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Item 7. Management’s Discussion and Analysis

2026-02-20 compared with 2025-02-21 · 446 added, 723 removed, 829 unchanged (59% of the section changed)

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CORPORATE DEVELOPMENTS

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a for-profit electric transmission company regulated by FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin that it leases to WE), Bluewater (which owns underground natural gas storage facilities in Michigan), and WECI, which holds ownership interests in several renewable generating facilities.

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin that it leases to WE), Bluewater (which owns underground natural gas storage facilities in Michigan), and WECI (which holds ownership interests in several renewable generating facilities).

Corporate Strategy

Our goal is to continue to build and sustain long-term value for our shareholders and customers by focusing on the fundamentals of our business:

environmental stewardship;

operating efficiency;

financial discipline;

exceptional customer care;

We are working to build and sustain long-term value for our shareholders and customers by supporting economic growth in our region while focusing on the fundamentals of our business:

reliability, operating efficiency, financial discipline, environmental stewardship, exceptional customer care, and safety.

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.

It is a plan premised upon maintaining superior reliability, delivering savings for customers, and growing our investment in the future of energy.

Throughout our strategic planning process, we take into account important developments, risks and opportunities, including new technologies, customer preferences and affordability, energy resiliency efforts, and sustainability.

Creating a Sustainable Future

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.

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

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

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.

In addition to retiring these older, fossil-fueled plants, we expect to invest approximately $9.1 billion from 2025-2029 in regulated renewable energy in Wisconsin.

Our plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments:

Supporting Economic Growth Within Our Communities

Economic growth continues in our Wisconsin service territories.

Companies are investing in major projects, including data centers and modern manufacturing facilities.

We anticipate electric demand growth in the years ahead from these economic developments.

Microsoft has announced plans to invest over $20 billion in data centers in southern Wisconsin over the next several years, and we expect up to 2.6 GWs of load growth in the Milwaukee-to-Chicago corridor through 2030.

Additionally, Vantage Data Centers plans to develop a large data center campus in Port Washington that is forecasted to add 1.3 GWs of demand through 2030.

This site has the potential to add an incremental 2.2 GWs, for a total of up to 3.5 GWs over time.

We are working closely with these large customers to provide power to meet this substantial projected demand.

In 2025, we submitted a proposal to the PSCW for new VLC and Bespoke Resources tariffs.

The proposed tariffs specifically address the unique needs of VLCs while protecting our other customers and shareholders.

See Note 26, Regulatory Environment, for more information on the VLC and Bespoke Resources tariffs.

To meet the forecasted electric demand growth in the years ahead, greater capacity will be required to provide affordable, reliable, and clean energy for our communities.

Our capital plan addresses that demand with a range of planned investments in natural gas-fired generation, renewables, and battery storage.

We plan on investing approximately $5.4 billion from 2026 to 2030 in a combination of efficient natural gas-fired generation, including:

• 3,300 MWs of CTs (we plan on constructing a new natural gas lateral pipeline to support the CTs planned at our OCPP site);

• 180 MWs of RICE natural gas-fueled generation.

We expect to invest approximately $12.6 billion from 2026 to 2030 in regulated renewable energy in Wisconsin.

Our plan is to build and own zero-carbon-emitting renewable generation facilities that are anticipated to include the following investments:

• 3,850 MWs of utility-scale solar;

• 900 MWs of wind;

• 2,130 MWs of battery storage;

• 555 MWs of wind.

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

Our capital plan also reflects the planned retirement of our older, fossil-fueled generation, which we expect to replace with the natural gas-fired generation and zero-carbon-emitting renewables discussed above.

These retirements are intended to address compliance with EPA regulations established under the CAA, as well as contribute to meeting our goal to reduce CO 2 emissions from

2025 Form 10-K 47

WEC Energy Group, Inc.

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

• 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.

The Solar Now pilot is expected to add a total of 35 MWs of solar generation to WE's portfolio, allowing non-profit and governmental entities, as well as commercial and industrial customers, to site utility owned solar arrays on their property.

Under this program, WE has energized 29 Solar Now projects and currently has another one under construction, together totaling more than 30 MWs.

The second program, the DRER pilot, is designed to allow large commercial and industrial customers to access renewable resources that WE would operate.

The DRER pilot is intended to help these larger customers meet their sustainability and renewable energy goals, and could add up to 35 MWs of renewables to WE's portfolio.

In July 2023, the PSCW approved the Renewable Pathway Pilot, the third renewable energy program.

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.

In October 2021, subject to the receipt of any necessary regulatory approvals, we pledged to expand the EV charging network within the service territories of our electric utilities.

In doing so, we joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest.

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 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 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.

our electric generation.

Our long-term goal is to achieve net carbon neutral electric generation by the end of 2050.

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

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

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

Additionally, we have 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 900 MWs of additional coal-fired generation by the end of 2031, which includes the planned retirements of OCPP Units 7 and 8 and Weston Unit 3.

In conjunction with our new capital plan, we and the other co-owners of Columbia Units 1 and 2 currently plan to continue coal operations at these units through at least 2029, and continue to evaluate the conversion of both units to natural gas.

See Note 7, Property, Plant, and Equipment, for more information related to Columbia Units 1 and 2 and our planned power plant retirements.

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

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

In 2023, we began transporting the output of local dairy farms onto our natural gas distribution systems in Wisconsin.

The RNG supplied is replacing higher-emission methane from natural gas that would have entered our pipes.

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 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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WEC Energy Group, Inc.

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.

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

• The PSCW approved WE's request to construct an LNG facility with a storage capacity of two Bcf, which will be located on the OCPP site.

In addition, 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.

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

• 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 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.

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

In a limited-scope rehearing of this order, PGL was authorized spending for completion of projects that had started in 2023.

In February 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure.

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

PGL is working to retire this cast and ductile iron pipe through its PRP.

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

• Our capital plan includes $2.9 billion of investments in BESSs from 2026 to 2030, which are intended to capture excess power and release it during peak demand or when power is limited due to weather or other unexpected disruptions.

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

We expect to spend approximately $4.5 billion from 2025 to 2029 on reliability related projects with continued investment over the next decade.

We expect to spend approximately $7.1 billion and $4.7 billion on reliability related to natural gas and electric distribution projects, respectively, from 2026 to 2030, with continued investment over the next decade.

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

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WEC Energy Group, Inc.

Operating Efficiency

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.

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

An integrated system of smart meters, communication networks, and data management programs enables two-way communication between our utilities and our customers.

This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

We continue to focus on integrating the resources of all our businesses and finding the best and most efficient processes.

This program reduces the manual effort for customer connections and enhances outage management capabilities.

Through our multiyear Energy Delivery Program, we are planning to implement capabilities and standard processes for customer service, natural gas and electric operations, work management, and field operations.

This includes improvements to outage management, geographic information systems, and work and asset management systems, as well as the implementation of new capabilities through advanced distribution management systems.

We continue to focus on integrating the resources of all our businesses and improving our business processes to find the best and most efficient processes possible, including evaluating the use of AI tools.

We expect these efforts to continue to drive operational efficiency and to put us in a position to effectively support plans for future growth.

Financial Discipline

A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, and quality credit ratings.

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.

We work to earn allowed rates of return through a focus on cost control and strategic investment.

Our planned investment focus from 2026 to 2030 is in our regulated utilities and our investment in ATC.

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In addition, we currently forecast that our share of ATC's projected capital expenditures over the next five years will be approximately $4.1 billion.

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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WEC Energy Group, Inc.

For additional information regarding projects included in the $37.5 billion capital plan, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

See Note 2, Acquisitions, and Note 3, Disposition, for additional information on our recent and pending transactions.

Exceptional Customer Care

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We are committed to keeping our employees and the public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors.

To further protect public safety, we monitor the integrity of our distribution systems, have emergency response and business continuity plans in place, and provide key safety information to customers, contractors, and first responders.

Under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries.

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Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across our companies.

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WEC Energy Group, Inc.

Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

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.

The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2025 with the year ended December 31, 2024.

For a similar discussion that compares our results for the year ended December 31, 2024 with the year ended December 31, 2023, see Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations in Part II of our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 21, 2025.

Consolidated Earnings

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Year Ended December 31

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

(in millions, except per share data) 2025 2024 B (W)

Wisconsin $ 1,054.8 $ 863.1 $ 191.7

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Net income attributed to common shareholders $ 1,557.5 $ 1,527.2 $ 30.3

Diluted earnings per share

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

Diluted EPS $ 4.81 $ 4.83 $ (0.02)

2025 Compared with 2024

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The significant factors impacting the $30.3 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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WEC Energy Group, Inc.

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.

The significant factors impacting the $76.4 million decrease in earnings were:

• A $92.0 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense on both long-term and short-term debt.

This negative impact was partially offset by net gains from the investments held in the Integrys rabbi trust during 2023, compared with net losses during the same period in 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 $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 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.

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

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 in our 2023 Annual Report on Form 10-K.

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 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.

• A $191.7 million increase in net income attributed to common shareholders at the Wisconsin segment, driven by higher margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, higher retail sales volumes, and an increase in certain income tax benefits.

These positive impacts were partially offset by higher operating expenses, largely due to increases in depreciation and amortization expense, costs related to our power plants, transmission expense, and expense related to our earnings sharing mechanisms.

Lower other income, driven by a negative impact from the non-service components of our net periodic pension and OPEB costs, also partially offset the positive impacts to earnings.

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

• A $30.3 million increase in net income attributed to common shareholders at the non-utility energy infrastructure segment, driven by an increase in PTCs from our non-utility renewable generating facilities related to the acquisition of additional renewable generation facilities in the fourth quarter of 2024 and the first quarter of 2025.

This increase was partially offset by higher interest expense due to the issuance of long-term debt at WECI Energy Holding III in December 2024.

These increases in earnings were partially offset by:

• A $130.0 million decrease in net income attributed to common shareholders at the Illinois segment, driven by a $205.0 million pre-tax charge to income in 2025 due to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the UEA and QIP riders.

Partially offsetting this decrease was a year-over-year positive impact from a $25.3 million pre-tax charge to income in 2024 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.

• A $74.6 million increase in the net loss attributed to common shareholders at the corporate and other segment, driven by higher interest expense in 2025 and the year-over-year impact from the gain on debt extinguishment recorded in 2024.

A net loss from

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WEC Energy Group, Inc.

• 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 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 margins due to lower sales volumes and increases in depreciation and amortization and interest expense.

our equity method investments in technology and energy-focused investment funds during 2025, compared to net earnings in 2024, also contributed to the higher net loss.

Non-GAAP Financial Measures

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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, 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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WEC Energy Group, Inc.

The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 2025 was $1,054.8 million, representing a $191.7 million, or 22.2%, increase over the prior year.

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.

The higher earnings were driven by an increase in margins from the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, higher retail sales volumes, and an increase in certain income tax benefits.

Lower other income, driven by a negative impact from the non-service components of our net periodic pension and OPEB costs, also partially offset the positive impacts to earnings.

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

Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operating revenues $ 7,295.5 $ 6,330.5 $ 965.0

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

2025 Form 10-K 51

WEC Energy Group, Inc.

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

Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operation and maintenance not included in line items below $ 753.9 $ 659.6 $ (94.3)

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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 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.

This amortization drove the lower transmission expense during 2022.

During 2025 and 2024, $618.5 million and $565.3 million, respectively, of costs were billed to our electric utilities by transmission providers.

(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 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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WEC Energy Group, Inc.

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

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.

During 2025 and 2024, $125.1 million and $115.8 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 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.

2 unchanged sentences

Electric Sales Volumes (MWh - in thousands)

2024 2023 2022 2024 vs 2023 2023 vs 2022

2025 2024 B (W)

Customer class

14 unchanged sentences

Natural Gas Sales Volumes (Therms - in millions)

2024 2023 2022 2024 vs 2023 2023 vs 2022

2025 2024 B (W)

Customer class

4 unchanged sentences

Total sales in therms 3,244.0 2,910.2 333.8

2025 Form 10-K 52

WEC Energy Group, Inc.

Year Ended December 31

Weather (Degree Days) (1)

2024 2023 2022 2024 vs 2023 2023 vs 2022

WE and WG (1)

2025 2024 B (W)

Heating (6,351 Normal)

10 unchanged sentences

388 317 22.4 %

(1) Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

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

2024 Form 10-K 56

WEC Energy Group, Inc.

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

(1) Normal degree days are based on a 20-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations within each company's respective service territories.

Gross Margin GAAP and Utility Margin Non-GAAP

2 unchanged sentences

Year Ended December 31

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

(in millions) 2025 2024 B (W)

Electric revenues $ 5,547.4 $ 4,921.6 $ 625.8

18 unchanged sentences

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.

Gross margin (GAAP) at the Wisconsin segment increased $310.2 million during 2025, compared with 2024, and utility margin (non-GAAP) increased $536.2 million during 2025, compared with 2024.

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;

• A $402.4 million increase in margins driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025.

See Note 26, Regulatory Environment, for more information.

• A $135.5 million increase in margins related to higher retail sales volumes, driven by the impact of favorable weather during 2025, compared with 2024.

As measured by heating degree days, 2025 was 28.0% and 20.0% colder than 2024 in the Milwaukee area and Green Bay area, respectively.

As measured by cooling degree days, 2025 was 7.4% warmer than 2024 in the WPS service area.

2025 Form 10-K 53

WEC Energy Group, Inc.

• An $88.2 million increase in depreciation and amortization expense;

• A $46.2 million increase in other operating and maintenance related to our power plants;

• A $41.6 million increase in transmission expense;

• A $32.2 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.

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

• A $9.1 million increase in property and revenues taxes.

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

1 unchanged sentence

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.

• An $88.2 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $46.2 million increase 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 new renewable generation facilities placed in service during 2025.

• A $41.6 million increase in transmission expense as approved by the PSCW in our Wisconsin rate orders, effective January 1, 2025.

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

• A $32.9 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.

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

• A $32.2 million increase in electric and natural gas distribution expenses, driven by higher costs to maintain the distribution systems.

• A $15.9 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $12.4 million increase in expense driven by higher commitments made in 2025 to fund our charitable foundations.

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

• A $9.1 million increase in property and revenue taxes during 2025, compared with 2024, driven by a 2024 adjustment related to a sales tax audit at WE.

• A $6.2 million increase in environmental costs.

These increases in other operating expenses were partially offset by a $12.8 million decrease in benefit costs.

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

Other income, net at the Wisconsin segment decreased $50.1 million during 2025, compared with 2024, driven by an $83.6 million negative impact from the non-service components of our net periodic pension and OPEB costs.

In accordance with our December

2025 Form 10-K 54

WEC Energy Group, Inc.

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.

2024 PSCW rate orders, in 2025 we began amortizing our pension and OPEB costs that were previously deferred under escrow accounting.

During 2025, we amortized $48.4 million of the previously deferred non-service costs as we are now collecting these costs in rates.

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

This decrease in other income, net was partially offset by a $39.5 million positive impact from higher AFUDC-Equity due to continued capital investment.

Interest Expense

Interest expense at the Wisconsin segment increased $1.4 million during 2025, compared with 2024.

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

The increase was primarily due to the impact of long-term debt issuances in 2024 and 2025.

Partially offsetting this increase was long-term debt maturities for WE, WPS, and WG in 2024 and 2025.

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.

Also offsetting the increase was higher AFUDC-Debt due to continued capital investment, lower average short-term debt balances, and lower 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.

Income tax expense at the Wisconsin segment increased $5.7 million during 2025, compared with 2024, driven by higher pre-tax income.

This increase in income tax expense was partially offset by:

• A $23.3 million increase in PTCs;

• A $20.4 million increase in the benefit from the flow through of tax repairs in connection with the Wisconsin rate orders approved by the PSCW, effective January 1, 2025.

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.

• A $61.6 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 beyond the 2% price variance is generally deferred for future recovery or refund to customers.

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 in connection with the acquisition of the Whitewater facility, effective January 1, 2023.

These increases in margins were partially offset by:

• 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.

As measured by heating degree days, 2023 was 15.1% and 11.4% warmer than 2022 in the Milwaukee area and Green Bay area, respectively.

• A $25.1 million decrease in other revenues, primarily related to a FERC order in January 2023 that eliminated reactive power compensation MISO was required to pay to generators, including our electric utilities, as well as lower revenues from third-party use of our assets.

The decrease in reactive power revenues is substantially offset by a decrease in transmission expense related to a deferral of these revenues as a component of our transmission escrow, as approved by the PSCW in June 2023 and discussed below.

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

2024 Form 10-K 59

WEC Energy Group, Inc.

• 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)

Other operating expenses at the Wisconsin segment increased $273.4 million during 2023, compared with 2022.

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

• A $109.5 million increase in transmission expense as approved in the PSCW's 2023 rate orders, effective January 1, 2023.

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 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.

• A $62.7 million increase in regulatory amortizations and other pass through expenses, as discussed in the notes under the other operation and maintenance table above.

• A $33.3 million increase 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 $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 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.

These increases in other operating expenses were partially offset by:

• A $23.9 million decrease in expense primarily related to lower commitments made in 2023 to fund our charitable foundations.

• A $19.1 million increase in pre-tax gains on the sale of land, primarily at the site of our former Pleasant Prairie power plant during 2023.

• A $15.6 million decrease in electric and natural gas distribution expenses, driven by lower costs to maintain the distribution system and for storm restoration during 2023, compared with 2022.

• A $7.0 million decrease in expenses associated with the settlement of legal claims.

Other Income, Net

Other income, net at the Wisconsin segment increased $37.7 million during 2023, compared with 2022, driven by higher AFUDC-Equity due to continued capital investment.

See Note 27, Other Income, Net, for more information.

Interest Expense

Interest expense at the Wisconsin segment increased $45.1 million during 2023, compared with 2022.

The increase was primarily due to the impact of WE and WPS issuing long-term debt during the third and fourth quarters of 2022, respectively, and higher average short-term debt balances and increased short-term debt interest rates.

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 was amortized over a two-year period.

During 2023, WG amortized $4.1 million

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, 2025 was $122.1 million, representing a $130.0 million, or 51.6%, decrease from the prior year.

The decrease was driven by a $205.0 million pre-tax charge to income in 2025 due to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the UEA and QIP riders.

See Note 26, Regulatory Environment, for more information.

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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.

Income Tax Expense

Income tax expense at the Wisconsin segment decreased $10.1 million during 2023, compared with 2022.

The decrease was primarily due to a $23.1 million increase in PTCs and a $6.3 million increase in income tax benefits associated with AFUDC-Equity, both driven by continued capital investment.

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

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 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.

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) 2024 2023 2022 2024 vs 2023 2023 vs 2022

(in millions) 2025 2024 B (W)

Operating revenues $ 1,683.6 $ 1,602.4 $ 81.2

2 unchanged sentences

Other operation and maintenance 482.2 461.5 (20.7)

Impairment related to ICC disallowances 12.1 178.9 — 166.8 (178.9)

130.0 12.1 (117.9)

Depreciation and amortization 259.7 255.4 (4.3)

6 unchanged sentences

Net income attributed to common shareholders $ 122.1 $ 252.1 $ (130.0)

2024 Form 10-K 61

WEC Energy Group, Inc.

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

Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operation and maintenance not included in the line items below $ 323.2 $ 318.5 $ (4.7)

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Natural Gas Sales Volumes (Therms - in millions)

2024 2023 2022 2024 vs 2023 2023 vs 2022

2025 2024 B (W)

Customer Class

6 unchanged sentences

Weather (Degree Days) (1)

2024 2023 2022 2024 vs 2023 2023 vs 2022

2025 2024 B (W)

Heating (5,895 Normal)

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

5,869 4,848 21.1 %

(1) Normal heating degree days are based on a 12-year moving average of monthly temperature readings from National Oceanic and Atmospheric Administration weather stations throughout our Illinois service territories.

2025 Form 10-K 56

4 unchanged sentences

Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operating revenues $ 1,683.6 $ 1,602.4 $ 81.2

13 unchanged sentences

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.

Gross margin (GAAP) at the Illinois segment decreased $56.4 million during 2025, compared with 2024, and utility margin (non-GAAP) decreased $50.1 million during 2025, compared with 2024.

Both measures were driven by a $75.0 million decrease in revenues due to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the QIP and UEA riders.

See Note 26, Regulatory Environment, for more information.

This decrease in gross margin (GAAP) and utility margin (non-GAAP) was partially offset by:

• A $14.5 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.

• A $23.9 million increase in revenues at PGL due to continued capital investment in the SMP project under the QIP rider.

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.

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.

• A $12.9 million increase in revenues driven by a disallowance recorded in 2024 related to an ICC order received in August 2024 related to PGL's 2016 Rider QIP reconciliation prudency review, which required refunds to ratepayers for amounts previously collected related to the disallowance of certain capital costs.

See Note 26, Regulatory Environment, for more information.

• A $2.2 million increase in revenues related to the impact of the NSG rate order issued by the ICC, effective February 1, 2024.

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

• A $4.3 million increase in depreciation and amortization expense;

• A $3.7 million increase in costs associated with maintenance at the Manlove Gas Storage Field;

• A partially offsetting $4.4 million decrease in property and revenue taxes.

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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)

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

Other operating expenses at the Illinois segment increased $124.0 million, net of the $14.5 million impact of the riders referenced in the table above, during 2025, compared with 2024.

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

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

See Note 3, Dispositions, for more information.

• 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.

• A $130.0 million impairment related to PGL and NSG agreeing on the terms of a proposed settlement with the Illinois Attorney General that would resolve all open proceedings related to the QIP and UEA riders.

See Note 26, Regulatory Environment, for more information.

• A $7.4 million increase in expense primarily associated with the favorable settlement of a legal claim during 2024.

• A $4.3 million increase in depreciation and amortization expense, driven by assets being placed into service as we continue to execute on our capital plan.

• A $3.7 million increase in costs associated with maintenance at the Manlove Gas Storage Field.

These increases in operating expenses were partially offset by:

• A $43.8 million decrease in natural gas distribution and maintenance costs, primarily related to maintaining the natural gas infrastructure during 2023, compared with 2022.

• A $25.0 million decrease in expenses related to contributions to charitable projects supporting our customers and the communities within our service territories during 2023, compared with 2022.

• A $9.4 million decrease in expenses associated with the settlement of legal claims during 2022.

• An $8.7 million decrease in property and revenue taxes, primarily driven by lower property and use taxes.

• A $3.7 million decrease in customer service expense due to lower call center expense and metering costs.

• A $3.0 million decrease in benefit costs, primarily due to lower stock-based compensation expense related to plan performance during 2023.

Other Income, Net

Other income, net at the Illinois segment decreased $7.4 million during 2023, compared with 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs.

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

2024 Form 10-K 65

WEC Energy Group, Inc.

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

See Note 26, Regulatory Environment, for more information.

• A $4.4 million decrease in property and revenue taxes, driven by the invested capital tax.

Interest Expense

Interest expense at the Illinois segment increased $15.1 million during 2023, compared with 2022, driven by higher long-term debt balances related to incremental borrowings in both 2023 and 2022, primarily related to additional capital investment.

Also contributing to the increase was higher short-term debt interest rates.

Interest expense at the Illinois segment decreased $5.8 million during 2025, compared with 2024, due to lower average short-term debt balances, lower average short-term debt interest rates, and the impact of a series of PGL's first mortgage bonds maturing in November 2024.

Income Tax Expense

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The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 2025 was $60.8 million, representing a $6.3 million, or 11.6%, 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.

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 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.

The increase was driven by higher margins related to positive impacts from MGU's rate increase that was effective January 1, 2025, MERC's rate increase that was effective March 1, 2024, and an increase in retail sales volumes.

These increases in earnings were partially offset by higher operating expenses.

See Note 26, Regulatory Environment, for more information on the MGU and MERC rate increases.

2025 Form 10-K 58

WEC Energy Group, Inc.

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) 2024 2023 2022 2024 vs 2023 2023 vs 2022

(in millions) 2025 2024 B (W)

Operating revenues $ 527.5 $ 449.8 $ 77.7

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Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operation and maintenance not included in line item below $ 81.9 $ 76.8 $ (5.1)

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

2024 Form 10-K 66

WEC Energy Group, Inc.

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)

2024 2023 2022 2024 vs 2023 2023 vs 2022

2025 2024 B (W)

Customer Class

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Weather (Degree Days) (1)

2024 2023 2022 2024 vs 2023 2023 vs 2022

2025 2024 B (W)

Heating (7,888 Normal) 7,714 6,792 13.6 %

Heating (6,095 Normal) 6,126 5,083 20.5 %

(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.

(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 temperature readings from National Oceanic and Atmospheric Administration weather stations throughout their respective service territories.

2025 Form 10-K 59

WEC Energy Group, Inc.

Gross Margin GAAP and Utility Margin Non-GAAP

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Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operating revenues $ 527.5 $ 449.8 $ 77.7

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

2024 Form 10-K 67

WEC Energy Group, Inc.

2024 Compared with 2023

Gross margin (GAAP) increased $18.4 million during 2025, compared to 2024, and utility margin (non-GAAP) increased $30.0 million during 2025, compared to 2024.

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.

• A $10.5 million increase related to MGU's rate increase that was effective January 1, 2025, and MERC's rate increase that was

effective March 1, 2024.

• A $10.3 million increase related to higher sales volumes, driven by colder weather during 2025, compared to 2024.

As measured by heating degree days, 2025 was 13.6% and 20.5% colder than 2024 at MERC and MGU, respectively.

• A $5.3 million increase 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.

• A $3.3 million increase related to MGU's energy optimization program, which provides rebates, incentives, and energy efficiency education to customers.

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 $5.2 million increase in property and revenue taxes;

• A $3.6 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.

• A $2.8 million increase in depreciation and amortization.

2025 Form 10-K 60

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 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)

Other operating expenses at the other states segment decreased $0.5 million during 2023, compared with 2022.

The significant factors impacting the decrease in operating expenses were:

• A $1.8 million decrease in natural gas operations and customer service expense, driven by fewer operation and maintenance projects at MGU during 2023.

• A $1.6 million decrease in benefit costs, primarily due to lower stock-based compensation expense related to plan performance.

These decreases in other operating expenses were partially offset by a $2.4 million increase in depreciation and amortization related to continued capital investment.

Other Income, Net

Other income, net at the other states segment decreased $1.9 million during 2023, compared with 2022, driven by lower net credits from the non-service components of our net periodic pension and OPEB costs.

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

Other operating expenses at the other states segment increased $18.7 million during 2025, compared with 2024.

The significant factors impacting the increase in operating expenses were:

• A $5.3 million increase in operation and maintenance expense related to MERC's CIP program, which has an offsetting increase in margins.

• A $5.2 million increase in property and revenue taxes, driven by the year-over-year impact from a positive resolution of a use

tax audit at MGU during 2024.

• A $3.6 million increase in natural gas operations and customer service expense, driven by higher metering costs and call center expense at MERC and MGU.

• A $2.8 million increase in depreciation and amortization related to continued capital investment.

• A $1.4 million increase in bad debt expense, primarily at MERC.

MERC's bad debt expense was lower in 2024 due to reserve

adjustments related to improved loss rates.

Interest Expense

Interest expense at the other states segment increased $2.0 million during 2023, compared with 2022, primarily due to higher short-term debt interest rates.

Interest expense at the other states segment increased $2.8 million during 2025, compared with 2024, driven by the impact of MERC issuing long-term debt in April 2025 and MGU issuing long-term debt in October 2024 and April 2025.

This increase was partially offset by lower average short-term debt interest rates.

Income Tax Expense

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.

Income tax expense at the other states segment increased $2.3 million during 2025, compared with 2024, driven by an increase in pre-tax income.

Electric Transmission Segment Contribution to Net Income Attributed to Common Shareholders

Year Ended December 31

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

(in millions) 2025 2024 B (W)

Equity in earnings of transmission affiliates $ 215.8 $ 207.5 $ 8.3

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Net income attributed to common shareholders $ 147.6 $ 141.0 $ 6.6

2024 Compared with 2023

Equity in Earnings of Transmission Affiliates

Equity in earnings of transmission affiliates increased $8.3 million during 2025, compared with 2024.

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.

This increase was primarily due to continued capital investment by ATC.

A $3.6 million gain related to the sale of an investment at ATC Holdco in March 2025 also contributed to the increase.

Partially offsetting these increases was a $20.1 million increase in equity earnings recognized in 2024 related to the impact of a FERC order issued in October 2024 that addressed 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 $1.8 million during 2025, compared with 2024, 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.

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.

Income Tax Expense

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.

2025 Form 10-K 61

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Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operating income $ 405.3 $ 393.0 $ 12.3

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Income tax benefit (122.9) (82.4) 40.5

Net (income) loss attributed to noncontrolling interests 4.1 1.2 (0.4) 2.9 1.6

Net loss attributed to noncontrolling interests 3.2 4.1 (0.9)

Net income attributed to common shareholders $ 411.1 $ 380.8 $ 30.3

2024 Compared with 2023

Operating Income

Operating income at the non-utility energy infrastructure segment increased $12.3 million during 2025, compared with 2024, 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.

• A $26.4 million increase in operating income from new investments in several WECI renewable generation facilities made in late 2024 and early 2025.

• A $7.5 million positive impact due to lower transmission congestion that increased energy market prices.

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:

• 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.

• A $13.4 million positive revenue impact in 2022 from a sharing arrangement with one of our Blooming Grove customers resulting from strong energy prices.

These decreases in operating income were partially offset by:

• 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, a wind facility acquired in February 2023.

• A $15.9 million impairment loss recorded at Samson I, Delilah I, and Thunderhead related to storm damage.

• A $7.9 million increase in operation and maintenance expenses due primarily to a higher number of equipment repairs at our renewable generation facilities.

• A $2.2 million negative impact in 2025 related to the receipt of lower performance payments.

In addition to the above items at WECI, there was a $4.5 million positive impact from We Power due to continued capital investment.

Interest Expense

Interest expense at the non-utility energy infrastructure segment increased $25.4 million during 2023, compared with 2022, driven by a $16.1 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.

This intercompany interest expense is offset by higher intercompany interest income at the corporate and other segment and is eliminated in consolidation.

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

Interest expense at the non-utility energy infrastructure segment increased $23.4 million during 2025, compared with 2024, driven by the impact of WECI Energy Holding III issuing long-term debt in December 2024.

Income Tax Benefit

The income tax benefit at the non-utility energy infrastructure segment increased $40.5 million during 2025, compared with 2024.

The increase was primarily due to a $37.5 million increase in PTCs in 2023, driven by the acquisition of additional renewable generation facilities in the second half of 2022 and in the first quarter of 2023.

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

The increase was primarily due to an increase in PTCs that was related to the acquisition of additional renewable generation facilities in the fourth quarter of 2024 and the first quarter of 2025, and an IRS approved PTC rate increase, partially offset by lower production volumes.

2025 Form 10-K 62

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Year Ended December 31

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

(in millions) 2025 2024 B (W)

Operating loss $ (11.5) $ (11.3) $ (0.2)

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Net loss attributed to common shareholders $ (238.9) $ (164.3) $ (74.6)

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.

Other income, net at the corporate and other segment decreased $23.8 million during 2025, compared with 2024.

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

• A $15.1 million decrease due to net losses of $12.8 million from our equity method investments in technology and energy-focused investment funds during 2025, compared with net earnings of $2.3 million during 2024.

• A $6.6 million decrease in interest income, driven by the year-over-year negative impact from a $3.5 million gain recorded in 2024 related to the redemption of a long-term intercompany note WECI issued to WEC Energy Group.

This decrease in intercompany interest income was offset by lower intercompany interest expense at our non-utility energy infrastructure segment.

Lower interest income on cash balances of $3.4 million also contributed to the decrease in interest income.

• A $3.6 million decrease due to lower net gains from the investments held in the Integrys rabbi trust.

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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.

Interest expense at the corporate and other segment increased $49.0 million during 2025, compared with 2024, primarily due to the impact of long-term debt issuances in May and December 2024, as well as June and November 2025.

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.

Also partially offsetting the increase was lower than average short-term debt interest rates.

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.

Lower operating income at Wispark also contributed to the higher operating loss, driven by the 2022 positive impact from a payment on a note receivable that was previously written off due to uncertainty regarding its collectability and lower gains related to the sale of land and other assets.

Other Income, Net

Other income, net at the corporate and other segment increased $38.7 million during 2023, compared with 2022.

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

• 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.

• 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.

This intercompany interest income is offset by higher intercompany interest expense in our operating segments and is eliminated in consolidation.

These increases in other income, net were partially offset by a $3.5 million net loss from our equity method investments in technology and energy-focused investment funds during 2023, compared with $6.5 million of net earnings during 2022.

Interest Expense

Interest expense at the corporate and other segment increased $138.7 million during 2023, compared with 2022, primarily due to the impact of long-term debt issuances in September 2022, January 2023, and April 2023.

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

There was no gain on debt extinguishments during 2025, as we did not have an early settlement on any debt obligations.

In 2024, the gain on debt extinguishments was driven by the early retirement of a portion of both our 5.60% Senior Notes due September 12, 2026 and our 1.80% Senior Notes due October 15, 2030.

Also, during 2024, we recorded gains on redemptions and repurchases of our 2007 Junior Notes.

Income Tax Benefit

The income tax benefit at the corporate and other segment increased $22.6 million during 2023, compared with 2022, driven by a higher pre-tax loss.

This increase in the income tax benefit was partially offset by a $5.9 million decrease in excess tax benefits recognized related to stock option exercises.

LIQUIDITY AND CAPITAL RESOURCES

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.

The income tax benefit at the corporate and other segment increased $21.5 million during 2025, compared with 2024, driven by an increase in pre-tax loss.

2025 Form 10-K 63

WEC Energy Group, Inc.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion and analysis of our Liquidity and Capital Resources includes comparisons of our cash flows for the year ended December 31, 2025 with the year ended December 31, 2024.

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Net cash provided by operating activities increased $167.6 million during 2025, compared with 2024, driven by:

• 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.

• A $338.7 million increase in cash from higher overall collections from customers during 2025, compared with 2024.

This increase was driven by the impact of the Wisconsin rate orders approved by the PSCW, effective January 1, 2025, and higher sales volumes from favorable weather during 2025, compared with 2024.

• A $42.3 million increase in cash from lower payments for environmental remediation related to work completed on former manufactured gas plant sites during 2025, compared with 2024.

• A $36.5 million increase in cash from higher distributions from ATC during 2025, compared with 2024.

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

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

• 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.

• A $163.6 million decrease in cash from higher payments for operating and maintenance expenses.

During 2025, our payments were higher due to increased transmission costs, operating and maintenance costs related to our plants, and electric and natural gas distribution costs.

• A $72.8 million decrease in cash from higher payments for interest driven by higher amounts of outstanding long-term debt in 2025, compared with 2024, partially offset by lower payments for interest due to a decrease in short-term interest rates during 2025, compared with 2024.

• A $20.1 million decrease in cash driven by higher amounts of collateral paid to counterparties during 2025, compared with 2024, partially offset by lower realized losses on derivative instruments recognized during 2025, compared with 2024.

2025 Form 10-K 64

WEC Energy Group, Inc.

Investing Activities

Net cash used in investing activities increased $1,072.2 million during 2025, compared with 2024, driven by:

• A $1,617.0 million increase in cash paid for capital expenditures during 2025, compared with 2024, 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.

• The acquisition of a 90% ownership interest in Hardin III in February 2025 for $406.1 million, net of cash acquired of $0.2 million.

• A $96.9 million increase in capital contributions paid to transmission affiliates during 2025, compared with 2024.

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 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.

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

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

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

• 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.

• The acquisition of an additional 13.7% ownership interest in West Riverside in May 2024 for $97.9 million.

• A $31.7 million increase in cash received from ATC during 2025, compared with 2024, for the reimbursement of transmission infrastructure upgrades.

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

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Total capital expenditures $ 4,398.1 $ 2,781.1 $ 1,617.0

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.

The increase in cash paid for capital expenditures at the Wisconsin segment during 2025, compared with 2024, was driven by an increase in capital expenditures for the following:

renewable energy projects at WE, WPS, and UMERC;

CTs and an LNG facility at OCPP;

WE's and WPS's electric distribution systems;

and software to enhance productivity, collaboration, and overall efficiency across the company.

These increases in capital expenditures were partially offset by decreased payments for construction of WPS's service center completed in October 2024 and WG's LNG facility completed in February 2024.

The decrease in cash paid for capital expenditures at the Illinois segment during 2025, compared with 2024, was driven by lower payments related to PGL's upgrade of its natural gas delivery system.

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.

This decrease in capital expenditures was partially offset by increased capital expenditures at Manlove Gas Storage Field.

The increase in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2025, compared with 2024, was driven by an increase in capital expenditures related to new generator units at ERGS and PWGS.

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

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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.

Net cash provided by financing activities increased $1,056.3 million during 2025, compared with 2024, driven by:

• A $1,709.7 million increase in cash due to $806.9 million of net borrowings of commercial paper during 2025, compared with $902.8 million of net repayments of commercial paper during 2024.

• A $598.5 million increase in cash due to higher issuances of common stock during 2025, compared with 2024.

See Note 11, Common Equity, for more information.

• A $409.1 million increase in cash due to lower retirements of long-term debt during 2025, compared with 2024.

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

See Note 2, Acquisitions, for more information.

• A $15.4 million increase in cash related to a higher number of stock options exercised during 2025, compared with 2024.

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

• A $1,616.4 million decrease in cash due to lower issuances of long-term debt during 2025, compared with 2024.

• A $91.6 million decrease in cash due to higher dividends paid on our common stock during 2025, compared with 2024.

In January 2025, our Board of Directors increased our quarterly dividend by $0.0575 per share (6.9%) effective with the March 2025 dividend payment.

• 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 $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

For more information on our financing activities, see Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt.

For more information on our financing activities, see Note 11, Common Equity , Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt.

Cash Requirements

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Our significant cash requirements are discussed in further detail below.

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Significant Capital Projects

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

These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, inflation, and interest rates.

These factors include environmental and regulatory requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, economic trends, supply chain disruptions, inflation, and interest rates.

Our estimated capital expenditures and acquisitions for the next three years are reflected below.

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Total $ 5,018.1 $ 6,949.5 $ 6,965.6

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

These upgrades include addressing our aging infrastructure, system hardening, and the AMI program.

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 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 located in Kenosha County, Wisconsin.

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 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 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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• 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.

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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.

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

In addition, o ur utilities continue to upgrade their electric and natural gas distribution systems to enhance reliability.

Below are the anticipated amounts for the next three years for generation, LNG, and distribution projects that are proposed or currently underway.

(in millions) 2026 2027 2028

Solar $ 734.3 $ 1,693.6 $ 1,713.1

Wind 160.9 311.7 654.3

Battery 258.4 413.1 253.5

Thermal 945.7 1,582.7 1,424.5

Other 481.8 309.0 365.8

LNG 178.0 82.0 112.0

Distribution:

Electric distribution 972.2 946.4 973.3

Gas distribution 1,286.8 1,611.0 1,469.1

Total $ 5,018.1 $ 6,949.5 $ 6,965.6

The DOC set duties on solar panels and cells imported from four southeast Asian countries and is investigating additional AD/CVD allegations relating to Chinese-owned manufacturers in Laos and Indonesia, as well as India-headquartered companies.

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, and Legal Matters – Uyghur Forced Labor Prevention Act for information on the duties set by the DOC and its current investigation, as well as CBP actions, respectively.

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

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.

See Factors Affecting Results, Liquidity, and Capital Resources — Regulatory, Legislative, and Legal Matters — Renewable Energy Legislation for potential impacts to our capital projects as a result of the OBBBA.

In accordance with its November 2023 PGL rate order, the ICC initiated a proceeding in January 2024 to determine the optimal method and prudent investment level for replacing aging natural gas infrastructure.

In February 2025, the ICC issued an order setting expectations for PGL's prospective retirement of its aging natural gas infrastructure.

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

PGL is working on retiring this cast and ductile iron pipe through its PRP.

Annual investment for pipe replacement is expected to ramp up to approximately $500 million in 2028.

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

We expect to provide total capital contributions to ATC (not included in the above table) of approximately $645 million from 2026 through 2028.

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

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.

WEC's portion of the investment in MISO Tranche 1 and Tranche 2.1 is estimated to be approximately $700 million and $400 million, respectively, between 2026 and 2030, 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.

Tranche 2.1 is the second phase of long range transmission planning and builds on the foundation of Tranche 1.

Long-Term Debt

A significant amount of cash is required to retire and pay interest on our long-term debt obligations.

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.

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

The following table summarizes our required interest payments on long-term debt as of December 31, 2025:

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Interest payments due on long-term debt $ 8,972.8 $ 819.3 $ 1,430.9 $ 1,010.1 $ 5,712.5

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Common Stock Dividends

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This equates to an annual dividend of $3.81 per share.

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

We have been paying consecutive quarterly dividends dating back to 1942 and expect to continue paying quarterly cash dividends in the future.

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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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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

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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.

We also issue 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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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.

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As of December 31, 2025, these trusts had investments of approximately $3.6 billion, consisting of fixed income and equity securities, that are subject to the volatility of the stock market and interest rates.

The performance of existing plan assets, long-term discount rates, changes in assumptions, and other factors could affect our future contributions to the plans, our financial position if our accumulated benefit obligation exceeds the fair value of the plan assets, and future results of operations related to changes in pension and OPEB expense and the assumed rate of return.

The performance of existing plan assets, long-term

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discount rates, changes in assumptions, and other factors could affect our future contributions to the plans, our financial position if our accumulated benefit obligation exceeds the fair value of the plan assets, and future results of operations related to changes in pension and OPEB expense and the assumed rate of return.

For additional information, see Note 20, Employee Benefits.

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Ratio of debt to total capitalization 61.7 % 59.8 % 61.7 % 60.6 %

(1) Included in long-term debt on our Consolidated Balance Sheets as of December 31, 2025, was $600.0 million principal amount of WEC Energy Group's 2025 Junior Notes due 2056 and $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, 2025 attributes $675.0 million of the Junior Notes to common equity and $675.0 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, 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, 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.

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

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.

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In March 2025, Moody's changed the rating outlook for PGL to stable from negative as a result of the ICC's February 2025 order setting expectations for PGL's retirement of aging natural gas infrastructure.

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.

In November 2025, Moody's changed the rating outlook for WPS to negative and WG to positive, both from stable.

The negative outlook of WPS reflects the change in its financial ratios during 2025 along with the growing leverage associated with WPS's investments.

Moody's affirmed WPS's ratings, including its A2 Issuer and senior unsecured ratings and Prime-1 commercial paper rating.

The positive outlook for WG is a result of strong financial ratios that Moody's expects to be sustained over the next 12-18 months.

Moody's also affirmed WG's ratings including its A3 senior unsecured rating and Prime-2 commercial paper rating.

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.

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As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is substantially offset by an equal reduction to natural gas costs.

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Our Wisconsin utilities offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs.

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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

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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 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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We are not required by the MPSC or state law to make this choice option available to customers, but since this option is currently provided to our Michigan customers, we would need MPSC approval to eliminate it.

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Regulatory, Legislative, and Legal Matters

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

Illinois Riders

Uncollectible Expense Adjustment Rider

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

The order required a $15.4 million and $0.7 million refund to customers 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.

Upon appeal by PGL and NSG, the Illinois Appellate Court affirmed the ICC order and the related disallowance.

The Illinois Supreme Court denied a subsequent petition for review and reversal of the order in March 2025.

As of December 31, 2025, there can be no assurance that all costs incurred under the UEA rider during the open reconciliation years will be deemed recoverable by the ICC.

Future disallowances by the ICC could be material.

The combined annual costs of PGL and NSG included in the rider, which reflect uncollectible write-offs in excess of what is recovered in base rates, have ranged from $10 million to $40 million.

However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

Qualifying Infrastructure Plant Rider

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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.

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

however, in January 2026, PGL filed an unopposed motion to stay the appeal, which was granted by the court.

PGL's QIP reconciliations from 2017 through 2023 are still pending.

Future disallowances by the ICC could be material.

The aggregate capital costs included in the rider during the open reconciliation years, along with any previously recognized return on these investments, totaled approximately $3.0 billion as of December 31, 2025.

However, see Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement below for information on a proposed settlement that would resolve all open proceedings.

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Uncollectible Expense Adjustment and Qualifying Infrastructure Plant Riders Settlement

In February 2026, PGL and NSG agreed on the terms of a proposed settlement with the Illinois Attorney General that, if approved by the ICC, would resolve all open proceedings related to the UEA and QIP riders.

PGL and NSG agreed to refund $49.0 million and $1.0 million, respectively, to customers as bill credits over a three year period between 2026 and 2028 to resolve the open UEA proceedings.

In order to resolve the open QIP proceedings, PGL agreed to permanently remove $130.0 million of qualified infrastructure investment costs from rate base starting in 2027 and to refund $75.0 million to customers as bill credits over a three year period between 2026 and 2028.

As a result of this agreement, we recorded a $205.0 million charge to income during the fourth quarter of 2025.

The charge was recorded as a $130.0 million impairment to PGL's net property, plant, and equipment and a $75.0 million reduction to revenues.

The total of the rate base reduction and the obligation to refund amounts to customers through bill credits recorded on our balance sheet at December 31, 2025 is $255.0 million.

This includes the $205.0 million charge to income recorded during 2025 and a $50.0 million charge to income recorded in prior years.

This proposed settlement is subject to ICC approval following a public review process.

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 the PGL rate order issued by the ICC in November 2023, the ICC ordered PGL to pause spending on its projects to upgrade its natural gas delivery system 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.

In February 2025, the ICC issued an order setting expectations for PGL's prospective operations.

The ICC directed us to focus on retiring 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.

PGL is working to retire this cast and ductile iron pipe through its PRP.

Costs incurred under the PRP will be evaluated for prudency by the ICC in future rate cases.

In addition, the program will be overseen by a safety monitor hired by the ICC.

PGL initiated a general rate case proceeding in January 2026, which we anticipate will provide further regulatory clarity before we significantly increase our spend associated with the PRP.

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

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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.

The "Future of Gas" proceeding is expected to be completed by the end of 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.

See Note 26, Regulatory Environment, for more information regarding the 2026 rate case filing and November 2023 ICC rate order.

Chicago Decarbonization Efforts

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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.

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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, 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 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.

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Uyghur Forced Labor Prevention Act

The CBP issued a WRO in June 2021, applicable to certain silica-based products originating from the Xinjiang Uyghur Autonomous Region of China (Xinjiang), such as polysilicon, included in the manufacturing of solar panels.

In June 2022, the WRO was superseded by the implementation of the UFLPA.

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 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.

In June 2022, the CBP implemented the UFLPA, which establishes a rebuttable presumption that certain silica-based products wholly or partially manufactured in the Xinjiang Uyghur Autonomous Region of China, such as polysilicon included in the manufacturing of solar panels, are prohibited from entering the United States.

While our suppliers have been able to provide the CBP sufficient documentation to meet the 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 2025, the Department of Homeland Security announced the addition of more Chinese businesses to the UFLPA, including several 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

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.

Starting in June 2024, the DOC began applying duties to certain imports of solar cells from Malaysia, Vietnam, Thailand and Cambodia, with the potential for enhanced duties in certain circumstances, based on final findings by both the DOC and the USITC in their AD/CVD investigations that Chinese manufacturers were shifting products to those four Southeast Asian countries to avoid tariffs required on products imported from China.

In April 2025, based upon investigation in response to a new petition, the DOC reached affirmative findings that some Chinese companies had moved their solar operations to avoid penalties imposed in the first investigation, increasing tariff rates, in some cases significantly.

These increased rates became effective and enforceable in May 2025 upon the USITC’s final affirmative determination.

As a result of these duties, the cost and availability of solar panels in the U.S.

has been impacted and the U.S.

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.

In August 2025, in response to another petition filed by a coalition of trade groups, the DOC and USITC initiated new AD/CVD investigations based on the coalition’s claims that Chinese-owned manufacturers in Laos and Indonesia, as well as India-headquartered companies, are benefiting from illegal subsidies and selling solar products below cost in the US.

Affirmative findings in these investigations could cause further strain on the solar panel industry.

We are monitoring the status of these petitions.

Renewable Energy Legislation

Infrastructure Investment and Jobs Act

In November 2021, the Infrastructure Investment and Jobs Act was signed into law and provides for approximately $1.2 trillion of federal spending through 2026, including approximately $85 billion for investments in power, utilities, and renewables infrastructure across the United States.

Funding from this Act supports the work we are doing to reduce GHG emissions and to strengthen and protect the energy grid.

In January 2025, disbursement of funds was paused until agency heads can determine whether grants, loans, contracts, and other disbursements are consistent with the current administration's energy policy.

In some cases, the pause has disrupted, and could continue to disrupt, funding, temporarily or permanently, for infrastructure projects already in progress, may cause project delays and cancellations, and may impact continuing payment obligations for downstream contractors and suppliers.

Inflation Reduction Act

In August 2022, the IRA was signed into law and provides for $258 billion in energy-related provisions over a 10-year period.

The IRA has helped reduce our cost of investing in projects that support our commitment to reduce emissions and provide affordable, reliable, and clean energy for our communities.

We and our customers have benefited from the IRA’s provisions to extend tax benefits for renewable technologies, increase or restore higher rates for PTCs, claim PTCs for solar projects, expand qualified ITC facilities to include standalone energy storage, and allow companies to transfer tax credits generated from renewable projects.

Under the IRA transferability option, we entered into agreements in October 2024, April 2025, and September 2025 to sell the majority of the PTCs and ITCs we generated, or expect to generate, in 2025 and 2026, respectively, to third parties.

In May 2025, we

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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 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.

entered into an agreement to sell the majority of our remaining unsold PTCs we generated in 2024 to a third party.

See Note 1(q), Income Taxes, for more information about the impact of these sales.

The IRA also implements a 15% corporate alternative minimum tax and a 1% excise tax on stock repurchases.

Although significant regulatory guidance is expected on the tax provisions in the IRA, we currently believe the provisions on alternative minimum tax and stock repurchases will not have a material impact on us.

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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One Big Beautiful Bill Act

In July 2025, the OBBBA was signed into law, enacting significant modifications to clean-energy tax credits previously provided under the IRA.

The OBBBA provides companies the ability to earn solar and wind tax credits at current credit rates if construction of projects begins by July 4, 2026, and the projects are placed in-service within four years after beginning construction.

However, wind and solar projects that begin construction more than one year after enactment of the OBBBA must be placed in service by December 31, 2027 to qualify for PTCs and ITCs.

In addition, wind and solar projects that begin construction after December 31, 2025 must also satisfy prohibited foreign entity material assistance requirements.

The incentives can also be denied for taxpayers that exceed certain thresholds of equity or debt held by specified foreign entities.

The phase out of PTCs and ITCs does not apply to energy storage, hydroelectric facilities, nuclear, or any other zero emission technology.

The OBBBA preserves the ability to transfer tax credits, with the exception of transfers to a prohibited foreign entity.

In August 2025, the U.S.

Treasury Department implemented new beginning-of-construction safe harbor rules that became effective in September 2025.

The capital plan for 2026 through 2030 reflects the impacts of OBBBA, including the revised beginning-of-construction rules.

Return on Equity Incentive for Membership in a Transmission Organization

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The transmission costs WE, WPS, and UMERC are required to pay ATC after the effective date would also be reduced by this proposal.

American Transmission Company Allowed Return on Equity Complaints

American Transmission Company Allowed Return on Equity Complaint

The ROE allowed by the FERC helps determine how much transmission owners, such as ATC, earn on their transmission assets as well as how much consumers pay for those assets.

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.

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

When a complaint was 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.

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.

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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 also rejected the use of the risk

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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 complaint.

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• 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.

In January 2022, ATC 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.

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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.

As a result, WE, WPS, and UMERC are receiving refunds from ATC related to the transmission costs they paid during these two refund periods.

The refunds are being applied to WE’s and WPS’s PSCW-approved escrow accounting for transmission expense.

• March 2025 FERC Order – In response to rehearing requests filed concerning the October 2024 FERC Order, the FERC issued an order on March 25, 2025 that reaffirmed the October 2024 FERC Order in its entirety.

Appeals related to the October 2024 FERC Order are still pending before the D.C.

Circuit Court of Appeals.

Environmental Matters

See Note 24, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, and land quality.

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Market Risks and Other Significant Risks

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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.

In addition, there is continuing uncertainty over the impact of increasing tensions between the U.S.

and other countries and new, protracted or escalating regional and international conflicts on the global economy, supply chains, and fuel prices.

Commodity Costs

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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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Our utilities' rates are based upon estimated normal temperatures.

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Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins.

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.

A summary of actual weather information in our utilities' service territories, 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 by 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.

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This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

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Marketable Securities Return

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Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

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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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In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

Changes to United States Trade Policy (Tariff Activity)

continues to implement changes to its international trade policy including changes to tariffs, port fees and other policies relating to exports from and imports into the United States.

In response to these changes, foreign governments also continue to adjust their trade policies, including the imposition of additional tariffs.

There remains significant uncertainty as to the ultimate scope of the U.S.

and foreign trade policies.

Both the U.S.

and foreign trade policy changes could increase the cost of materials or disrupt supply chains, which could impact our ability to repair or maintain our infrastructure;

the timing, cost or completion of our infrastructure projects;

and/or our ability to execute our capital plan.

In addition, these changes, including any impact they may have to economic conditions, could lead to reduced energy demand by our customers.

Consequently, these policy changes could have a material adverse effect on our business, results of operations and financial condition.

Inflation and Supply Chain Disruptions

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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 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.

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accordance with our capital plan.

For additional information concerning risks related to inflation and supply chain disruptions, see the four risk factors below.

Risk Factors – Risks Related to the Operation of Our Business – Public health crises, including epidemics and pandemics, could adversely affect our business functions, financial condition, liquidity, and results of operations.

Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions and inflation.

Risk Factors – Risks Related to the Operation of Our Business – Our operations and corporate strategy may be adversely affected by supply chain disruptions, inflation, and tariffs.

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.

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Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC (Topic 980).

Our financial statements reflect the effects of the ratemaking principles followed by the various jurisdictions regulating us.

Our financial statements reflect the effects of the ratemaking principles followed by the jurisdictions regulating us.

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

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We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2025.

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See Note 1(k), Asset Impairment, for our policy on accounting for abandonments and recently completed plant subject to disallowance.

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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.

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See Note 7, Property, Plant, and Equipment, for more information on our generating units probable of being retired.

See Note 6, Regulatory Assets and Liabilities, and Note 26, Regulatory Environment, for more information on our retired generating units, including various approvals we received from the FERC and the PSCW.

See Note 6, Regulatory Assets and Liabilities, for information on our retired generating units.

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Pension and Other Postretirement Employee Benefits

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Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods.

Changes in benefit costs 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 orders issued by the PSCW.

See Note 26, Regulatory Environment, for more information on 2023 and 2024 rates at our Wisconsin utilities.

Changes in benefit costs are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs, as required by rate orders issued by the PSCW.

See Note 26, Regulatory Environment, for more information on rates at our Wisconsin utilities.

We believe that changes to benefit costs at our other utilities would be recovered or refunded through the ratemaking process.

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Rate of return on plan assets 0.5 N/A (4.2)

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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 6.61%, 6.62%, and 6.88%, in 2024, 2023 and 2022, respectively.

The assumed long-term rate of return on pension plan assets was 6.61% in 2025 and 2024, and 6.62% in 2023.

The actual rate of return on pension plan assets, net of fees, was 9.23%, 4.75%, and 9.23%, in 2025, 2024, and 2023, respectively.

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For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 20, Employee Benefits.

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Unbilled Revenues

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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