WEC ENERGY GROUP, INC.

Wisconsin Segment

The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.

Electric Utility Operations

Our electric utility operations include the operations of WE, WPS, and UMERC.

•WE generates and distributes electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin.

•WPS generates and distributes electric energy to customers located in northeastern and central Wisconsin.

•UMERC generates and distributes electric energy to customers, including one iron ore mine owned by Tilden, located in the Upper Peninsula of Michigan.

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail, wholesale, and resale customers, and distribution sales to those customers who switched to an alternative electric supplier in the Upper Peninsula of Michigan. In 2025, retail revenues accounted for 92.3% of total electric operating revenues, wholesale revenues accounted for 1.9% of total electric operating revenues, and resale revenues accounted for 4.8% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders for information on MWh sales by customer class.

Our electric utilities are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.

We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers.

The majority of our sales for resale are conducted within an energy market operated by MISO at market rates based on the availability of our generation and market demand. Retail fuel costs are reduced by the amount that revenue exceeds the cost of sales derived from these opportunity sales.

Our electric utilities buy and sell electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the MISO Energy Markets compared to our competitors affects how often our generating units are dispatched and whether we buy or sell power. For more information on the MISO Energy Markets, see E. Regulation.

Steam Sales

WE has a steam utility that generates, distributes, and sells steam supplied by the VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions.

Electric Sales Forecast

Our service territory experienced higher weather-normalized retail electric sales in 2025, compared with 2024. We currently forecast retail electric sales volumes, excluding the Tilden mine located in the Upper Peninsula of Michigan, to increase 1.6% for 2026, compared with 2025, assuming normal weather. Excluding the very large data center customers, we currently forecast sales volumes to be relatively flat for 2026, assuming normal weather.

Electric Commercial and Industrial Retail Customers

We provide electric utility service to a diversified base of customers in industries such as metals and other manufacturing, paper, governmental, food manufacturing, and health services.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from a diverse generation portfolio that balances a stable, reliable, and affordable supply of electricity with environmental stewardship. Through our participation in the MISO Energy Markets, we supply a significant amount of electricity to our customers from generation that we own. We supplement our internally generated power supply with long-term PPAs, including the Point Beach PPA discussed under the heading "Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess power supply into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power. On a real time basis, the MISO Energy Market continuously evaluates system load requirements and dispatches the lowest-cost generation resources, while respecting any limitations on the transmission system.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2026:

(1)The values included in the estimate assume a natural gas price based on the December 2025 NYMEX.

(2)Includes hydroelectric, biomass, solar, BESS, and wind generation.

(3)Includes hydroelectric, wind, and customer-owned renewable generation.

Electric Generation Facilities

Our generation portfolio is a mix of energy resources having different operating characteristics and fuel sources. We own 8,375 MWs of generation capacity, including wholly owned and jointly owned facilities. We Power's generating units are also included in the generation capacity. Our generation facilities include natural gas-fired plants, coal-fired plants, renewable generation, and BESSs. Certain of our natural gas-fired generation units have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our facilities, see Item 2. Properties.

We are engaged in discussions with a small number of customers to provide power to large-scale data centers being constructed in our service territories. We anticipate electric demand growth in the years ahead from these VLCs. Subject to pending regulatory approvals from the PSCW as discussed below, WE is planning to make significant infrastructure investments in new natural gas-fired plants, wind, solar and battery projects, and other generation and distribution assets to power and serve these large-scale data centers and other projects. We are working closely with the new data center customers to provide bespoke resources, which are generation resources assigned to the VLCs that match their growing demand in order to minimize the impact on our other retail customers.

Supporting Economic Growth Within Our Communities

Our capital plan reflects the planned retirement of our older, fossil-fueled generation, which we expect to replace with natural gas-fired generation and zero-carbon-emitting renewables. These retirements are intended to address compliance with EPA regulations established under the CAA, as well as contribute to meeting our goal to reduce CO 2 emissions from our electric generation. When taken together, the retirements and new investments in natural gas generation and renewables discussed in more detail below should better balance our supply with our demand, while helping to address compliance and maintaining reliable, affordable energy for our customers. As described in the preceding section, we are planning to make significant investments in generation and distribution assets for the future demands of VLCs.

Environmental Goal

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 of the end of 2025, our electric generation fleet has achieved a 53% reduction in carbon emissions from the 2005 baseline.

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 2024 retirements of OCPP Units 5 and 6, 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. See Note 6, Regulatory Assets and Liabilities, for more information related to certain of these power plant retirements. 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.

See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Corporate Developments for more information on our capital plan.

Also see Item 1A. Risk Factors - Risks Related to Legislation and Regulation - Our operations, capital expenditures, and financial results may be affected by the impact of GHG legislation, regulation, and our emission reduction goal.

Renewable Generation

Our electric utilities meet a portion of their electric generation supply with various renewable energy resources, including wind, solar, hydroelectric, and biomass. This helps our electric utilities work towards our goal of reducing carbon emissions while also maintaining compliance with renewable energy legislation. These renewable energy resources also help us maintain diversity in our generation portfolio, which effectively serves as a price hedge against future fuel costs, and will help mitigate the risk of potential unknown costs associated with any future carbon restrictions for electric generators.

Wind

Our utilities continue to invest in and upgrade their wind-powered generation systems to enhance reliability. We have received approval from the PSCW to acquire and construct 160 MWs of additional wind-powered generation. Our subsidiaries will jointly own these generation facilities with an unaffiliated entity. See Note 8, Jointly-Owned Utility Facilities, for more information.

Solar and Battery Storage

In June 2025, the construction of the battery portion of Paris located in Kenosha County, Wisconsin was completed, and the facility became commercially operational. The solar portion of Paris was commercially operational in December 2024. Paris is owned by WE, WPS, and an unaffiliated entity, with WE and WPS collectively owning 180 MWs of solar generation. WE and WPS also collectively own 99 MWs of battery storage associated with this project.

In March 2025, the construction of the solar portion of Darien located in Rock and Walworth counties, Wisconsin was completed, and the facility became commercially operational. Darien is owned by WE, WPS, and an unaffiliated entity, with WE and WPS collectively owning 225 MWs of solar generation. WE and WPS will collectively own 68 MWs of battery storage associated with this project, with construction expected to be completed in 2027.

As part of our commitment to invest in additional zero-carbon generation within our Wisconsin segment, we have received approval from the PSCW to acquire and construct 955 MWs of additional solar-powered generation and 411 MWs of battery storage. See Note 8, Jointly-Owned Utility Facilities, for more information.

We have also filed requests with the PSCW to acquire and construct 1,333 MWs of solar-powered generation and 212 MWs of battery storage.

Thermal Generation

As part of our commitment to invest in additional thermal generation within our Wisconsin segment, we have received approval from the PSCW to acquire and construct 1,228 MWs of additional natural gas-fired generation.

We have also filed requests with the PSCW to acquire and construct 1,660 MWs of additional natural gas-fired generation. Some of the generation projects pending approval are for bespoke resources to serve VLCs. See Note 26, Regulatory Environment, for more information on bespoke resources and the proposed VLC tariff.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO implemented seasonal requirements effective June 1, 2023. The installed capacity reserve margins for the planning year June 1, 2025 through May 31, 2026 are as follows: 15.7% summer (June – August); 25.3% fall (September – November); 38.6% winter (December – February); and 38.8% spring (March – May). MISO's short-term reserve margin requirements experience year-to-year and season-to-season fluctuations, primarily due to changes in the generation resource mix and average forced outage rate of generation within the MISO footprint.

Michigan legislation requires all electric providers to annually demonstrate to the MPSC that they have adequate resources to serve the anticipated needs of their customers for a minimum of four consecutive planning years beginning in the upcoming planning year June 1, 2026, through May 31, 2027. The MPSC has established future planning reserve margin requirements based on the same study conducted by MISO that determines the short-term reserve margin requirements.

In both our Wisconsin and Michigan jurisdictions, we believe that we have adequate capacity through company-owned generation units and power purchase contracts to meet the MISO calculated planning reserve margin during the current planning year. We also fully anticipate that we will have adequate capacity to meet the planning reserve margin requirements for the upcoming planning year in both jurisdictions.

Fuel and Purchased Power Costs

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW generally allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customers. For more information about the fuel rules, see E. Regulation.

Our average fuel and purchased power costs per MWh by fuel type, including delivery costs, were as follows for the years ended December 31:

WE and WPS purchase coal under long-term contracts, which helps with price stability. Coal and associated transportation services are exposed to volatility in pricing due to changing domestic and world-wide demand for coal and diesel fuel. To mitigate against this volatility risk, WE and WPS have PSCW approval for a hedging program. This program allows them to hedge, over a 60-month period, up to 75% of their potential risks related to rail transportation fuel surcharge exposure. The results of this hedging program, when used, are reflected in the average costs of fuel and purchased power.

We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage. WE and WPS also have PSCW approval for a hedging program to mitigate against volatility related to natural gas price risk. This program allows them to hedge, over a 60-month period, up to 75% of their estimated natural gas use for electric generation. The results of this hedging program are reflected in the average costs of natural gas.

Coal Supply

We diversify the coal supply for our electric generating facilities and jointly-owned plants by purchasing coal from several mines in Wyoming and Pennsylvania, as well as from various other states. For 2026, 51% of our total projected coal requirements of 8.9 million tons are contracted under fixed-price contracts. See Note 24, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for the next three years are as follows.

Coal Deliveries

All of our coal requirements are expected to be shipped by unit trains that we own or lease under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming and Pennsylvania. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities. For additional information concerning risks related to coal supply chain disruptions, see the risk factor below.

•Item 1A. Risk Factors – Risks Related to Economic and Market Volatility – We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

Power Purchase Commitments

We enter into short- and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. Excluding planning capacity purchases, our power purchase commitments with unaffiliated parties consist of 1,133 MWs per year for 2026 through 2029 and 1,033 MWs in 2030. This amount includes 1,033 MWs per year related to a long-term PPA for electricity generated by Point Beach. If necessary, we purchase planning capacity from the MISO annual auction to ensure that we maintain our compliance with planning reserve requirements as established by the PSCW, MPSC, and MISO.

Natural Gas Utility Operations

WE, WPS, and WG are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. Our Wisconsin natural gas utilities operate throughout the state of Wisconsin, including the City of Milwaukee and surrounding areas, northeastern Wisconsin, and in large areas of both central and western Wisconsin. In addition, UMERC is authorized to provide retail natural gas distribution service in designated territories in the Upper Peninsula of Michigan.

Our Wisconsin segment natural gas utilities provide service to residential and commercial and industrial customers. In addition, our Wisconsin segment offers natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Major industries served include real estate, food manufacturing, governmental, restaurants, and paper. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Wisconsin Segment Contribution to Net Income Attributed to Common Shareholders for information on natural gas sales volumes by customer class in Wisconsin and the Upper Peninsula of Michigan.

Natural Gas Sales Forecast

Our combined Wisconsin service territories experienced slightly lower weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2025 as compared to 2024. We currently forecast retail natural gas delivery volumes to decrease slightly in 2026 as compared to 2025, assuming normal weather.

Natural Gas Supply, Pipeline Capacity and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns. For more information on our natural gas utility supply and transportation contracts, see Note 24, Commitments and Contingencies.

We have long-term firm capacity contracts with interstate pipelines that access supply from a variety of natural gas producing areas. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

Due to variations in natural gas usage in Wisconsin, our Wisconsin natural gas utilities have also contracted for substantial underground storage capacity, primarily in Michigan. WE, WPS, and WG have entered into long-term service agreements for approximately 99% of a wholly owned subsidiary of Bluewater's natural gas storage. Bluewater owns natural gas storage facilities in Michigan and provides approximately one-third of the current storage needs for our Wisconsin natural gas utilities. We target storage inventory levels at approximately 40% of forecasted demand for November through March. Diversity of natural gas supply enables us to manage significant changes in demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months and withdraw it in the winter months.

We contract with interstate pipeline companies, as well as other service providers, to purchase firm transportation and storage services under varied-length long-term contracts. We believe that having diverse capacity and storage benefits our customers.

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our Wisconsin segment natural gas utilities' forecasted design peak-day throughput is 39.9 million therms for the 2025 through 2026 heating season. Our Wisconsin segment natural gas utilities' peak daily send-out during 2025 was 24.2 million therms on January 20, 2025. Peak or near-peak demand generally occurs only a few times each year. Natural gas pipeline capacity and storage and natural gas supplies under contract can be resold in secondary markets. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRMs. For information on the GCRMs, see Note 1(d), Operating Revenues.

To ensure a reliable supply of natural gas during peak winter conditions, we have LNG facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers. WE and WG each have LNG facilities, which together provide approximately two Bcf of natural gas supply. The PSCW approved WE's request to construct an additional LNG facility with a storage capacity of two Bcf. The construction of additional LNG facilities in Wisconsin has been proposed as part of the 2026-2030 capital plan and would provide another approximately four Bcf of natural gas supply. The use of LNG allows us to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity.

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

As part of their hedging programs, our Wisconsin utilities further reduce their supply cost volatility through the use of a mix of financial instruments, such as NYMEX-based natural gas options and futures contracts. WE, WPS, and WG have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand. These approvals allow these companies to pass 100% of the hedging costs (premiums, brokerage fees, and losses) and proceeds (gains) to customers through their respective GCRMs.

Illinois Segment

Our Illinois segment includes the natural gas utility operations of PGL and NSG. Our customers are located in Chicago and the northern suburbs of Chicago. PGL and NSG provide service to residential and commercial and industrial customers. In addition, PGL and NSG offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Major industries served include real estate, non-profits, education, restaurants, and wholesale distributors. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Illinois Segment Contribution to Net Income Attributed to Common Shareholders for information on natural gas sales volumes by customer class.

Natural Gas Supply, Pipeline Capacity, and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns. For more information on our natural gas utility supply and transportation contracts, see Note 24, Commitments and Contingencies.

We have long-term firm capacity contracts with interstate pipelines that access supply from a variety of natural gas producing areas. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

We own a 38.8 Bcf storage field (Manlove Field in central Illinois) and contract with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, which provides a hedge against supply cost volatility. We also own a natural gas pipeline system that connects Manlove Field to Chicago and nine major interstate pipelines. These assets are directed primarily to serving rate-regulated retail customers and are included in our regulatory rate base. We also use a portion of these company-owned storage and pipeline assets as a natural gas hub, which consists of providing transportation and storage services in interstate commerce to our wholesale customers. Customers deliver natural gas to us for storage through an injection into the storage reservoir, and we return the natural gas to the customers under an agreed schedule through a withdrawal from the storage reservoir. Title to the natural gas does not transfer to us. We recognize service fees associated with the natural gas hub services provided to wholesale customers. These service fees reduce the cost of natural gas and services charged to retail customers in rates.

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our Illinois utilities' forecasted design peak-day throughput is 25.1 million therms for the 2025 through 2026 heating season. Our Illinois utilities' peak daily send-out during 2025 was 19.4 million therms on January 21, 2025. Peak or near-peak demand generally occurs only a few times each year. Natural gas pipeline capacity and storage and natural gas supplies under contract can be resold in secondary markets. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRMs. For information on the GCRMs, see Note 1(d), Operating Revenues.

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

As part of their hedging programs, our Illinois utilities further reduce their supply cost volatility through the use of a mix of financial instruments, such as NYMEX-based natural gas options and futures contracts. Their hedging programs are reviewed by the ICC as part of the annual purchased gas adjustment reconciliation. They hedge between 25% and 50% of planned natural gas purchases, with a target of 37.5%.

Natural Gas Pipe Retirement Program

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.

For information on regulatory proceedings related to the PRP, see Note 26, Regulatory Environment, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters – Illinois Proceedings.

Other States Segment

Our other states segment includes the natural gas utility operations of MERC and MGU and the non-utility operations of MERC related to servicing appliances for customers. MERC serves customers in various cities and communities throughout Minnesota, and MGU serves customers in southern and western Michigan. MERC and MGU provide service to residential and commercial and industrial customers. In addition, MERC and MGU offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Major industries served include real estate, education, restaurants, wholesale distributors, and non-profits. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Other States Segment Contribution to Net Income Attributed to Common Shareholders for information on natural gas sales volumes by customer class.

Natural Gas Supply, Pipeline Capacity and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns. For more information on our natural gas utility supply and transportation contracts, see Note 24, Commitments and Contingencies.

MGU owns a 2.9 Bcf storage field (Partello in Michigan) and contracts with various other underground storage service providers for additional storage services. We contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having diverse capacity and storage benefits our customers.

Combined with our storage capability, management believes that the volume of gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Forecasted design peak-day throughput for our other states utilities is 9.5 million therms for the 2025 through 2026 heating season. Our other states utilities' peak daily send-out during 2025 was 7.9 million therms on January 20, 2025. Peak or near-peak demand generally occurs only a few times each year. Natural gas pipeline capacity and storage and natural gas supplies under contract can be resold in secondary markets. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRMs. For information on the GCRMs, see Note 1(d), Operating Revenues.

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, contracted and owned storage, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

Our other states utilities further reduce their supply cost volatility through the use of financial instruments, such as commodity futures, swaps, and options as part of their hedging programs. MERC has MPUC approval to hedge up to 30% of planned winter demand using NYMEX financial instruments. MGU has MPSC approval to hedge up to 20% of its planned annual purchases using NYMEX financial instruments.

General

Seasonality

Electric Utility Operations – Wisconsin Segment

Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. In 2025, our generating plants performed as expected during the most demanding periods of the year, and all power purchase commitments under firm contract were received. During this period, our electric utilities did not make any public appeals for conservation, and they did not interrupt or curtail service to non-firm customers who participate in load management programs. Our electric utilities did have economic interruption events; however, service to customers was not curtailed. Economic interruptions are declared during times in which the price of electricity in the regional market exceeds the cost of operating the company's peaking generation. During this time, customers taking service under these interruptible programs can choose to continue using electricity at a price based on wholesale market prices or to reduce their load.

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather. The effect on earnings from these changes in weather are reduced by decoupling mechanisms included in the rates of PGL, NSG, and MERC. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes.

Our natural gas utilities' working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

Electric Utility Operations – Wisconsin Segment

Our electric utilities face competition from various entities and other forms of energy sources available to customers, including self-generation by customers and alternative energy sources. Our electric utilities compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.

Our natural gas utilities also face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternative fuels. Electrification initiatives or mandates are being considered or proposed by local and state governments. In addition, the majority of our natural gas customers have the opportunity to choose a natural gas supplier other than us. Our natural gas utilities offer transportation services for customers that elect to purchase natural gas directly from a third-party supplier. We continue to earn distribution revenues from these transportation customers for their use of our distribution systems to transport natural gas to their facilities. 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 offset by an equal reduction to natural gas costs.

For more information on electrification initiatives in certain of our Illinois service territories, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Regulatory, Legislative, and Legal Matters - Chicago Decarbonization Efforts.

For more information on competition in each of our service territories, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.

Methane Emission Reductions

We 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, our Wisconsin utilities began transporting the output of local dairy farms onto their natural gas distribution systems. 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.