 $ 618.5 $ (99.4)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating revenues $ 449.8 $ 519.1 $ 618.5 $ (69.3) $ (99.4)

Operating expenses

Cost of natural gas sold 198.6 277.2 391.6 78.6 114.4

Total natural gas margins 241.9 226.9 15.0

Other operation and maintenance 93.9 94.5 98.5 0.6 4.0

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Year Ended December 31

(in millions) 2023 2022 B (W)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operation and maintenance not included in line item below $ 76.8 $ 72.6 $ 77.8 $ (4.2) $ 5.2

$ 72.6 $ 77.8 $ 5.2

Regulatory amortizations and other pass through expenses (1)

2 unchanged sentences

(1) Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.

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The following tables provide information on delivered sales volumes by customer class and weather statistics:

1 unchanged sentence

Natural Gas Sales Volumes ( Therms - in millions)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

Customer Class

6 unchanged sentences

Weather (Degree Days) (1)

2023 2022 B (W)

2024 2023 2022 2024 vs 2023 2023 vs 2022

Heating (7,993 Normal) 6,792 7,324 8,585 (7.3) % (14.7) %

1 unchanged sentence

(1) Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective territories.

Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP).

See "Non-GAAP Financial Measures" above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

Year Ended December 31

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating revenues $ 449.8 $ 519.1 $ 618.5 $ (69.3) $ (99.4)

Operating expenses

Cost of natural gas sold (198.6) (277.2) (391.6) 78.6 114.4

Other operation and maintenance (1)

(55.4) (54.2) (55.9) (1.2) 1.7

Depreciation and amortization (47.0) (43.3) (40.9) (3.7) (2.4)

Property and revenue taxes (21.0) (24.4) (23.3) 3.4 (1.1)

Gross margin (GAAP) 127.8 120.0 106.8 7.8 13.2

Other operation and maintenance (1)

55.4 54.2 55.9 1.2 (1.7)

Depreciation and amortization 47.0 43.3 40.9 3.7 2.4

Property and revenue taxes 21.0 24.4 23.3 (3.4) 1.1

Utility margin (non-GAAP) $ 251.2 $ 241.9 $ 226.9 $ 9.3 $ 15.0

(1) Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses.

These expenses are included in the above table to calculate gross margin as defined under GAAP.

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Natural Gas Revenues

Natural gas revenues decreased $99.4 million during 2023, compared with 2022.

Because prudently incurred natural gas costs are passed through to our customers in current rates, the changes are offset by comparable changes in revenues.

The average per-unit cost of natural gas sold decreased approximately 17% during 2023, compared with 2022.

The remaining drivers of changes in natural gas revenues are described in the discussion of margins below.

Natural Gas Utility Margins

Natural gas utility margins increased $15.0 million during 2023, compared with 2022, driven by a $19.5 million increase related to an interim rate increase at MERC that was effective January 1, 2023.

2024 Compared with 2023

Gross margin (GAAP) increased $7.8 million during 2024, compared to 2023, and utility margin (non-GAAP) increased $9.3 million during 2024, compared to 2023.

Both measures were driven by:

• A $9.6 million increase related to MGU's rate increase approved by the MPSC that was effective January 1, 2024.

• A $2.0 million increase related to MERC's final rate increase approved by the MPUC in November 2023.

• A $1.6 million increase related to higher sales volumes, driven by higher transportation sales.

These increases were partially offset by:

• A $2.3 million decrease related to MGU's energy optimization program, which provides rebates, incentives, and energy efficiency education to customers.

• A $1.4 million decrease related to MERC CIP revenue, which was offset in operation and maintenance expense.

Rebates and programs are available to residential and commercial customers of MERC through the CIP, which is funded by rate payers using the Conservation Cost Recovery Charge and the Conservation Cost Recovery Adjustment funds that are collected on their monthly billing statements.

Additionally, the lower increase in gross margin (GAAP) as compared to the increase in utility margin (non-GAAP), was driven by the following items that are further described in Other Operating Expenses below:

• A $3.7 million increase in depreciation and amortization;

• A $1.2 million increase in natural gas operations and customer service expense;

partially offset by

• A $3.4 million decrease in property and revenue taxes.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

Other operating expenses at the other states segment decreased $0.3 million during 2024, compared with 2023.

The significant factors impacting the decrease in operating expenses were:

• A $4.2 million decrease in bad debt expense, driven by improvements in MERC's and MGU's loss rates and lower past due account receivable balances due to warmer than normal weather conditions during most of 2024 and low average natural gas prices.

• A $3.4 million decrease in property and revenue taxes, driven by the resolution of a use tax audit at MGU.

• A $1.4 million decrease in operation and maintenance expense related to MERC's CIP program, which has an offsetting decrease in margins.

These decreases in other operating expenses were partially offset by:

• A $3.7 million increase in depreciation and amortization related to continued capital investment.

• A $2.8 million increase in benefit costs, driven by higher costs related to stock-based compensation and deferred compensation.

• A $1.2 million increase in natural gas operations and customer service expense, driven by the timing of various operation and maintenance projects approved in MERC's and MGU's most recent rate orders.

2024 Form 10-K 68

WEC Energy Group, Inc.

Interest Expense

Interest expense at the other states segment increased $0.5 million during 2024, compared with 2023, due to higher average short-term debt balances and higher average short-term debt interest rates.

Also contributing to the increase was the impact of MGU issuing long-term debt in October 2024.

Income Tax Expense

Income tax expense at the other states segment increased $2.4 million during 2024, compared with 2023, driven by an increase in pre-tax income.

2023 Compared with 2022

Gross margin (GAAP) increased $13.2 million during 2023, compared to 2022, and utility margin (non-GAAP) increased $15.0 million during 2023, compared to 2022.

Both measures were driven by a $19.5 million positive impact related to an interim rate increase at MERC that was effective January 1, 2023.

See Note 26, Regulatory Environment, for more information.

This increase in natural gas utility margins was partially offset by a $6.1 million decrease related to lower sales volumes, primarily driven by warmer weather.

This increase was partially offset by a $6.1 million decrease related to lower sales volumes, primarily driven by warmer weather.

As measured by heating degree days, 2023 was 14.7% and 13.1% warmer than 2022 at MERC and MGU, respectively.

• A $2.4 million increase in depreciation and amortization;

partially offset by

• A $1.8 million decrease in natural gas operations and customer service expense.

Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)

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Income Tax Expense

Income tax expense at the other states segment increased $3.2 million during 2023, compared with 2022, driven by an increase in pre-tax income.

Income tax expense at the other states segment increased $3.2 million during 2023, compared with 2022, primarily driven by an increase in pre-tax income.

2024 Form 10-K 69

WEC Energy Group, Inc.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

Year Ended December 31

(in millions) 2023 2022 B (W)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Equity in earnings of transmission affiliates $ 207.5 $ 177.5 $ 194.7 $ 30.0 $ (17.2)

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Net income attributed to common shareholders $ 141.0 $ 119.1 $ 129.5 $ 21.9 $ (10.4)

2023 Form 10-K 61

WEC Energy Group, Inc.

2024 Compared with 2023

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $30.0 million during 2024, compared with 2023.

This increase was primarily driven by a $20.1 million increase in equity earnings due to the impact of a FERC order issued in October 2024 addressing complaints related to ATC's ROE.

Continued capital investment by ATC also contributed to the year-over-year increase in equity earnings.

Income Tax Expense

Income tax expense at the electric transmission segment increased $8.1 million during 2024, compared with 2023, driven by an increase in pre-tax income.

2023 Compared with 2022

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates decreased $17.2 million during 2023, compared with 2022.

The decrease was primarily driven by the $20.5 million positive impact recorded in 2022 related to the D.C.

This decrease was primarily driven by the $20.5 million positive impact recorded in 2022 related to the D.C.

Circuit Court of Appeals opinion issued in August 2022 addressing complaints related to ATC's ROE.

For information on this D.C.

Partially offsetting this negative year-over-year impact was continued capital investment by ATC.

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Income tax expense at the electric transmission segment decreased $6.8 million during 2023, compared with 2022, driven by a decrease in pre-tax income.

2024 Form 10-K 70

WEC Energy Group, Inc.

Non-Utility Energy Infrastructure Segment Contribution to Net Income Attributed to Common Shareholders

Year Ended December 31

(in millions) 2023 2022 B (W)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating income $ 393.0 $ 360.7 $ 372.8 $ 32.3 $ (12.1)

Other income, net 1.0 — — 1.0 —

Interest expense 99.7 94.3 68.9 (5.4) (25.4)

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Net income attributed to common shareholders $ 380.8 $ 336.0 $ 324.4 $ 44.8 $ 11.6

2024 Compared with 2023

Operating Income

Operating income at the non-utility energy infrastructure segment increased $32.3 million during 2024, compared with 2023, driven by these items at WECI:

• A $48.4 million positive impact in 2024 related to the receipt of performance payments.

• A $3.9 million increase in PPA revenue resulting from increased generation driven by higher wind speeds and lower energy curtailments.

These increases in operating income were partially offset by:

• A $12.3 million negative impact due to transmission congestion that reduced energy market prices.

• A $7.1 million increase in operation and maintenance expenses due primarily to equipment failures at several of our renewable generation facilities.

• The recognition of $6.4 million in revenue related to Blooming Grove in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event.

The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.

• A $3.1 million decrease due to lower amounts recognized for REC sales in 2024 at Blooming Grove driven by lower contracted REC prices overall, as well as timing of REC contract execution.

In addition to the above items at WECI, there was an $11.7 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $5.4 million during 2024, compared with 2023, driven by an $8.6 million increase in interest expense due to WECI’s issuance of a $430.0 million long-term intercompany note payable to WEC Energy Group in April 2023.

The $430.0 million intercompany note payable was redeemed in December 2024, and WECI recorded a $3.5 million loss on early redemption.

This intercompany interest expense (including the loss on early redemption) is offset by higher intercompany interest income at the corporate and other segment and is eliminated in consolidation.

Also driving an increase in interest expense was the impact of WECI Energy Holding III's issuance of long-term debt in December 2024.

Partially offsetting these increases was lower interest expense due to lower principal balances on previously issued long-term debt, as a result of the semi-annual principal payments on long-term debt.

2024 Form 10-K 71

WEC Energy Group, Inc.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $14.0 million during 2024, compared with 2023.

The increase was primarily due to an increase in PTCs that was related to the acquisition of additional renewable generation facilities, the IRS approved PTC rate increase, and higher production volumes, partially offset by higher pre-tax earnings.

2023 Compared with 2022

Operating Income

Operating income at the non-utility energy infrastructure segment decreased $12.1 million during 2023, compared with 2022, driven by these items at WECI:

• Recognition of $15.2 million in revenue related to our Upstream wind park in 2022 that was associated with market settlements received from SPP in February 2021.

• The recognition of $15.2 million in revenue related to our Upstream wind park in 2022 that was associated with market settlements received from SPP in February 2021.

These settlements were subject to a FERC complaint, so we were not able to recognize them as revenue until the FERC issued an order denying that complaint in 2022.

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These decreases in operating income were partially offset by:

• Recognition of $6.4 million in revenue related to our Blooming Grove wind park in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event.

• The recognition of $6.4 million in revenue related to our Blooming Grove wind park in 2023 for a capacity payment received from PJM Interconnection that was associated with a December 2022 cold weather event.

The capacity payment was subject to a FERC complaint, so we recognized this as revenue in 2023 when FERC issued an order denying that complaint.

• A $4.4 million positive impact from Sapphire Sky Wind, a new wind facility acquired in February 2023.

• A $4.4 million positive impact from Sapphire Sky, a wind facility acquired in February 2023.

In addition to the above items at WECI, there was a $5.4 million positive impact from We Power due to continued capital investment.

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Also driving the increase was the impact of WECI Wind Holding II's issuance of long-term debt in December 2022.

2023 Form 10-K 62

WEC Energy Group, Inc.

Income Tax Benefit

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Also contributing to the favorable income tax variance were lower pre-tax earnings during 2023, compared with 2022.

2024 Form 10-K 72

WEC Energy Group, Inc.

Corporate and Other Segment Contribution to Net Income Attributed to Common Shareholders

Year Ended December 31

(in millions) 2023 2022 B (W)

(in millions) 2024 2023 2022 2024 vs 2023 2023 vs 2022

Operating loss $ (11.3) $ (26.8) $ (11.7) $ 15.5 $ (15.1)

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Interest expense 310.0 258.1 119.4 (51.9) (138.7)

Gain on debt extinguishment (23.1) (0.5) — 22.6 0.5

Loss before income taxes (243.8) (231.1) (116.5) (12.7) (114.6)

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Net loss attributed to common shareholders $ (164.3) $ (162.8) $ (70.8) $ (1.5) $ (92.0)

2024 Compared with 2023

Operating Loss

The operating loss at the corporate and other segment decreased $15.5 million during 2024, compared with 2023.

The lower operating loss was driven by a $16.8 million positive impact from WBS's allocation of its net credits from the non-service components of its net periodic pension and OPEB costs.

These net credits are initially recorded in other income, net, but are allocated to our operating segments as an overhead cost, which is recorded through operating expenses.

As a result, this positive impact is fully offset in the other income, net line item discussed below.

Other Income, Net

Other income, net at the corporate and other segment increased $1.1 million during 2024, compared with 2023.

The significant factors impacting the increase in other income, net were:

• A $14.3 million increase in interest income, driven by an $8.6 million increase in intercompany interest income from WECI, primarily related to its issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023.

The $430.0 million intercompany note was redeemed in December 2024, and WEC Energy Group recorded a $3.5 million gain on the redemption.

This intercompany interest income is offset by higher intercompany interest expense at our non-utility energy infrastructure segment.

Higher interest income on cash balances of $3.5 million also contributed to the increase in other income.

• A $5.8 million increase due to net earnings of $2.3 million from our equity method investments in technology and energy-focused investment funds during 2024, compared with net losses of $3.5 million during 2023.

These increases in other income, net were partially offset by:

• A $16.8 million decrease driven by lower net credits from the non-service components of WBS's net periodic pension and OPEB costs.

As discussed above, this negative impact was offset by lower operating expenses as these credits are allocated to our operating segments as an overhead cost.

• A $2.0 million decrease due to lower net gains from the investments held in the Integrys rabbi trust.

The gains from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments.

See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Interest Expense

Interest expense at the corporate and other segment increased $51.9 million during 2024, compared with 2023, primarily due to the impact of long-term debt issuances in April and September 2023, as well as May and December 2024.

This increase was partially offset by long-term debt maturities and redemptions.

See Note 14, Long-Term Debt, for more information.

2024 Form 10-K 73

WEC Energy Group, Inc.

Gain on Debt Extinguishments

The gain on debt extinguishments increased $22.6 million during 2024, compared with 2023, driven by the early settlement of a portion of both our 5.60% Senior Notes due September 12, 2026 and our 1.80% Senior Notes due October 15, 2030.

We also recorded gains on redemptions and repurchases of our 2007 Junior Notes during 2024.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $11.2 million during 2024, compared with 2023, driven by the resolution of a tax audit and higher pre-tax loss.

2023 Compared with 2022

Operating Loss

The operating loss at the corporate and other segment increased $15.1 million during 2023, compared with 2022, driven by the year-over-year impact from the 2022 resolution of a previously recorded liability as certain outstanding matters reached a favorable outcome.

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• A $13.7 million net gain from the investments held in the Integrys rabbi trust during 2023, compared with a $12.6 million net loss during 2022.

The gains and losses from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments.

See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

• An $18.3 million increase in intercompany interest income, driven by WECI's issuance of a $430.0 million long-term intercompany note to WEC Energy Group in April 2023 and higher interest rates on short-term borrowings to subsidiaries in our operating segments.

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Also driving the increase in interest expense was higher average short-term debt balances and increased short-term debt interest rates.

2023 Form 10-K 63

WEC Energy Group, Inc.

Income Tax Benefit

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We expect to maintain adequate liquidity to meet our cash requirements for operation of our businesses and implementation of our corporate strategy through internal generation of cash from operations and access to the capital markets.

2024 Form 10-K 74

WEC Energy Group, Inc.

The following discussion and analysis of our Liquidity and Capital Resources includes comparisons of our cash flows for the year ended December 31, 2024 with the year ended December 31, 2023.

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Net cash provided by operating activities increased $193.4 million during 2024, compared with 2023, driven by:

• A $1.54 billion increase in cash from lower payments for fuel and purchased power at our generation plants, as well as lower natural gas costs related to natural gas sold to our customers during 2023, compared with 2022, primarily driven by a decrease in the price of natural gas.

• A $111.3 million increase in cash related to $58.9 million of cash received for income taxes during 2023, compared with $52.4 million of cash paid for income taxes during 2022.

The increase in cash received for income taxes was driven by proceeds received in 2023 related to PTCs that were sold to a third party.

• A $24.1 million increase in cash related to higher distributions received from ATC during 2023, compared with 2022.

• A $215.5 million increase in cash driven by lower amounts of collateral paid to counterparties during 2024, compared with 2023, as well as lower realized losses on derivative instruments recognized during 2024, compared with 2023.

• A $205.3 million increase in cash received for income taxes driven by proceeds received during 2024, compared with 2023, related to 2023 and 2024 PTCs that were sold to third parties.

• An $83.1 million increase in cash from lower payments for operating and maintenance expenses.

During 2024, our payments were lower associated with previous commitments to charitable projects and operation and maintenance related to our We Power and Wisconsin generation units, as well as due to the timing of payments for accounts payable.

• A $21.9 million increase in cash related to lower payments for taxes other than income taxes during 2024, compared with 2023.

• An $8.9 million increase in cash from lower payments for environmental remediation related to work completed on former manufactured gas plant sites during 2024, compared with 2023.

These increases in net cash provided by operating activities were partially offset by:

• A $403.7 million decrease in cash driven by collateral paid to counterparties during 2023, compared with collateral received from counterparties during 2022, as well as realized losses on derivative instruments recognized during 2023, compared with realized gains recognized during 2022.

• A $168.2 million decrease in cash from higher payments for interest, driven by long-term debt issuances during the last four months of 2022 and early 2023, higher average short-term debt balances, and higher interest rates during 2023, compared with 2022.

2023 Form 10-K 64

WEC Energy Group, Inc.

• A $127.9 million decrease in cash from higher payments for operating and maintenance expenses.

During 2023, our payments were higher associated with previous commitments to charitable projects, transmission costs, and operation and maintenance related to our We Power and Wisconsin generation units, as well as due to the timing of payments for accounts payable.

• A $22.1 million decrease in cash related to higher payments for environmental remediation related to work completed on former manufactured gas plant sites during 2023, compared with 2022.

• A $224.8 million decrease in cash from lower overall collections from customers during 2024, compared with 2023.

This decrease was driven by the lower per-unit cost of natural gas and lower sales volumes from warmer winter weather during 2024, compared with 2023.

• A $132.3 million decrease in cash from higher payments for interest, driven by long-term debt issuances at higher interest rates during 2023 and 2024, higher average short-term debt balances, and higher average short-term debt interest rates during 2024, compared with 2023.

Investing Activities

Net cash used in investing activities increased $244.3 million during 2024, compared with 2023, driven by:

• The acquisition of a 90% ownership interest in Delilah I in December 2024 for $462.5 million, net of cash acquired of $0.6 million.

• The acquisition of a 90% ownership interest in Maple Flats in November 2024 for $431.2 million, net of cash acquired of $0.5 million.

2024 Form 10-K 75

WEC Energy Group, Inc.

• A $288.2 million increase in cash paid for capital expenditures during 2024, compared with 2023, which is discussed in more detail below.

• A $31.1 million decrease in proceeds received from the sale of assets during 2024, compared with 2023, driven by the sale of land at the site of our former Pleasant Prairie power plant in 2023.

See Note 3, Dispositions, for more information.

These increases in net cash used in investing activities were partially offset by:

• The acquisition of a 90% ownership interest in Sapphire Sky in February 2023 for $442.6 million, net of cash acquired of $0.3 million.

• The acquisition of an 80% ownership interest in Samson I in February 2023 for $257.3 million, net of cash acquired of $5.2 million.

• A $178.0 million increase in cash paid for capital expenditures during 2023, compared with 2022, which is discussed in more detail below.

• The acquisition of a 90% ownership interest in Red Barn in April 2023 for $143.8 million.

• The acquisition of a 13.8% ownership interest in West Riverside in June 2023 for $95.3 million.

See Note 8, Jointly Owned Utility Facilities, for more information.

• The acquisition of Whitewater in January 2023 for $76.0 million.

• A decrease of $39.1 million in insurance proceeds received during 2023, compared with 2022.

In 2022, we received insurance proceeds for property damage related to the PSB water damage claim.

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

• A $36.2 million decrease in proceeds received from the sale of assets during 2023, compared with 2022.

See Note 3, Dispositions, for more information.

• An $18.2 million increase in capital contributions paid to transmission affiliates during 2023, compared with 2022.

See Note 21, Investment in Transmission Affiliates, for more information.

• A $10.1 million decrease in cash received for the reimbursement of ATC's construction costs during 2023, compared with 2022.

• An $18.2 million decrease in capital contributions paid to transmission affiliates during 2024, compared with 2023.

See Note 21, Investment in Transmission Affiliates, for more information.

These increases in net cash used in investing activities were partially offset by the acquisition of a 90% ownership interest in Thunderhead in September 2022 for $382.0 million.

For more information on our acquisitions, see Note 2, Acquisitions.

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Total capital expenditures $ 2,781.1 $ 2,492.9 $ 288.2

The increase in cash paid for capital expenditures at the Wisconsin segment during 2024, compared with 2023, was driven by higher payments for WE's electric distribution system, increased capital expenditures for renewable energy projects at WE, WPS, and UMERC, increased capital expenditures for combustion turbines at OCPP, as well as increased capital expenditures for a project to consolidate our electric utility operations technology.

These increases in capital expenditures were partially offset by decreased payments for construction of WE's and WG's LNG facilities, which were completed in November 2023 and February 2024, respectively, as well as decreased payments for natural gas-fired generation that was constructed at WPS's existing Weston power plant site, which was completed in July 2023.

The decrease in cash paid for expenditures at the Illinois segment during 2024, compared with 2023, was driven by lower payments related to PGL's natural gas distribution system, including SMP.

For more information on the factors contributing to this decrease, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceedings.

The increase in cash paid for capital expenditures at the Other States segment during 2024, compared with 2023, was driven by increased payments for MGU's natural gas distribution system.

See Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects below for more information.

2024 Form 10-K 76

WEC Energy Group, Inc.

The increase in cash paid for capital expenditures at the Wisconsin segment during 2023, compared with 2022, was driven by higher payments related to renewable energy projects, upgrades to WE's and WPS's electric and natural gas distribution systems, and construction of WE's and WG's LNG facilities.

These increases were partially offset by lower payments for capital expenditures related to the natural gas-fired generation constructed at WPS's Weston power plant site.

The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2023, compared with 2022, was primarily driven by lower payments for capital expenditures related to wastewater treatment system modifications for We Power's ERGS units.

See Note 24, Commitments and Contingencies, for more information.

See Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects below for more information.

Financing Activities

Net cash provided by financing activities decreased $55.1 million during 2024, compared with 2023, driven by:

• A $1,276.5 million decrease in cash due to $902.8 million of net repayments of commercial paper during 2024, compared with $373.7 million of net borrowings of commercial paper during 2023.

• A $1,132.6 million decrease in cash due to higher retirements of long-term debt during 2024, compared with 2023.

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In January 2024, our Board of Directors increased our quarterly dividend by $0.055 per share (7.1%) effective with the March 2024 dividend payment.

• A $27.3 million decrease in cash proceeds related to fewer stock options exercised during 2023, compared with 2022.

• A $31.7 million decrease in cash due to higher payments for debt extinguishment and issuance costs during 2024, compared with 2023.

• The purchase of an additional 10% ownership interest in Samson I in January 2024 for $28.1 million.

These decreases in net cash provided by financing activities were partially offset by:

• A $626.3 million increase in cash due to $373.7 million of net borrowings of commercial paper during 2023, compared with $252.6 million of net repayments of commercial paper during 2022.

• A $2,290.9 million increase in cash due to higher issuances of long-term debt during 2024, compared with 2023.

• A $163.4 million increase in cash due to the issuance of common stock during 2024.

We did not issue any common stock during 2023.

See Note 11, Common Equity, for more information.

• A $17.4 million increase in cash proceeds related to an increase in stock options exercised during 2024, compared with 2023.

• A $13.4 million increase in cash due to a decrease in common stock purchased during 2024, compared with 2023, to satisfy requirements of our stock-based compensation plans.

See Note 11, Common Equity, for more information.

Significant Financing Activities

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Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond.

We have several capital projects and acquisitions that will require significant capital expenditures over the next three years and beyond.

All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors.

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AMI is an integrated system of smart meters, communication networks, and data management systems that enable two-way communication between utilities and customers.

We are committed to investing in solar, wind, battery storage, and clean natural gas-fired generation.

We are committed to investing in solar, wind, battery storage, and natural gas-fired generation.

Below are examples of projects that are proposed or currently underway.

• WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and 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 180 MWs of solar generation and 99 MWs of battery storage of this project.

In December 2024, the construction of the solar portion of Paris was completed, with WE and WPS collectively owning 180 MWs of solar generation.

WE and WPS will collectively own 99 MWs of battery storage of this project, with construction expected to be completed in 2025.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $542 million.

• WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire and 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 fully constructed, WE and WPS will collectively own 225 MWs of solar generation and 68 MWs of battery storage of this project.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $567 million, with construction of the solar portion and battery storage expected to be completed in 2025 and 2026, respectively.

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

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

WE's and WPS's combined share of the cost of this project is estimated to be approximately $405 million, with construction expected to be completed in 2024.

As part of its order, the PSCW approved battery capacity at this project, which is no longer included in the current capital plan.

We will continue to evaluate timing, cost, and feasibility of the installation of batteries.

• WE and WPS, along with an unaffiliated utility, received PSCW approval to acquire 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 collectively own 270 MWs of solar generation.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $486 million, with construction expected to be completed in 2026.

As part of its order, the PSCW approved battery capacity at this project, which is no longer included in the current capital plan.

We will continue to evaluate timing, cost, and feasibility of the installation of batteries.

• In September 2023, WPS filed a request with the PSCW to exercise a second option to acquire an additional 100 MWs of capacity in West Riverside, a combined cycle natural gas plant operated by an unaffiliated utility in Rock County, Wisconsin.

In October 2023, WPS filed for approval to assign the second option to purchase West Riverside to WE.

If approved, our share of the cost of this ownership interest is expected to be approximately $100 million, with the transaction expected to close in 2024.

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

The project will be located in Dane County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project.

WE's and WPS's combined share of the cost of this project is estimated to be approximately $930 million, with construction of the solar portion and battery storage expected to be completed in 2026 and 2027, respectively.

• WE and WPS plan to enhance fuel flexibility at the coal-fired ERGS units and Weston Unit 4.

• In February 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct High Noon, a utility-scale solar-powered electric generating facility.

The project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation of this project.

If approved, WE and WPS's combined share of the cost of the project is estimated to be approximately $576 million, with construction expected to be

• In February 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct High Noon, a utility-scale solar-powered electric generating facility with a battery energy storage system.

If approved, the project will be located in Columbia County, Wisconsin and once fully constructed, WE and WPS will collectively own 270 MWs of solar generation and 149 MWs of battery storage of this project.

If approved, WE and WPS's combined share of the cost of the project is estimated to be approximately $883 million, with construction of the solar portion and battery storage expected to be completed in 2027.

• UMERC received MPSC approval to acquire and construct Renegade, a utility-scale solar-powered electric generating facility.

The project will be located in Delta and Marquette counties, Michigan and once fully constructed, UMERC will own 100 MWs of solar generation.

The cost of this project is estimated to be approximately $226 million, with construction expected to be completed by the end of 2026.

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completed by the end of 2026.

Approval for battery capacity at this project was also requested, which is not included in the current capital plan.

We will continue to evaluate the timing, cost, and feasibility of the installation of batteries.

• In December 2023, UMERC filed a request with the MPSC to acquire and construct Renegade, a utility-scale solar-powered electric generating facility.

The project will be located in Delta County, Michigan and once fully constructed UMERC will own 100 MWs of solar generation.

The cost of this project is estimated to be approximately $226 million, with construction expected to be completed by the end of 2026.

In August 2023, the DOC issued a ruling in its investigation into whether new tariffs should be imposed on solar panels and cells imported from multiple southeast Asian countries.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaint and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the DOC ruling and CBP actions related to solar panels, respectively.

• In April 2024, WE filed a request with the PSCW to build five natural gas-fired combustion turbines capable of producing approximately 1,100 MWs, which would be located at the existing OCPP site.

If approved, the cost of this project is estimated to be approximately $1.2 billion.

• In April 2024, WE filed a request with the PSCW to add seven natural gas-fired RICE units near the Paris Generating Station.

The new RICE units would be fueled with natural gas and capable of producing approximately 128 MWs.

If approved, the cost of this project is estimated to be approximately $280 million.

• In April 2024, WE filed a request with the PSCW to construct the Rochester Lateral, which would supply additional natural gas service to the OCPP site.

The natural gas lateral would be built in Kenosha, Racine, and Milwaukee counties.

If approved, the cost of this project is estimated to be approximately $200 million.

• In April 2024, WE filed a request with the PSCW to construct an LNG facility which would be located on the OCPP site.

If approved, the facility would have a storage capacity of two Bcf and the cost of this project is estimated to be approximately $456 million.

• In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Dawn Harvest, a utility-scale solar-powered electric generating facility with a battery energy storage system.

If approved, the project will be located in Rock County, Wisconsin and once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and WE will own 50 MWs of battery storage of this project.

If approved, WE and WPS's combined share of the cost of this project is estimated to be approximately $409 million, with construction expected to be completed in 2028.

• In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire Saratoga, a utility-scale solar-powered electric generating facility with a battery energy storage system, and Ursa, a utility-scale solar-powered electric generating facility.

If approved, Saratoga will be located in Wood County, Wisconsin and Ursa will be located in Columbia County, Wisconsin.

Once fully constructed, WE and WPS will collectively own 135 MWs of solar generation and 45 MWs of battery storage of Saratoga and 180 MWs of solar generation of Ursa.

If approved, WE and WPS's combined share of the cost of Ursa is estimated to be approximately $406 million, with construction expected to be completed in 2027.

If approved, WE and WPS's combined share of the cost of Saratoga is estimated to be approximately $406 million, with construction expected to be completed in 2028.

• In September 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Badger Hollow Wind and to acquire Whitetail, two utility-scale wind-powered electric generating facilities.

If approved, Badger Hollow Wind will be located in Iowa and Grant counties, Wisconsin, and Whitetail will be located in Grant County, Wisconsin.

Once fully constructed, WE and WPS will collectively own 100 MWs of wind generation of Badger Hollow Wind and 60 MWs of wind generation of Whitetail.

If approved, WE and WPS's combined share of the cost of Badger Hollow Wind is estimated to be $320 million, with construction expected to be completed in 2027.

If approved, WE and WPS's combined share of the cost of Whitetail is estimated to be approximately $200 million, with construction expected to be completed in 2027.

• In October 2024, WE and WPS, along with an unaffiliated utility, filed a request with the PSCW to acquire and construct Good Oak and Gristmill, two utility-scale solar electric generating facilities.

If approved, both Good Oak and Gristmill will be located in Columbia County, Wisconsin.

Once fully constructed, WE and WPS will collectively own 88 MWs of solar generation of Good Oak and 60 MWs of solar generation of Gristmill.

If approved, WE and WPS's combined share of the cost of Good Oak is estimated to be $194 million and the cost of Gristmill is estimated to be approximately $130 million, with construction for both projects expected to be completed in 2028.

The construction of additional LNG facilities in Wisconsin has been proposed as part of our capital plan and would provide another approximately four Bcf of natural gas supply at an estimated cost of $940 million.

The facilities are expected to reduce the likelihood of constraint s on our natural gas distribution system during the highest demand days of winter.

As part of our capital plan, we plan to build additional natural gas-fired combustion turbines capable of producing approximately 675 MWs at an estimated cost of $960 million.

In addition, we plan to add natural gas-fired RICE units that would be capable of producing approximately 114 MWs at an estimated cost of $250 million.

In connection with several investigations it conducted, the DOC set duties on solar panels and cells imported from four southeast Asian countries.

See Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – United States Department of Commerce Complaints and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative,

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and Legal Matters – Uyghur Forced Labor Prevention Act for information on the potential impacts to our solar projects as a result of the duties set by the DOC and related USITC and DOC investigations, and CBP actions related to solar panels, respectively.

The expected in-service dates and costs identified above already reflect some of these impacts.

The construction of additional LNG facilities has been proposed as part of the 2024-2028 capital plan .

The facilities would provide approximately four Bcf of natural gas supply and are expected to reduce the likelihood of constraint s on the natural gas systems during the highest demand days of winter.

The total cost of the projects is estimated to be approximately $860 million .

During 2023, PGL continued work on the SMP, a project to replace approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure.

In November 2023, the ICC ordered PGL to pause spending on the SMP until the ICC has a proceeding to determine the optimal method of pipeline replacement and a prudent investment level.

The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last twelve months.

For more information, see Factors Affecting Results, Liquidity, and Capital Resources - Regulatory, Legislative, and Legal Matters - Future Illinois Proceedings.

On January 3, 2024, the ICC granted PGL a limited-scope rehearing, which includes the authorized spending for the completion of SMP projects that started in 2023 and the authorized spending for emergency repairs needed to ensure the safety and reliability of our delivery system.

As a result, PGL has suspended neighborhood work pending the results of the limited hearing.

See Note 26, Regulatory Environment, for more information on the SMP.

The non-utility energy infrastructure line item in the table above includ es WECI's previously announced investment in Maple Flats and the purchase in January 2024 of an additional 10% ownership interest in Samson I.

See Note 2, Acquisitions, for more information on these projects.

In November 2023, the ICC ordered PGL to pause spending on its SMP until the ICC had 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 in January 2024.

On February 20, 2025, the ICC issued an order setting expectations for PGL's prospective operations under its SMP.

For information on regulatory proceedings related to the SMP, see Note 26, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceedings.

The non-utility energy infrastructure line item in the table above includ es WECI's investment in Hardin III, which closed in February 2025.

See Note 2, Acquisitions, for more information on this project.

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $445 million from 2025 through 2027.

We do not expect to make any contributions to ATC Holdco during that period.

WEC's portion of the cost for MISO Tranche 1 is estimated to be approximately $330 million between 2024 and 2028.

WEC's portion of the investment in MISO Tranche 1 is estimated to be approximately $580 million between 2025 and 2029, a portion of which will be funded by ATC's cash from operations.

Tranche 1 is part of MISO's Long Range Transmission Planning initiative to upgrade the grid so that it can reliably accommodate for the shift in generation to lower-carbon resources.

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See Note 14, Long-Term Debt, for more information on our outstanding long-term debt, including a schedule of our long-term debt maturities over the next five years.

The following table summarizes our required interest payments on long-term debt (excluding finance lease obligations) as of December 31, 2023:

The following table summarizes our required interest payments on long-term debt as of December 31, 2024:

Interest Payments Due by Period

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Interest payments due on long-term debt $ 8,357.6 $ 805.2 $ 1,330.7 $ 1,014.9 $ 5,206.8

$ 7,966.6 $ 677.7 $ 1,155.5 $ 899.1 $ 5,234.3

(1) The interest due on our variable rate debt is based on the interest rates that were in effect on December 31, 2023.

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Common Stock Dividends

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See Note 24, Commitments and Contingencies, for more information, including our minimum future commitments related to these purchase obligations.

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In addition to our energy-related purchase obligations, we have commitments for other costs incurred in the normal course of business, including costs related to information technology services, meter reading services, maintenance and other service agreements for certain generating facilities, and various engineering agreements.

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We have various finance and operating lease obligations.

Our finance lease obligations primarily relate to power purchase commitments and land leases for our solar projects.

Our finance lease obligations primarily relate to land leases for our renewable generation projects.

Our operating lease obligations are for office space and land.

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These liabilities include AROs, liabilities for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes.

For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 24, Commitments and Contingencies, and Note 16, Income Taxes, respectively.

For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 16, Income Taxes, and Note 24, Commitments and Contingencies, respectively.

Off-Balance Sheet Arrangements

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See Note 13, Short-Term Debt and Lines of Credit, Note 19, Guarantees, and Note 23, Variable Interest Entities, for more information.

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Sources of Cash

We anticipate meeting our short-term and long-term cash requirements to operate our businesses and implement our corporate strategy through internal generation of cash from operations and access to the capital markets, which allows us to obtain external short-term borrowings, including commercial paper and term loans, and intermediate or long-term debt securities, as well as other types of securities.

In addition, in January 2024, we started issuing common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan.

We also anticipate issuing common equity through an at-the-market program in the future.

Accessing the capital markets allows us to obtain external short-term borrowings, including commercial paper and term loans, and issue intermediate or long-term debt securities, as well as other types of securities.

In 2024, we started issuing common equity through a combination of our employee benefit plans and stock purchase and dividend reinvestment plan, as well as through an at-the-market program.

Cash generated from operations is primarily driven by sales of electricity and natural gas to our utility customers, reduced by costs of operations.

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Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions.

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.

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 $6.4 million gain related to the early settlement.

Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper.

We recorded a $0.2 million gain related to the early settlement.

In December 2024, we redeemed the remaining $358.9 million outstanding principal at par, plus accrued interest, of our 2007 Junior Notes with the proceeds we received from the issuance of our 2024A Junior Notes and 2024B Junior Notes.

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In December 2024, pursuant to a tender offer, we repurchased $250.0 million aggregate principal amount of the $600.0 million outstanding of our 5.60% Senior Notes due September 12, 2026 and repurchased $150.0 million aggregate principal amount of the $450.0 million outstanding of our 1.80% Senior Notes due October 15, 2030, for $380.9 million, plus accrued interest, with proceeds received from issuing commercial paper.

As a result of the repurchase, we recorded a $16.5 million gain on debt extinguishment.

WEC Energy Group, WE, WPS, WG, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

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We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity under existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

See Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information about our credit facilities and debt securities.

See Note 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information about our common stock activity, commercial paper, credit facilities, and debt securities.

Investments in Outside Trusts

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For additional information, see Note 20, Employee Benefits.

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Capitalization Structure

The following table shows our capitalization structure as of December 31, 2024 and 2023, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our Junior Notes:

(in millions) Actual Adjusted Actual Adjusted

(in millions) Actual Adjusted (1)

Actual Adjusted (2)

Common shareholders' equity $ 12,395.0 $ 12,770.0 $ 11,724.2 $ 11,974.2

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Ratio of debt to total capitalization 61.7 % 60.6 % 61.3 % 60.5 %

Included in long-term debt on our balance sheets as of December 31, 2023 and 2022, is $500.0 million principal amount of the 2007 Junior Notes.

The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common shareholders' equity and $250.0 million to long-term debt.

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.

(1) Included in long-term debt on our Consolidated Balance Sheets as of December 31, 2024, was $750.0 million principal amount of WEC Energy Group's 2024 Junior Notes (2024A Junior Notes and 2024B Junior Notes, collectively) due 2055.

The adjusted presentation at December 31,

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2024 attributes $375.0 million of the Junior Notes to common equity and $375.0 million to long-term debt, similar to how the majority of rating agencies treat them.

(2) Included in long-term debt on our Consolidated Balance Sheets as of December 31, 2023, was $500.0 million principal amount of the 2007 Junior Notes.

The adjusted presentation at December 31, 2023 attributes $250.0 million of the 2007 Junior Notes to common equity and $250.0 million to long-term debt, similar to how the majority of rating agencies treat them.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP.

Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted to reflect the treatment of the 2007 Junior Notes by the majority of rating agencies.

Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted to reflect the treatment of the 2024 Junior Notes and 2007 Junior Notes by the majority of rating agencies.

Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

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We expect to be in compliance with all such debt covenants for the foreseeable future.

See Note 13, Short-Term Debt and Lines of Credit, Note 14, Long-Term Debt, and Note 11, Common Equity, for more information.

See Note 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information.

Credit Rating Risk

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Any credit ratings downgrade could impact our ability to access capital markets.

On May 2, 2023, S&P Global Inc.

affirmed WEC Energy Group’s ratings and revised its outlook to negative from stable, citing weakening financial measures.

S&P Global Inc.

upgraded WEC Energy Group’s outlook back to stable on November 21, 2023, following their review of our updated five year capital and financing plan.

The factors leading to the upgraded outlook included the maintenance of improving financial metrics and the expected reduction in our exposure to coal fired generation through the rest of the decade.

The ratings outlooks on our utilities remain stable.

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In June 2024, Moody's changed the rating outlook for PGL to negative from stable as a result of the November 2023 rate order and the May 2024 limited re-hearing.

The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets.

Moody's affirmed PGL's ratings including its Aa3 senior secured rating and its P-1 short term rating for commercial paper.

See Note 26, Regulatory Environment, for more information on the outcome of the rate order.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms.

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Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.

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Electric utility revenues in Wisconsin are regulated by the PSCW.

The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature.

No such legislation has been introduced in Wisconsin to date.

It is uncertain when, if at all, retail choice might be implemented in Wisconsin.

No such legislation has been introduced in Wisconsin to date, and it is uncertain when, if at all, retail choice might be implemented in Wisconsin.

Michigan has adopted a limited retail choice program.

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We are currently unable to predict the impact, if any, of potential future industry restructuring on our results of operations or financial position.

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Absent extraordinary circumstances, potential competitors are not allowed to construct competing natural gas distribution systems in the service territories for PGL and NSG.

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An interstate pipeline may seek to provide transportation service directly to our Illinois end users, which would bypass our natural gas transportation service.

However, PGL and NSG have anti-bypass tariffs approved by the ICC, which allow them to negotiate rates with customers that are potential bypass candidates to help ensure that such customers continue to use utility transportation service.

However, PGL and NSG have anti-bypass tariffs approved by the ICC, which allow them to negotiate rates

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with customers that are potential bypass candidates to help ensure that such customers continue to use utility transportation service.

Natural gas utilities in the state of Minnesota do not have exclusive franchise service territories and, as a matter of law and policy, natural gas utilities may compete for new customers.

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See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

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See Note 26, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Uncollectible Expense Adjustment Rider

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

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In May 2023, the ICC issued a written order on PGL's and NSG's 2018 UEA rider reconciliation.

The order requires a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively.

These amounts are being refunded over a period of nine months, which began on September 1, 2023.

In June 2023, the ICC denied PGL's and NSG's application requesting a rehearing of the ICC's May 2023 order.

In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC orders.

Their appeal is still pending.

The order required a $15.4 million and $0.7 million refund to ratepayers at PGL and NSG, respectively.

These amounts were refunded over a period of nine months, which began on September 1, 2023.

In July 2023, PGL and NSG petitioned the Illinois Appellate Court for review of the ICC order.

On November 7, 2024, the Illinois Appellate Court issued an opinion affirming the ICC order and the related disallowance.

PGL and NSG petitioned the Illinois Supreme Court on December 12, 2024 seeking review and reversal of the May 2023 order.

As of December 31, 2024, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years, which include 2019 through 2024, will be deemed recoverable by the ICC.

The combined annual costs of PGL and NSG included in

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the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million during these open reconciliation years.

Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Qualifying Infrastructure Plant Rider

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP.

This rider, which was in effect until December 1, 2023, continues to be 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.

In addition, costs incurred during 2023 under the QIP rider are also still subject to reconciliation and review.

Annual costs included in PGL's QIP rider have ranged from $192 million to $348 million.

As of December 31, 2023, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years, which include 2016 through 2023, will be deemed recoverable by the ICC.

Disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

See Note 26, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

Future Illinois Proceedings

In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its SMP until the ICC completes a proceeding to determine the optimal method for replacing aging natural gas infrastructure and a prudent investment level.

The ICC initiated the proceeding on January 31, 2024, and the proceeding is expected to last 12 months.

In addition, the ICC ordered staff to develop a plan for a "Future of Gas" proceeding.

The goal of this proceeding will be to explore the issues involved with decarbonization of the gas distribution system in Illinois and recommend any future ICC action or legislative changes needed.

It will include the formal exploration and consideration of the role of natural gas in the future, including in the context of the state’s environmental and energy policy goals.

The proceeding will include a broad range of stakeholders, including Illinois utilities and other interested parties.

Once initiated, the “Future of Gas” proceeding is expected to last at least one year.

At this time, we cannot predict the ultimate outcome of these proceedings or the resulting impact to our natural gas operations in Illinois.

Future natural gas investment opportunities in Illinois could be negatively impacted depending upon the outcomes.

In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs.

PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on and of these investments.

The charge was recorded on the income statement as a $12.9 million reduction in revenues for the amounts previously collected from customers, a $12.1 million increase to operating expenses for the impairment of PGL's property, plant, and equipment, and a $0.3 million increase to interest expense related to the amounts due to customers.

On October 25, 2024, PGL filed a petition with the Illinois Appellate Court for review of the ICC's August order.

In March 2024, PGL filed its 2023 reconciliation with the ICC, which, along with the reconciliations from 2017 through 2022, is still pending.

The aggregate capital costs included in the rider during the open reconciliation years, which include 2017 through 2023, along with any previously recognized return on these investments, totaled approximately $2.8 billion as of December 31, 2024.

There can be no assurance that all of these costs and the previously recognized returns will be deemed recoverable by the ICC.

Further disallowances by the ICC, if any, could be material and have a material adverse impact on our results of operations.

Illinois Proceedings

In the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its SMP until the ICC completed 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 in January 2024.

On February 20, 2025, the ICC issued an order setting expectations for PGL's prospective operations under its SMP.

The ICC directed us to focus on replacing all cast and ductile iron pipe that has a diameter under 36 inches by January 1, 2035.

The ICC also indicated that failure to comply with this directive could subject us to civil penalties under Illinois statute.

We are evaluating the impact of this order on our operations and capital plan.

In March 2024, the ICC initiated a statewide "Future of Gas" proceeding.

The goal of this proceeding is to explore the issues involved with decarbonization of the gas distribution system in Illinois and recommend any future ICC action or legislative changes needed.

It includes the formal exploration and consideration of the role of natural gas in the future, including in the context of the state’s environmental and energy policy goals.

The proceeding includes a broad range of stakeholders, including Illinois utilities and other interested parties.

The “Future of Gas” proceeding is expected to be completed in 2026.

At this time, we cannot predict the ultimate outcome of this proceeding or the resulting impact to our natural gas operations in Illinois.

Future natural gas investment opportunities in Illinois could be negatively impacted depending upon the outcome.

See Note 26, Regulatory Environment, for more information regarding the November 2023 ICC rate order.

Chicago Decarbonization Efforts

The CABO was introduced at a meeting of the Chicago city council held on January 24, 2024.

The CABO was introduced at a meeting of the Chicago city council held in January 2024.

If approved, this ordinance would set an indoor emissions standard that would require zero-to-low-emission energy systems in newly built commercial and residential buildings and major building additions in the city of Chicago.

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If the resolution is passed, this analysis would need to be completed prior to the adoption of any decarbonization initiatives, such as the CABO.

If approved by the city council, the CABO is expected to become effective one year after the approval date.

PGL's future natural gas operations could be materially adversely impacted if the CABO is passed.

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If approved by the city council, the CABO is expected to become effective one year after the approval date.

PGL's future natural gas operations could be materially adversely impacted if the CABO is passed.

Petitions Before PSCW Regarding Third-Party Financed Distributed Energy Resources

In May 2022, two petitions were filed with the PSCW requesting a declaratory ruling that the owner of a third-party financed DER is not a "public utility" as defined under Wisconsin law and, therefore, is not subject to the PSCW’s jurisdiction under any statute or rule regulating public utilities.

The parties that filed the petitions provide financing to their customers for installation of DERs (including solar panels and energy storage) on the customer’s property.

In May 2022, a petition was filed with the PSCW requesting a declaratory ruling that the owner of a third-party financed DER is not a "public utility" as defined under Wisconsin law and, therefore, is not subject to the PSCW’s jurisdiction under any statute or rule regulating public utilities.

The party that filed the petition provides financing to its customers for installation of DERs (including solar panels and energy storage) on the customer’s property.

A DER is connected to the host customer’s utility meter and is used for the customer’s energy needs.

It may also be connected to the grid for distribution.

In July 2022, the PSCW found that the specific facts and circumstances merited the opening of a docket for each petition to consider whether to grant all or part of the requested declaratory ruling.

In December 2022, the PSCW granted one petitioner’s request for a declaratory ruling, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law.

The ruling was limited to the specific facts and circumstances of the lease presented in that petition.

A petition by the WUA to reopen or rehear the case expired without action by the PSCW.

The WUA has filed an appeal which is pending consideration by the circuit court.

The second petition was denied.

Although the finding in the first petition was limited to the specific facts and circumstances of the lease presented in that petition, similar findings or a broader policy position could adversely impact our business operations.

Climate and Equitable Jobs Act

On September 15, 2021, the state of Illinois signed into law the Climate and Equitable Jobs Act.

This legislation includes, among other things, a path for Illinois to move towards 100% clean energy, expanded commitments to energy efficiency and renewable energy, additional consumer protections, and expanded ethics reform.

The provisions in this legislation that had the potential to have the most significant financial impact on PGL and NSG related to the new consumer protection requirements.

Effective September 15, 2021, the new legislation prohibits utilities from charging customers a fee when they elect to pay for service with a credit card.

Utilities are now required to incur these expenses and seek recovery through a rate proceeding or by establishing a recovery mechanism.

In December 2021, the ICC approved the use of a TPTFA rider for PGL.

The TPTFA rider allowed PGL to recover the costs incurred for these third-party transaction fees prior to them being included in PGL's base rates.

Effective December 1, 2023, PGL began recovering these costs through its base rates.

See Note 26, Regulatory Environment, for more information on the TPTFA rider.

NSG has been recovering costs related to these third-party transaction fees through its base rates since September 15, 2021.

In accordance with the new legislation, effective January 1, 2023, natural gas utilities are no longer allowed to charge late payment fees to certain low-income residential customers.

As a result of the ICC's November 2023 rate orders, we do not expect this legislation to have a significant impact on our results of operations.

In December 2022, the PSCW granted the petitioner’s request for a declaratory ruling in part, finding that the owner of the third-party financed DER at issue in the petitioner’s brief is not a public utility under Wisconsin law, but declining to issue the petitioner’s request for a broader declaratory ruling that the petitioner would not be regulated as a "public utility".

Upon appeal, in April 2024, the Dane County Circuit Court reversed the PSCW’s decision, finding that the PSCW erroneously interpreted the definition of "public utility," and the evidence did not support its determination that the lease at issue in the petition did not involve the sale of electricity to the "public" under Wisconsin law.

The case was remanded to the PSCW for further review.

Although the PSCW issued an order in June 2024 to reopen the docket to consider modifications, the project lease originally at issue was no longer going forward, and so in October 2024 the PSCW issued an order declining to issue any declaratory ruling.

Meanwhile, in June 2024, the party that filed the May 2022 PSCW petition appealed the Dane County Circuit Court’s April 2024 decision to the Wisconsin Court of Appeals.

That appeal was in briefing when the PSCW issued its October 2024 order, which left the Court of Appeals with no agency decision to review.

Based on this and the fact that the underlying project was no longer going forward, a motion to dismiss the appeal was granted by the Court of Appeals in February 2025.

At this time we do not expect any material impact on our business operations.

Uyghur Forced Labor Prevention Act

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The UFLPA establishes a rebuttable presumption that any imports wholly or partially manufactured in Xinjiang are prohibited from entering the United States.

While our suppliers were able to provide the CBP sufficient documentation to meet WRO compliance requirements, and we expect the same will be true for UFLPA purposes, we cannot currently predict what, if any, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and whether we will experience any further impacts to the timing and cost of solar projects included in our long-term capital plan.

While our suppliers have been able to provide the CBP sufficient documentation to meet WRO and UFLPA compliance requirements, and we expect the same will be true for subsequent projects, we cannot currently predict what, if any, long-term impact the UFLPA will have on the overall supply of solar panels into the United States and whether we will experience any further impacts to the timing and cost of solar projects included in our long-term capital plan.

In January 2025, the Department of Homeland Security announced the addition of several more Chinese businesses to the UFLPA, including five solar supply chain providers.

We are working to avoid doing business with these companies and remain in compliance with the UFLPA.

United States Department of Commerce Complaints

In February 2022, a California based company filed a petition (Antidumping and Countervailing Duties) with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia.

The petitioners claimed that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China and requested that the DOC conduct a country-wide inquiry into each of the four countries.

After investigation, in December 2022, the DOC announced its preliminary determination that certain companies are circumventing anti-dumping and countervailing duty orders on solar cells and modules from China.

The solar panel industry continues to experience uncertainty resulting from AD and CVD investigations involving four southeast Asian countries including Malaysia, Vietnam, Thailand, and Cambodia.

In August 2023, the DOC issued a final decision regarding an AD/CVD petition filed by a California-based company alleging that Chinese manufacturers were shifting products to the four southeast Asian countries to avoid tariffs required on products imported from China and requesting that the DOC conduct a country-wide inquiry into each country.

In its final decision, the DOC determined that circumvention was occurring in each of the four Southeast Asian countries noted above.

Duties began to be applied to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia after expiration of the 24-month tariff moratorium on June 6, 2024.

In addition, in response to its findings, the DOC promulgated new regulations that imposed enhanced duties in certain circumstances, including when the USITC determines there is a reasonable indication the domestic solar industry is materially or potentially injured because of imported products that violate certain fair trade laws.

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In August 2023, the DOC issued its final decision, substantially affirming its preliminary determination that circumvention was occurring in each of the four Southeast Asian countries noted above.

In its decision, the DOC affirmed that the Biden Administration’s current 24-month tariff moratorium will remain in effect until June 6, 2024, subject to certain use and installation requirements, at which time tariffs are expected to resume.

In December 2023, two U.S.

solar manufacturers filed a challenge to this moratorium in the United States Court of International Trade.

The Biden Administration also invoked the Defense Production Act to accelerate the production of solar panels in the U.S.;

however, the DOC’s ruling may have an adverse impact on the solar industry overall.

Additionally, the Biden Administration's actions did not address whether WROs applied to panels under previous complaints would be affected.

At this time, we do not expect this final ruling to have a material impact on our results of operations.

Infrastructure Investment and Jobs Act

In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over a five year period, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States.

We expect funding from this Act will support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid.

Funding in the Act should also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future.

We believe the Infrastructure Investment and Jobs Act will accelerate investment in projects that will help us meet our net zero emission goals to the benefit of our customers, the communities we serve, and our company.

Inflation Reduction Act

In August 2022, President Biden signed into law the IRA, which provides for $258 billion in energy-related provisions over a 10-year period.

In April 2024, a coalition of several U.S.

producers of solar panels filed a petition with the DOC requesting new tariffs on imports from the same four Southeast Asian countries.

The group alleged that some Chinese companies had moved their solar operations to avoid penalties implemented after the expiration of the moratorium.

In May 2024, in response to the petition, the DOC initiated a new AD/CVD investigation of solar panels from the four southeast Asian countries.

In April 2024, the USITC began a preliminary investigation and, in June 2024, issued a preliminary determination that there is a reasonable indication imports of solar panels from the four Southeast Asian countries have caused injury to the U.S.

solar industry.

Based on the USITC’s preliminary decision, the DOC began an investigation and, in October and November 2024, announced preliminary affirmative determinations in its CVD and AD investigations, respectively, and set preliminary duties on imports from the four southeast Asian countries.

The DOC and USITC are expected to make final determinations in the second quarter of 2025, which could result in enhanced duties, including retroactive duties in certain circumstances.

The Biden Administration invoked the Defense Production Act to accelerate the production of solar panels in the U.S.;

however, final determinations by the DOC and/or USITC may have an adverse impact on the solar industry overall.

Additionally, there is uncertainty with respect to how WROs applied to panels under previous complaints would be affected.

As a result of these investigations, the solar industry overall has experienced higher costs of materials as well as delays.

Some of these impacts have already been reflected in the estimated cost and in-service dates for certain of our solar projects.

We are continuing to assess the potential impact from the preliminary determinations on our business and results of operations.

Infrastructure Investment and Jobs Act and Inflation Reduction Act

In November 2021, former President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over a five year period, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States.

We believe that funding from this Act would support the work we are doing to reduce GHG emissions, increase EV charging, and strengthen and protect the energy grid.

Funding in the Act could also help to expand emerging technologies, like hydrogen and carbon management, as we continue the transition to a clean energy future to the benefit of our customers, the communities we serve, and our company.

In August 2022, former President Biden signed into law the IRA, which provides for $258 billion in energy-related provisions over a 10-year period.

The provisions of the IRA are intended to, among other things, lower gasoline and electricity prices, incentivize domestic clean energy investment, manufacturing, and production, and promote reductions in carbon emissions.

We believe that we and our customers can benefit from the IRA’s provisions that extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, add an option to claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and its provision to allow companies to transfer tax credits generated from renewable projects.

Under this new IRA transferability option, we entered into a sales agreement in September 2023 to sell substantially all of our 2023 PTCs to a third party.

See Note 1(q), Income Taxes, for more information about the impact of these sales.

Under the IRA transferability option, we entered into an agreement in 2024 to sell substantially all of our 2024 PTCs to a third party.

Additionally, in October 2024, we entered into an agreement to sell the majority of our 2025 PTCs to a third party.

See Note 1(q), Income Taxes, for more information about the impact of these sales during 2024.

The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases.

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Overall, we believe the IRA will help reduce our cost of investing in projects that will support our commitment to reduce emissions and provide customers affordable, reliable, and clean energy over the longer term.

In January 2025, pursuant to an executive order issued by the new presidential administration, disbursement of funds under these two Acts was paused until agency heads can determine whether grants, loans contracts, and other disbursements are consistent with the new administration's energy policy.

Agency heads must consult with the Office of Management and Budget and the National Economic Council prior to any funding being disbursed.

The new policy encourages use of domestic energy sources including oil, natural gas, coal, hydropower, biofuels, critical minerals, and nuclear, promotes consumer choice of goods and appliances, aims to boost American workers and businesses, eliminates the EV mandate, and limits regulations that apply to the energy industry.

The executive order did not impact the IRA's provisions for tax credits and the transferability option.

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Return on Equity Incentive for Membership in a Transmission Organization

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When two complaints were filed arguing the base ROE for MISO transmission owners, including ATC, was too high, the FERC started analyzing the base ROE for these transmission owners.

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The base ROEs listed in the two ROE complaint sections below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization.

The first of these complaints is discussed below.

For information on the second complaint, see Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – American Transmission Company Allowed Return on Equity Complaints in our 2023 Annual Report on Form 10-K

The base ROEs listed in the ROE complaint section below do not include the 50 basis point ROE incentive currently provided for membership in a transmission organization.

See the Return on Equity Incentive for Membership in a Transmission Organization section above for more information on this incentive.

First Return on Equity Complaint

Return on Equity Complaint

In November 2013, a group of MISO industrial customers filed a complaint with the FERC asking that the FERC order a reduction to the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%.

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The refunds resulting from these orders and opinion are also described below.

• Orders Issued by the FERC

◦ September 2016 Order – On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by the first complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.

◦ November 2019 Order – On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE.

• September 2016 FERC Order – On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by this complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.

• November 2019 FERC Order – On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE.

In this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions.

The FERC also rejected the use of the risk premium model as part of its base ROE methodology in this order.

The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the first complaint.

The FERC's modified methodology further reduced the base ROE for all MISO transmission owners, including ATC, to 9.88% for the period covered by the complaint.

In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

◦ May 2020 Order – On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order.

• May 2020 FERC Order – On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order.

In this May 2020 Order, the FERC made additional revisions to its base ROE methodology, including reinstating the use of the risk premium model.

The additional revisions made by the FERC increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02% for the period covered by the first complaint.

Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.

◦ November 2020 Order – In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.

◦ Refunds – Due to the base ROE changes resulting from these FERC orders, ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020.

In January 2022, ATC completed providing WE, WPS, and UMERC with the net refunds related to the transmission costs they paid during the period covered by the first complaint.

• November 2020 FERC Order – In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.

• Refunds for FERC Orders Issued Prior to October 2024 – Due to the base ROE changes resulting from the FERC orders issued prior to October 2024, ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020.

In January 2022, ATC

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completed providing WE, WPS, and UMERC with the net refunds related to the transmission costs they paid during these periods.

The refunds were applied to WE's and WPS's PSCW-approved escrow accounting for transmission expense.

• Opinion Issued by the D.C.

Circuit Court of Appeals

◦ August 2022 Decision – Since several petitions for review were filed with the D.C.

• August 2022 D.C.

Circuit Court of Appeals Opinion – Since several petitions for review were filed with the D.C.

Circuit Court of Appeals concerning this ROE complaint, the D.C.

Circuit Court of Appeals issued an opinion on August 9, 2022, addressing these petitions.

In its August 2022 Decision, the D.C.

In its August 2022 Opinion, the D.C.

Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order.

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Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings.

As of December 31, 2023, the FERC had not provided a ruling in response to the August 2022 Decision issued by the D.C.

Circuit Court of Appeals.

◦ Refunds – Since the FERC is required to conduct more proceedings, additional refunds could still be required for the 15-month period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 until the date of any future order.

Therefore, ATC recorded a liability on its financials for these potential refunds, which reduced our equity earnings from ATC by $18.6 million during the third quarter of 2022.

The liability recorded by ATC is based on a 9.88% base

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ROE for the first complaint period.

If it is ultimately determined a refund is required for the first complaint period, we would not expect any such refund to have a material impact on our financial statements or results of operations in the future.

In addition, WE, WPS, and UMERC would be entitled to receive a portion of the refund from ATC for the benefit of their customers.

Second Return on Equity Complaint

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015.

To resolve this complaint, the following orders and opinion were issued by the FERC and the D.C.

Circuit Court of Appeals.

The orders and opinion discussed below are the same orders and opinion described above in the first complaint section.

• Orders Issued by the FERC

◦ November 2019 Order – Similar to the first complaint, the November 2019 Order stated the newly calculated base ROE of 9.88% was also reasonable for the period covered by the second complaint, February 12, 2015 through May 10, 2016.

However, in the November 2019 Order, the FERC relied on certain provisions of the Federal Power Act to dismiss the second complaint and to determine refunds were not allowed for this period.

◦ May 2020 Order – In its May 2020 Order, the FERC stated the newly calculated base ROE of 10.02% was also reasonable for the period covered by the second complaint.

However, the FERC relied on the same provisions of the Federal Power Act to again dismiss the complaint and to determine refunds were not allowed for this period.

In addition, the FERC denied in its May 2020 Order the requests to rehear both the dismissal of the second complaint and the determination that no refunds are allowed for the second complaint period.

• Opinion Issued by the D.C.

Circuit Court of Appeals

◦ August 2022 Decision - The August 2022 Decision issued by the D.C.

Circuit Court of Appeals affirmed both the FERC’s dismissal of the second complaint and the FERC’s finding that no refunds are allowed for the second complaint period.

Therefore, during the third quarter of 2022, we reduced the liability previously recorded for the potential refunds related to the second complaint period by $39.1 million, which increased our equity earnings from ATC.

As a result, ATC recorded a reserve for potential refunds based on a 9.88% base ROE.

• October 2024 FERC Order – In response to the August 2022 D.C.

Circuit Court of Appeals Opinion, the FERC issued an order on October 17, 2024.

The FERC’s October 2024 Order removed the risk premium model from the base ROE methodology and required MISO transmission owners, including ATC, to adopt a 9.98% base ROE for the period covered by the complaint.

• Refunds for FERC Order Issued in October 2024 – Prior to the October 2024 FERC order, the base ROE for MISO transmission owners was 10.02% based on the November 2020 FERC order.

Since the October 2024 FERC order changed the base ROE to 9.98%, ATC will be providing additional refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through October 17, 2024.

Therefore, ATC is expected to provide WE, WPS, and UMERC with refunds related to the transmission costs they paid during these two refund periods.

The refunds will be applied to WE’s and WPS’s PSCW-approved escrow accounting for transmission expense.

Due to the change between the 9.88% base ROE originally reflected in ATC's reserve and the 9.98% base ROE authorized in the October 2024 FERC Order, ATC reduced its refund liability, which increased our pre-tax equity earnings by $20.1 million during the fourth quarter of 2024.

Environmental Matters

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We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate.

These risks, described in further detail below, include but are not limited to:

These include, but are not limited to, the risks described below.

In addition, there is continuing uncertainty over the impact that the ongoing regional and international conflicts, including those in Ukraine, Israel and in other parts of the Middle East, will have on the global economy, supply chains, and fuel prices.

Commodity Costs

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Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.

Higher commodity costs combined

Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.

See Note 5, Credit Losses, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

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with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.

See Note 5, Credit Losses, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

Our utilities' rates are based upon estimated normal temperatures.

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A summary of actual weather information in our utilities' service territories during 2024, 2023, and 2022, as measured by degree days, can be found in Results of Operations.

Our utility operations (primarily our electric utility operations) and the operations of WECI, can be negatively impacted from storms.

High wind conditions, lightning, hail, and flooding from these storms can result in downed wires and poles, as well as damage to wind and solar generation facilities and other operating equipment.

This can result in us incurring significant restoration costs at our utilities and at WECI, including lost revenue to customers.

Our utilities' rates include a fixed amount for expected storm restoration costs.

To the extent actual storm restoration costs are above what is included in these rates, earnings at our utility operations are negatively impacted and it becomes more difficult to achieve our authorized ROEs.

Similarly, restoration costs and lost revenue from storms negatively impacts operations and earnings at our non-utility WECI renewable generation facilities.

Interest Rates

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Additionally, future contributions can also be affected by the investment returns on trust fund assets.

The financial risks associated with investment returns are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 and 2024, as required by the December 2022 rate order issued by the PSCW.

The financial risks associated with investment returns are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 through 2026, as required by the December 2022 and December 2024 rate orders issued by the PSCW.

As a result, our Wisconsin utilities defer as a regulatory asset or liability, the difference between actual pension and OPEB costs and those included in rates until recovery or refund is authorized in a future rate proceeding.

We also believe that the financial risks associated with investment returns would be partially mitigated at our other utilities through future rate actions by regulators.

See Note 26, Regulatory Environment, for more information on 2023 and 2024 rates at our Wisconsin utilities.

The fair value of our trust fund assets and expected long-term returns were approximately:

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Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

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Economic Conditions

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We monitor the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance costs, and other costs in order to minimize inflationary effects in future years, to the extent possible, through pricing strategies, productivity improvements, and cost reductions.

We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the necessary materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan.

We monitor the global supply chain, and related disruptions, in order to ensure we are able to procure the materials and other resources necessary to both maintain our energy services in a safe and reliable manner and to grow our infrastructure in accordance with our capital plan.

For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below.

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Risk Factors – Risks Related to the Operation of Our Business – We are actively involved with multiple significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

Risk Factors – Risks Related to Economic and Market Volatility – Fluctuating commodity prices could negatively impact our operations.

Risk Factors – Risks Related to Economic and Market Volatility – The fluctuation in demand for certain commodities and their respective prices could negatively impact our operations.

For additional information concerning other risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A.

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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 our regulators.

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Future recovery of regulatory assets, including the timeliness of recovery and our ability to earn a reasonable return, is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness.

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If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings.

Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or

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refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application.

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See Note 1(k), Asset Impairment, for our policy on accounting for abandonments and recently completed plant subject to disallowance.

Performing an impairment evaluation involves a significant degree of estimation and judgment by management in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted future cash flows.

An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

The fair value of the asset is assessed using various methods, including recent comparable third-party

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sales for our nonregulated operations, internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

The fair value of the asset is assessed using various methods, including recent comparable third-party sales for our nonregulated operations, internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

See Note 7, Property, Plant, and Equipment, for more information on our generating units probable of being retired.

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Rate of return on plan assets 0.5 N/A (4.1)

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The discount rates are selected based on hypothetical bond portfolios consisting of noncallable, high-quality corporate bonds across the full maturity spectrum.

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We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios.

The assumed long-term rate of return on pension plan assets was 6.62% in 2023 and

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6.88% in 2022 and 2021.

The assumed long-term rate of return on pension plan assets was 6.61%, 6.62%, and 6.88%, in 2024, 2023 and 2022, respectively.

The actual rate of return on pension plan assets, net of fees, was 4.75%, 9.23%, and (14.03)%, in 2024, 2023, and 2022, respectively.

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Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.

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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 7. Management’s Discussion and Analysis