WEC ENERGY GROUP, INC. (WEC)

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying unaudited financial statements and related notes and our 2025 Annual Report on Form 10-K.

Introduction

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

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 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.

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 southeastern 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 plan 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. On April 24, 2026, we received verbal approval from the PSCW for new VLC and Bespoke Resources tariffs. These tariffs specifically address the unique needs of VLCs while protecting our other customers and shareholders. See Note 23, 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); and

•180 MWs of reciprocating internal combustion engine 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;

•2,130 MWs of battery storage; and

•555 MWs of wind.

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

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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 CO2 emissions from 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. 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, but continue to evaluate the conversion of both units to natural gas. 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 Presque Isle Power Plant, and the 2018 retirements of the Pleasant Prairie power plant, the Pulliam power plant, and the jointly-owned Edgewater Generating Station 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. See Note 7, Property, Plant, and Equipment, for more information related to the planned retirement of OCPP Units 7 and 8.

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.

Reliability

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.

Below are a few of the more significant 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.

•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 23, Regulatory Environment, and Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceeding – Replacement of Aging Natural Gas Infrastructure.

•Our capital plan includes $2.9 billion of investments in battery energy storage systems 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.

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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.

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 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 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 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. We expect total capital expenditures for our regulated utility businesses to be approximately $33.4 billion from 2026 to 2030. 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. For additional information regarding projects included in the $37.5 billion capital plan, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

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,

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

Introduction

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

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 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.

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); and

•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;

•2,130 MWs of battery storage; and

•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 CO2 emissions from

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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.

Reliability

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.

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.

•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 $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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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 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 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 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. We expect total capital expenditures for our regulated utility businesses to be approximately $33.4 billion from 2026 to 2030. 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. For additional information regarding projects included in the $37.5 billion capital plan, see Liquidity and Capital Resources – Cash Requirements – Significant Capital Projects.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 2, Acquisitions, and Note 3, Disposition, for additional information on our recent and pending transactions.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

A multiyear effort is driving a standardized, seamless approach to digital customer service across our companies. We have moved all utilities to a common platform for all customer-facing self-service options. Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service to customers.

Safety

Safety is one of our core values and a critical component of our culture. 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. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across our companies.

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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, 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

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

2025 Compared with 2024

Earnings increased $30.3 million during 2025, compared with 2024. The significant factors impacting the $30.3 million increase in earnings were:

•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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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

The discussions below address the contribution of each of our utility segments to net income attributed to common shareholders. The discussions include financial information prepared in accordance with GAAP, as well as utility margin, which is not a measure of financial performance under GAAP. Utility margin (operating revenues less fuel and purchased power costs and cost of natural gas sold) is a non-GAAP financial measure because it excludes certain operation and maintenance expenses applicable to revenues, as well as depreciation and amortization and property and revenue taxes.

We believe that utility margin provides a useful basis for evaluating utility operations since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses utility margin internally when assessing the operating performance of our utility segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of utility margin herein is intended to provide supplemental information for investors regarding our operating performance.

Our utility margin may not be comparable to similar measures presented by other companies. Furthermore, this measure is not intended to replace gross margin as determined in accordance with GAAP as an indicator of operating performance. Each of our three utility segment discussions below include a table that provides the calculation of both gross margin as determined in accordance with GAAP and utility margin, as well as a reconciliation between the two measures.

Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders

The Wisconsin segment's contribution to net income attributed to common shareholders for the year ended December 31, 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 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.

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

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

(1)    Represents transmission expense that our electric utilities are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses for WE and WPS. 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 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.

(3)    Represents costs associated with the We Power generation units, including operating and maintenance costs recognized by WE. 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. See Note 26, Regulatory Environment, for more information.

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

(1)    Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

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(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

The following table summarizes our Wisconsin segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include plant operating and maintenance expenses related to our generating units; costs associated with the We Power generating units; and transmission, distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

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 $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.

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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:

•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;

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

•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)

Other operating expenses at the Wisconsin segment increased $287.3 million during 2025, compared with 2024. The significant factors impacting the increase in other operating expenses were:

•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 $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 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

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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 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 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 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; and

•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.

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. 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.

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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.

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

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

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

(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.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our Illinois segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

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.

•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; and

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

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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 $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 $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 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

Income tax expense at the Illinois segment decreased $51.8 million during 2025, compared with 2024, driven by a decrease in pre-tax income.

Other States Segment Contribution to Net Income Attributed to Common Shareholders

The other states segment's contribution to net income attributed to common shareholders for the year ended December 31, 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 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.

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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.

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

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

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

(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.

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Gross Margin GAAP and Utility Margin Non-GAAP

The following table summarizes our other states segment gross margin (GAAP) and reconciles gross margin (GAAP) to utility margin (non-GAAP). See Non-GAAP Financial Measures above for additional information regarding gross margin (GAAP) and utility margin (non-GAAP).

(1)    Operating and maintenance expenses deemed to be directly attributable to our revenue-producing activities include distribution and customer service expenses. These expenses are included in the above table to calculate gross margin as defined under GAAP.

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 $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 $5.2 million increase in property and revenue taxes;

•A $3.6 million increase in natural gas operations and customer service expense; and

•A $2.8 million increase in depreciation and amortization.

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

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 $2.8 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 $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

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 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. 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.

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.

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

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 $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 $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 $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 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.

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

Other Income, Net

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. The gains from the investments held in the rabbi trust partially offset the changes in benefit costs related to deferred compensation, which are primarily included in other operation and maintenance expense in our utility segments. See Note 17, Fair Value Measurements, for more information on our investments held in the Integrys rabbi trust.

Interest Expense

Interest expense at the corporate and other segment increased $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. Also partially offsetting the increase was lower than average short-term debt interest rates.

Gain on Debt Extinguishments

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 $21.5 million during 2025, compared with 2024, driven by an increase in pre-tax loss.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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 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. For a similar discussion that compares our cash flows 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 – Liquidity and Capital Resources in Part II of our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 21, 2025.

Cash Flows

The following table summarizes our cash flows during the years ended December 31:

Operating Activities

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

•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 $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.

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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.

•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 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.

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

Capital Expenditures

Capital expenditures by segment for the years ended December 31 were as follows:

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. 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 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.

Significant Financing Activities

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

We require funds to support and grow our businesses. Our significant cash requirements primarily consist of capital and investment expenditures, payments to retire and pay interest on long-term debt, the payment of common stock dividends to our shareholders, and the funding of our ongoing operations. Our significant cash requirements are discussed in further detail below.

Significant Capital Projects

We have several capital projects and acquisitions that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. 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. These amounts include anticipated expenditures for environmental compliance and certain remediation issues. For a discussion of certain environmental matters affecting us, see Note 24, Commitments and Contingencies.

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

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.

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

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Common Stock Dividends

On January 22, 2026, our Board of Directors increased our quarterly dividend to $0.9525 per share effective with the first quarter of 2026 dividend payment, an increase of 6.7%. This equates to an annual dividend of $3.81 per share.

We have been paying consecutive quarterly dividends dating back to 1942 and expect to continue paying quarterly cash dividends in the future. Any payment of future dividends is subject to approval by our Board of Directors and is dependent upon future earnings, capital requirements, and financial and other business conditions. In addition, our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our subsidiaries. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. See Note 11, Common Equity, for more information related to these restrictions and our other common stock matters.

Other Significant Cash Requirements

Our utility and non-utility operations have purchase obligations under various contracts for the procurement of fuel, power, and gas supply, as well as the related storage and transportation. These costs are a significant component of funding our ongoing operations. See Note 24, Commitments and Contingencies, for more information, including our minimum future commitments related to these purchase obligations.

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. Our estimated future cash requirements related to these purchase obligations, excluding energy-related obligations, are reflected below.

We have various finance and operating lease obligations. Our finance lease obligations primarily relate to land leases for our renewable generation projects. Our operating lease obligations are for office space and land. See Note 15, Leases, for more information, including an analysis of our minimum lease payments due in future years.

We make contributions to our pension and OPEB plans based upon various factors affecting us, including our liquidity position and tax law changes. See Note 20, Employee Benefits, for our expected contributions in 2026 and our expected pension and OPEB payments for the next 10 years. We expect the majority of these future pension and OPEB payments to be paid from our outside trusts. See Sources of Cash–Investments in Outside Trusts below for more information.

In addition to the above, our balance sheet at December 31, 2025 included various other liabilities that, due to the nature of the liabilities, the amount and timing of future payments cannot be determined with certainty. These liabilities include AROs, liabilities for the remediation of manufactured gas plant sites, and liabilities related to the accounting treatment for uncertainty in income taxes. For additional information on these liabilities, see Note 9, Asset Retirement Obligations, Note 16, Income Taxes, and Note 24, Commitments and Contingencies, respectively.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. 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

Liquidity

We anticipate meeting our short-term and long-term cash requirements to operate our businesses and implement our corporate strategy through internal generation of cash from operations and access to the capital markets, and common equity. 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. 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. Our access to the capital markets is critical to our overall strategic plan and allows us to supplement cash flows from operations with external borrowings to manage seasonal variations, working capital needs, commodity price fluctuations, unplanned expenses, and unanticipated events. Subject to market conditions and other factors, we may repurchase our debt securities through open market purchases, privately negotiated transactions and/or other types of transactions.

In January and February 2024, pursuant to a tender offer, we purchased $122.1 million aggregate principal amount of the $500.0 million outstanding of our 2007 Junior Notes for $115.2 million with proceeds from issuing commercial paper. We recorded a $6.4 million gain related to the early settlement. Additionally, in May 2024, we repurchased $19.0 million aggregate principal amount of the $377.9 million outstanding of our 2007 Junior Notes for $18.7 million, plus accrued interest, with proceeds received from issuing commercial paper. We recorded a $0.2 million gain related to the early settlement. In December 2024, we redeemed the remaining $358.9 million outstanding principal at par, plus accrued interest, of our 2007 Junior Notes with the proceeds we received from the issuance of our 2024A Junior Notes and 2024B Junior Notes.

In December 2024, pursuant to a tender offer, we repurchased $250.0 million aggregate principal amount of the $600.0 million outstanding of our 5.60% Senior Notes due September 12, 2026 and repurchased $150.0 million aggregate principal amount of the $450.0 million outstanding of our 1.80% Senior Notes due October 15, 2030, for $380.9 million, plus accrued interest, with proceeds received from issuing commercial paper. As a result of the repurchase, we recorded a $16.5 million gain on debt extinguishment.

WEC Energy Group, WE, WPS, WG, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations.

The amount, type, and timing of any financings in 2026, as well as in subsequent years, will be contingent on investment opportunities and our cash requirements and will depend upon prevailing market conditions, regulatory approvals for certain subsidiaries, and other factors. Our regulated utilities plan to maintain capital structures consistent with those approved by their respective regulators. For more information on our utilities approved capital structures, see Item 1. Business – E. Regulation.

The issuance of securities by our utility companies is subject to the approval of the applicable state commissions or FERC. Additionally, with respect to the public offering of securities, we, WE, and WPS file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

At December 31, 2025, our current liabilities exceeded our current assets by $2,308.7 million. We do not expect this to have an impact on our liquidity as we currently believe that our cash and cash equivalents, our available capacity under existing revolving credit facilities, cash generated from ongoing operations, and access to the capital markets are adequate to meet our short-term and long-term cash requirements.

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

Investments in Outside Trusts

We maintain investments in outside trusts to fund the obligation to provide pension and certain OPEB benefits to current and future retirees. 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

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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.

Capitalization Structure

The following table shows our capitalization structure as of December 31, 2025 and 2024, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our Junior Notes:

(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, 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.

The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted to reflect the treatment of the 2025 Junior Notes and 2024 Junior Notes by the majority of rating agencies. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Debt Covenants

Certain of our short-term and long-term debt agreements contain financial covenants that we must satisfy, including debt to capitalization ratios and debt service coverage ratios. At December 31, 2025, we were in compliance with all such covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Common Equity, Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt, for more information.

Credit Rating Risk

Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial as of December 31, 2025. From time to time, we may enter into commodity contracts that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings, a division of S&P Global Inc., and/or Baa3 at Moody’s Investors Service, Inc. If WE had a sub-investment grade credit rating at December 31, 2025, it could have been required to post $106 million of additional collateral or other assurances pursuant to the terms of a PPA. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact 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. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

Competitive Markets

Electric Utility Industry

The FERC supports large RTOs, which directly impacts the structure of the wholesale electric market. Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMPs to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.

Wisconsin

Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date, and it is uncertain when, if at all, retail choice might be implemented in Wisconsin.

Michigan

Michigan has adopted a limited retail choice program. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. As a result, some of our small retail customers have switched to an alternative electric supplier. At December 31, 2025, Michigan law limited customer choice to 10% of an electric utility's Michigan retail load. Our iron ore mine customer, Tilden, is exempt from this 10% cap based on current law, but Tilden is required under a long-term agreement to purchase electric power from UMERC through March 2039. In addition, certain load increases by facilities already using an alternative electric supplier can still be serviced by their alternative electric supplier, when various conditions exist, even if the cap has already been met. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

Natural Gas Utility Industry

We offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. 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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Wisconsin

Our Wisconsin utilities offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.

Due to the PSCW's previous proceedings on natural gas industry regulation in a competitive environment, the PSCW currently provides all Wisconsin customer classes with competitive markets the option to choose a third-party natural gas supplier. All of our Wisconsin non-residential customer classes have competitive market choices and, therefore, can purchase natural gas directly from either a third-party supplier or their local natural gas utility. Since third-party suppliers can be used in Wisconsin, the PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates.

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

Illinois

Absent extraordinary circumstances, potential competitors are not allowed to construct competing natural gas distribution systems in the service territories for PGL and NSG. A charter from the State of Illinois gives PGL the right to provide natural gas distribution service in the City of Chicago as a public utility. Further, the "first in the field" and public interest standards limit the ability of potential competitors to operate in an existing utility service territory. In addition, we believe it would be impractical to construct competing duplicate distribution facilities due to the high cost of installation.

Since 2002, PGL and NSG have, under ICC-approved tariffs, provided their customers with the option to choose a third-party natural gas supplier. There are no state laws requiring PGL and NSG to make this choice option available to customers, but since this option is currently provided to our Illinois customers under tariff, ICC approval would be needed to withdraw those tariffs.

An interstate pipeline may seek to provide transportation service directly to our Illinois end users, which would bypass our natural gas transportation service. However, PGL and NSG have anti-bypass tariffs approved by the ICC, which allow them to negotiate rates with customers that are potential bypass candidates to help ensure that such customers continue to use utility transportation service.

Minnesota

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. However, natural gas utilities have customarily avoided competing for existing customers of other utilities, as there would be duplicative utility facilities and/or increased costs to customers. If this approach were to change, it could lead to a greater level of competition amongst utilities to obtain customers and potentially adversely impact our results of operations.

MERC offers both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change. MERC has provided its commercial and industrial customers with the option to choose a third-party natural gas supplier since 2006. We are not required by the MPUC or state law to make this choice option available to customers, but since this option is currently provided to our Minnesota commercial and industrial customers, we would need MPUC approval to eliminate it.

Michigan

The option to choose a third-party natural gas supplier has been provided to UMERC’s natural gas customers (formerly WPS’s Michigan natural gas customers) since the late 1990s and MGU's customers since 2005. 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

Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. See Item 1. Business – E. Regulation for more information on these commissions.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to generic and/or specific orders issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities. 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

The rates of PGL and NSG include a UEA rider for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The UEA rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency by the ICC. In May 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 customers at PGL and NSG, respectively. These amounts were refunded over a period of nine months, which began on September 1, 2023. 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

In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider, which was in effect until December 1, 2023, continues to be subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In August 2024, the ICC issued a final order on PGL's 2016 annual reconciliation, which included a disallowance of $14.8 million of certain capital costs. PGL recorded a pre-tax charge to income of $25.3 million during the third quarter of 2024 related to the disallowance and the previously recognized return on and of these investments. The charge was recorded on the income statement as a $12.9 million reduction in revenues for the amounts previously collected from customers, a $12.1 million increase to operating expenses for the impairment of PGL's property, plant, and equipment, and a $0.3 million increase to interest expense related to the amounts due to customers. 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 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. 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. 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. The goal of this proceeding is to explore the issues involved with decarbonization of the gas distribution system in Illinois and recommend any future ICC action or legislative changes needed. It includes the formal exploration and consideration of the role of natural gas in the future, including in the context of the state’s environmental and energy policy goals. The proceeding includes a broad range of stakeholders, including Illinois utilities and other interested parties. The "Future of Gas" proceeding is expected to be completed 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 2026 rate case filing and November 2023 ICC rate order.

Chicago Decarbonization Efforts

The CABO was introduced at a meeting of the Chicago city council held in January 2024. If approved, this ordinance would set an indoor emissions standard that would require zero-to-low-emission energy systems in newly built commercial and residential buildings and major building additions in the city of Chicago. The proposed emission standards would effectively prohibit the use of natural gas in new buildings and homes and require electric heat and appliances. The CABO would not impact existing homes and businesses. In addition, certain buildings and equipment, such as hospitals, commercial kitchens, and back-up generators, would be exempt from the new emission limits.

In response to the CABO, a resolution was also introduced that would require the formation of a working group comprised of various subject matter experts to analyze the costs of converting buildings from natural gas to electricity, the costs for additional electric generation capacity needed for future building conversions, and the impact of shifting natural gas system costs from new construction to existing buildings if electrification measures are adopted. If the resolution is passed, this analysis would need to be completed prior to the adoption of any decarbonization initiatives, such as the CABO.

If approved by the city council, the CABO is expected to become effective one year after the approval date. PGL's future natural gas operations could be materially adversely impacted if the CABO is passed.

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Uyghur Forced Labor Prevention Act

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

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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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.

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

The FERC currently allows transmission utilities, including ATC, to increase their ROE by 50 basis points as an incentive for membership in a transmission organization, such as MISO. This incentive was established to stimulate infrastructure development and to support the evolving electric grid. However, a Notice of Proposed Rulemaking was issued by the FERC on April 15, 2021, proposing to limit the 50 basis point increase in ROE to only be available to transmission utilities initially joining a transmission organization for the first three years of membership. If this proposal becomes a final rule, ATC would be required to submit, within 30 days of the final rule's effective date, a compliance filing eliminating the 50 basis point incentive from its tariff. As a result, we estimate that this proposal, if adopted, would reduce our future after-tax equity earnings from ATC by approximately $9 million annually on a prospective basis. 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 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 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. See the Return on Equity Incentive for Membership in a Transmission Organization section above for more information on this incentive.

Return on Equity Complaint

In November 2013, a group of MISO industrial customers filed a complaint with the FERC asking that the FERC order a reduction to the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. Due to this complaint, the FERC and the D.C. Circuit Court of Appeals issued the following orders and opinion. The refunds resulting from these orders and opinion are also described below.

•September 2016 FERC Order – On September 28, 2016, the FERC issued an order reducing the base ROE for MISO transmission owners to 10.32% for the period covered by this complaint, November 12, 2013 through February 11, 2015 and September 28, 2016 going forward.

•November 2019 FERC Order – On November 21, 2019, the FERC issued another order after directing MISO transmission owners and other stakeholders to provide briefs and comments on a proposed change to the methodology for calculating base ROE. In this order, the FERC expanded its base ROE methodology to include the capital-asset pricing model in addition to the discounted cash flow model to better reflect how investors make their investment decisions. The FERC also rejected the use of the risk

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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. In response to this FERC decision, requests for the FERC to rehear the November 2019 Order in its entirety were filed by various parties.

•May 2020 FERC Order – On May 21, 2020, the FERC issued an order that granted in part and denied in part the requests to rehear the November 2019 Order. In this May 2020 Order, the FERC made additional revisions to its base ROE methodology, including reinstating the use of the risk premium model. The additional revisions made by the FERC increased the base ROE for all MISO transmission owners, including ATC, from the 9.88% authorized in the November 2019 Order to 10.02% for the period covered by the complaint. Various parties then filed requests to rehear certain parts of the May 2020 Order with the FERC.

•November 2020 FERC Order – In response to the rehearing requests filed concerning certain parts of the May 2020 Order, the FERC issued an order in November 2020 that confirmed the ROE previously authorized in its May 2020 Order.

•Refunds for FERC Orders Issued Prior to October 2024 – Due to the base ROE changes resulting from the FERC orders issued prior to October 2024, ATC was required to provide refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through November 19, 2020. In January 2022, ATC 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.

•August 2022 D.C. Circuit Court of Appeals Opinion – Since several petitions for review were filed with the D.C. Circuit Court of Appeals concerning this ROE complaint, the D.C. Circuit Court of Appeals issued an opinion on August 9, 2022, addressing these petitions. In its August 2022 Opinion, the D.C. Circuit Court of Appeals ruled the FERC failed to adequately explain why it reinstated the use of the risk premium model as part of its ROE methodology in its May 2020 Order after previously rejecting the model in its November 2019 Order. Due to this ruling, the D.C. Circuit Court of Appeals vacated the FERC’s previous orders and remanded the issue of determining an appropriate base ROE for MISO transmission owners back to the FERC for additional proceedings. As a result, ATC recorded a reserve for potential refunds based on a 9.88% base ROE.

•October 2024 FERC Order – In response to the August 2022 D.C. Circuit Court of Appeals Opinion, the FERC issued an order on October 17, 2024. The FERC’s October 2024 Order removed the risk premium model from the base ROE methodology and required MISO transmission owners, including ATC, to adopt a 9.98% base ROE for the period covered by the complaint.

•Refunds for FERC Order Issued in October 2024 – Prior to the October 2024 FERC order, the base ROE for MISO transmission owners was 10.02% based on the November 2020 FERC order. Since the October 2024 FERC order changed the base ROE to 9.98%, ATC will be providing additional refunds, with interest, for the 15-month refund period from November 12, 2013 through February 11, 2015 and for the period from September 28, 2016 through October 17, 2024. 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.

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 in 2024.

•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

We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These include, but are not limited to, the risks described below. 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

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

Embedded within our utilities' rates are amounts to recover fuel, natural gas, and purchased power costs. Our utilities have recovery mechanisms in place that generally allow them to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – E. Regulation for more information on these mechanisms.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 5, Credit Losses, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

Weather

Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. 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, 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. This can result in us incurring significant restoration costs at our utilities and at WECI, including lost revenue to customers. Our utilities' rates include a fixed amount for expected storm restoration costs. To the extent actual storm restoration costs are above what is included in these rates, earnings at our utility operations are negatively impacted and it becomes more difficult to achieve our authorized ROEs. Similarly, restoration costs and lost revenue from storms negatively impacts operations and earnings at our non-utility WECI renewable generation facilities.

Interest Rates

We are exposed to interest rate risk resulting from our short-term and long-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.

Based on the variable rate debt outstanding at December 31, 2025 and 2024, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $19.2 million and $11.2 million in 2025 and 2024, respectively. 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

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. The financial risks associated with investment returns are mitigated at our Wisconsin utilities through the requirement that WE, WPS, and WG implement escrow accounting treatment for pension and OPEB costs in 2023 through 2026, as required by the December 2022 and December 2024 rate orders issued by the PSCW. As a result, our Wisconsin utilities defer as a regulatory asset or liability, the difference between actual pension and OPEB costs and those included in rates until recovery or refund is authorized in a future rate proceeding. We also believe that the financial risks associated with investment returns would be partially mitigated at our other utilities through future rate actions by regulators.

The fair value of our trust fund assets and expected long-term returns were approximately:

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.

Economic Conditions

We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Minnesota, and Michigan. As such, we are exposed to market risks in the regional Midwest economy. 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)

The U.S. 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

We continue to monitor the impact of inflation and supply chain disruptions. 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

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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.

•Item 1A. 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.

•Item 1A. 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.

•Item 1A. 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.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – The fluctuation in demand for certain commodities and their respective prices could negatively impact our operations.

For additional information concerning other risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.

Critical Accounting Policies and Estimates

The preparation of financial statements in compliance with GAAP requires the application of accounting policies, as well as the use of estimates, assumptions, and judgments that could have a material impact on our financial statements and related disclosures. Judgments regarding future events may include the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. Actual results may differ significantly from estimated amounts based on varying assumptions.

Our significant accounting policies are described in Note 1, Summary of Significant Accounting Policies. The following is a list of accounting policies and estimates that require management's most difficult, subjective, or complex judgments and may change in subsequent periods.

Regulatory Accounting

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 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.

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. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery or refund period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, rate orders issued by our regulators, historical decisions by our regulators regarding regulatory assets and liabilities, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. See Note 6, Regulatory Assets and Liabilities, for more information on our regulatory assets and liabilities.

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Goodwill

We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2025. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.

For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the calculated fair value of a reporting unit. For our reporting units that are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.

Key assumptions used in the income approach include ROEs, the long-term growth rates used to determine terminal values at the end of the discrete forecast period, and the discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.

For the market approach, we used a higher weighting for the guideline public company method than the guideline merged and acquired company method due to a low number of mergers and acquisitions in recent years. The guideline public company method uses financial metrics from similar publicly traded companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting units to determine fair value.

The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.

For all of our reporting units that carried a goodwill balance at July 1, 2025, the fair value exceeded its carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.

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

Long-Lived Assets

In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, a regulatory decision related to recovery of assets from customers, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold or abandoned. See Note 1(k), Asset Impairment, for our policy on accounting for abandonments and recently completed plant subject to disallowance.

Performing an impairment evaluation involves a significant degree of estimation and judgment by management in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted future cash flows. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. The fair value of the asset is assessed using various methods, including recent comparable third-party sales for our nonregulated operations, internally developed discounted cash flow analysis, expected recovery of regulated assets, and analysis from outside advisors.

See Note 7, Property, Plant, and Equipment, for more information on our generating units probable of being retired. See Note 6, Regulatory Assets and Liabilities, for information on our retired generating units.

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Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 20, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. 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, 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.

The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost (including amounts capitalized to our balance sheets). Each factor below reflects an evaluation of the change based on a change in that assumption only.

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost (including amounts capitalized to our balance sheets). Each factor below reflects an evaluation of the change based on a change in that assumption only.

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable, high-quality corporate bonds across the full maturity spectrum. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

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% 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.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. 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

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated.

Unbilled revenues are estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Energy demand for the unbilled period or changes in rate mix due to fluctuations in usage patterns of customer classes could impact the accuracy of the unbilled revenue estimate. Total unbilled utility revenues were $667.5 million and $567.2 million as of December 31, 2025 and 2024, respectively. The changes in unbilled revenues are primarily due to changes in the cost of natural gas, weather, and customer rates.

Income Tax Expense

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(q), Income Taxes, and Note 16, Income Taxes, for a discussion of accounting for income taxes.

We are required to estimate income taxes for each of our applicable tax jurisdictions as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.

Uncertainty associated with the application of tax statutes and regulations, the outcomes of tax audits and appeals, changes in income tax law, enacted tax rates or amounts subject to income tax, and changes in the regulatory treatment of any tax reform benefits requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

We expect our 2026 annual effective tax rate to be between 5.5% and 6.5%. Our effective tax rate calculations are revised every quarter based on the best available year-end tax assumptions, adjusted in the following year after returns are filed. 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.