NorthWestern Energy Group, Inc.: Form 10-K for the period ended Dec 31, 2025

OVERVIEW

NorthWestern Energy - Delivering a Bright Future

NorthWestern Energy Group, doing business as NorthWestern Energy, provides essential energy infrastructure and valuable services that enrich lives and empower communities while serving as long-term partners to our customers and communities. We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We provide electricity and / or natural gas to approximately 850,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Upon the completion of the holding company reorganization in 2023, NW Corp became a subsidiary of NorthWestern Energy Group. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. We have provided service in South Dakota and Nebraska since 1923 and in Montana since 2002.

On August 18, 2025, we entered into the Merger Agreement with Black Hills and Merger Sub, that provides for an all-stock merger of equals between NorthWestern and Black Hills (the Merger). The Merger Agreement provides for Merger Sub to merge with and into NorthWestern, with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume the new corporate name of Bright Horizon Energy as the resulting parent company of the combined corporate group. The Merger will combine the strengths of both companies, resulting in an organization with greater scale, financial stability, and operational expertise. It is designed to create a stronger, more resilient energy company focused on delivering safe, reliable, and affordable energy solutions to customers. Pursuant to the Merger Agreement, at the effective time of the Merger, each share of common stock of NorthWestern issued and outstanding as of immediately prior to closing will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of common stock of Black Hills, par value $1.00 per share (Black Hills Common Stock). See Note 3 - Pending Merger with Black Hills Corporation to the Consolidated Financial Statements included herein for additional information regarding this pending Merger.

We manage our businesses by the nature of services provided, and operate principally in two operating segments: electric utility operations and natural gas utility operations. Our electric utility operations include the generation, purchase, transmission and distribution of electricity, and our natural gas utility operations include the production, purchase, transmission, storage, and distribution of natural gas. Our customer base consists of a mix of residential, commercial, and diversified industrial customers.

Our electric and natural gas utility operations are not dependent on a single customer, or even a few customers, and the loss of any one or even a few of our largest customers is not reasonably likely to have a material adverse effect on our financial condition. Our utility operations are seasonal and weather patterns can have a material impact on operating performance. Consumption of electricity is often greater in the summer and winter months for cooling and heating, respectively. Because natural gas is used primarily for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season.

We have a social responsibility to our customers to deliver reliable energy at an affordable price. Our reliability standards and results are typically in the first or second quartile compared to our peers and our typical residential bills are significantly lower than the national average. We are engaged with the communities we serve, hosting town meetings to provide updates on important matters relating to both NorthWestern and our residents. For our employees, we offer a career with competitive pay and great benefits, providing a balance between work and life. We have been recognized by Newsweek as one of the “Great Places to Work” three years in a row.

Over time, we have increased our environmental sustainability efforts and our access to carbon-free energy resources. In February 2022, we made a commitment to achieving Net-Zero by the year 2050 for Scope 1 and Scope 2 carbon and methane emissions. Our Scope 1 emissions are primarily from owned electric generation plants, fugitive emissions from our natural gas production, gathering, transmission and distribution systems and company owned transportation fleet. Our Scope 2 emissions are primarily from the electric and natural gas utilized to heat, cool and power our offices, warehouses and other facilities.

We currently own a mix of clean and carbon-free energy resources balanced with traditional energy sources that are necessary for us to deliver affordable and reliable electricity to our customers 24/7. In 2025, approximately 52 percent of our electric portfolio, from owned and long-term resources, was carbon-free, compared to approximately 41 percent (Source: U.S. Energy Information Administration, Annual Energy Review, Electricity Net Generation: Electric Power Sector) for the total U.S. electric power industry in 2024. We do not receive all of the related Renewable Energy Credits (RECs) from our contracted electric supply resources. The owner of the RECs claims the renewable attributes of the energy. Our resource mix does not represent the actual energy delivered to our customers. Market purchases and sales fill the gaps between customer demand and economic dispatch of our supply portfolio resources.

In 2025, we completed construction of the 175 MW YCGS electric generation facility and in 2026, we expect to complete construction of Aberdeen Generating Station Units 3 & 4, a 33 MW natural gas fired electric generating facility located in Aberdeen, South Dakota. On January 1, 2026, we acquired an additional 592 MW of ownership interest in Colstrip Units 3 & 4. As discussed further below, in order to meet the SPP's additional accredited capacity needs by 2030, we submitted a project with the SPP under their Expedited Resource Adequacy Study program for the construction of a 131 MW natural gas generating facility located in Aberdeen, South Dakota. While still striving to meet our environmental goal of Net Zero by 2050, these generation facilities are needed to support our efforts to provide reliability and affordability to our customers. Since 2011, we have added 1,096 MW of carbon-free generation (both owned and long-term contract) in Montana and South Dakota. We believe that technological advancements, along with decreasing costs of carbon-free generation and the regionalization of intermittent generation, will significantly contribute to our Net-Zero goal. The pace of transition to Net-Zero will depend on the timing of technological advancements, costs, and retirement of our existing coal fleet.

We are committed to conducting business with integrity, while ensuring transparency and accountability, and meeting our responsibilities to all our stakeholders. We adhere to a strict code of ethics regarding corporate governance. Our Code of Conduct and Ethics applies to all employees, board members, vendors and contractors, with additional Code of Ethics for the Chief Executive Officer and Senior Financial Officers concerning financial reporting and other related matters.

MONTANA ELECTRIC OPERATIONS

Our regulated electric utility business in Montana, which is primarily conducted through NW Corp, includes generation, transmission and distribution. Our service territory covers approximately 107,600 square miles, representing approximately 73 percent of Montana's land area. During 2025, we delivered electricity to approximately 440,700 customers in 225 communities and their surrounding rural areas, 13 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2025, by category, residential, commercial, industrial, and other sales accounted for approximately 46%, 46%, 5%, and 3%, respectively, of our Montana retail electric utility revenue.

Transmission and Distribution

Our electric system is composed of high voltage transmission lines and low voltage distribution lines as follows:

In addition to delivering energy to distribution systems to serve customers, we also transmit electricity for nonregulated entities owning generation, and utilities, cooperatives, and power marketers serving the Montana electricity market. Our total control area peak demand reached a peak of approximately 1,976 MWs on February 13, 2025. Our control area average demand for 2025 was approximately 1,345 MWs per hour, with total energy delivered of approximately 11.78 million MWHs.

Our transmission system is directly interconnected with Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; WAPA; and Montana Alberta Tie. Such interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase, and sale of power among all major electric systems in the west interconnecting with the winter-peaking northern and summer-peaking southern regions of the western power system. We provide wholesale transmission service and firm and non-firm transmission services for eligible transmission customers pursuant to our FERC OATT.

Electric Supply

Our annual retail electric supply load requirement averages approximately 767 MWs per day, with a peak load of approximately 1,300 MWs, and are supplied by owned and contracted resources and market purchases with multiple counterparties.

In 2025, our owned generation resources generated electric supply representing approximately 67 percent of our retail load. We expect that our owned generation resources will generate electric supply representing approximately 95 percent of our forecasted retail load for 2026. The increase relative to the prior year is due to the acquisition of additional interests in Colstrip Units 3 & 4 from Avista. In addition, we have contracts with QFs totaling 569 MWs of nameplate capacity, including 107 MWs from waste petroleum coke and waste coal, 268 MWs from wind, 17 MWs from hydro, and 177 MWs from solar projects. We have several other long-term power purchase agreements including contracts for 135 MWs nameplate capacity from wind generation, 310 MWs from unspecified resources, 52 MWs of natural gas generation, and 13 MWs of hydro supply. On average, our owned and long-term contracted resources are expected to provide enough energy to meet our retail energy load requirements in 2026. Load requirements during peak demand in excess of our owned and long-term contracted resources will be satisfied with market purchases. Our owned and contracted resources will be economically dispatched to meet load requirements and any excess supply will be sold into the market.

Owned Generation Facilities

Details of these generating facilities are described in the following tables.

(1) We are in the process of relicensing the Thompson Falls hydro facility. The FERC extended our current license for 2026, and we anticipate that they will continue to extend on an annual basis until our relicensing proceeding is complete.

(2) The Hebgen facility (0 MW net capacity) is excluded from the figures above. These are run-of-river dams except for Mystic, Cochrane, Ryan and Morony.

(1) We have three separate ownership interests in Colstrip facility, a 30 percent ownership interest in Unit 4, a 15 percent ownership interest in Colstrip Units 3 & 4, and a 25 percent ownership interest in Colstrip Units 3 & 4, totaling to a 55 percent ownership interest in Colstrip Units 3 & 4.

Colstrip Units 3 & 4 provide base-load supply and are operated by Talen Montana, LLC (Talen). Talen has a 30 percent ownership interest in Colstrip Unit 3. Associated with our 30 percent ownership interest in Colstrip Unit 4, we have a reciprocal sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15 percent of the respective combined output and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or 4. However, each party is responsible for its own fuel-related costs. On January 1, 2026, we acquired an additional 40 percent ownership interest in Colstrip Units 3 & 4. This includes the acquisition of ownership interests previously owned by Avista Corporation (Avista) (222 MW) and Puget Sound Energy (Puget) (370 MW) that brought our total share of Colstrip Units 3 & 4 up to 814 MW, or 55 percent of the plant capacity. We have a coal supply agreement to supply fuel from adjacent coal reserves for our ownership interests in Colstrip Units 3 & 4 that is effective through 2033. The 222 MW interest in Colstrip Units 3 & 4 acquired from Avista is owned by NW Corp and is included in our MPSC regulated supply portfolio. The 370 MW interest in Colstrip Units 3 & 4 acquired from Puget is owned by NW Colstrip 370. This resource is not included within the MPSC regulated resource supply portfolio at this time. We expect our future opportunity to serve growing utility customer demand, including large-load customers, may be supported by this resource.

Resource Planning

Resource planning is an important function necessary to meet our customers' future energy needs and is used to guide resource acquisition activities. Our Draft 2026 IRP is publicly available and is scheduled to be filed with the Commission in April 2026. This IRP is our first plan developed under the 2023 Montana administrative rules, which transitioned the planning process from a traditional resource adequacy focus to an integrated evaluation of generation, transmission, fuel supply, and reliability. Our previous resource plan was filed with the MPSC in April 2023.

While 2026 capacity adequacy is maintained due to the recent additions of YCGS and Avista’s 222 MW share of Colstrip Units 3 & 4, the 2026 IRP identifies emerging capacity needs beginning in 2027 driven by load growth, capacity contract expirations, and resource retirements. Consistent with regional practice, NorthWestern evaluates resource adequacy through the Western Resource Adequacy Program, which establishes planning reserve margin requirements based on probabilistic reliability metrics and seasonal system conditions.

In addition to our responsibility to meet peak demand, national NERC reliability standards continue to require sufficient dispatchable generation capable of increasing or decreasing output to manage system variability, including the growing demand of intermittent generation such as wind and solar. Our generation portfolio remains a balanced mix of energy and capacity resources having different operating characteristics and fuel sources designed to reliably serve retail customers at the lowest possible cost while maintaining reliability.

Western Energy Imbalance Market

We entered the Western Energy Imbalance Market (EIM), operated by the California Independent System Operator, on June 16, 2021. We have EIM transfer capability with PacifiCorp, Idaho Power Company, Bonneville Power Administration, Avista Corp, and Tacoma Power.

SOUTH DAKOTA ELECTRIC OPERATIONS

Our South Dakota electric utility business, which is conducted through NWE Public Service, operates as a vertically integrated generation, transmission and distribution utility. We have the exclusive right to serve an area in South Dakota comprised of 25 counties. We provide retail electricity to more than 65,600 customers in 118 communities in South Dakota. In 2025, by category, residential, commercial and other sales accounted for approximately 39%, 59%, and 2%, respectively, of our South Dakota retail electric utility revenue.

Transmission and Distribution

Our electric system includes high voltage transmission and low voltage distribution lines as follows:

Our South Dakota system is interconnected with the transmission facilities of Otter Tail Power Company; Montana-Dakota Utilities Co.; Xcel Energy Inc.; and WAPA. We also have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative.

We are a member in the SPP, with our transmission facilities residing in zone 19 of the SPP footprint. Each year, we review all new or modified transmission assets and transfer functional control of assets that qualify under the SPP Tariff to the SPP. This annual update goes into effect on April 1st each year. To date, we have transferred control of 333 line miles of 115 kV facilities and over 158 line miles of 69 kV facilities. While we have transferred functional control of these facilities to the SPP, they are still owned by us and reflected in the table above. Along with SPP, our South Dakota facilities have ties to MISO. We have grandfathered agreements in MISO, which provide us the access to move the power from the Coyote, Big Stone, and Neal power plants to our customers. Along with operating the transmission system, SPP also coordinates regional transmission planning for all of its members on an annual basis through its Integrated Transmission Planning (ITP) process. Our annual participation in the ITP process includes model development, system needs assessment, and solution development to address identified needs.

Electric Supply

Our annual retail electric supply load requirements average approximately 188 MWs, with a peak load of approximately 325 MWs, and are supplied by owned and contracted resources and market purchases. We use market purchases and peaking generation to provide peak supply in excess of our base-load capacity. We are a member of the SPP. As a market participant in SPP, we buy and sell wholesale energy and reserves in both day-ahead and real-time markets through the operation of a single, consolidated SPP balancing authority. We and other SPP members submit into the SPP market both offers to sell our generation and bids to purchase power to serve our load. SPP optimizes next-day and real-time generation dispatch across the region and provides participants with greater access to economic energy. Marketing activities in SPP are handled for us by a third-party provider acting as our agent.

Electric supply resources include 211 MWs from jointly owned coal plants and 118 MWs from two natural gas-fired plants. Additional resources include several peaking units and an 80 MW wind facility. We also purchase the output of four wind projects, three of which are QFs, under power purchase agreements. Actual output for our wind resources varies based upon weather conditions.

Owned Generation Facilities

Details of our generating facilities are described further in the following chart:

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The Big Stone, Coyote and Neal plants are owned jointly with unaffiliated parties. Each of the jointly owned plants is subject to a joint management structure, and we are not the operator of any of these plants. Based on our ownership interest, we are entitled to a proportionate share of the capacity of our jointly owned plants and are responsible for a proportionate share of the operating costs.

The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. Coyote is a mine-mouth generating facility. Neal Unit No. 4 and Big Stone receive their fuel supply via rail. The average delivered cost by type of fuel burned varies between generation facilities due to differences in transportation costs and owner purchasing power for coal supply. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs.

Resource Planning

We maintain an integrated resource planning process that includes forecasts of customer energy usage and evaluates a range of options to provide for the economic, reliable, and timely supply of energy. We regularly update our load forecasts to reflect changes in customer demand, industrial growth, and regional planning requirements, and we assess future generating capacity needs on an ongoing basis. In September 2024, we submitted an updated 2024 IRP to the South Dakota Public Utilities Commission that incorporates updated load forecasts, revised planning reserve margin requirements, updated resource cost and performance assumptions, and an evaluation of a range of resource portfolios over a twenty-year planning horizon.

Consistent with the 2024 IRP, we are replacing older generation resources at the Aberdeen Generating Station, with construction of Aberdeen Generating Station Units 3 & 4 underway and an expected in-service date in 2026. This project is expected to provide approximately 33 MW of nameplate capacity at a total projected cost of approximately $65.0 million, of which approximately $29.0 million is expected to be incurred in 2026.

The SPP has recently updated its resource accreditation and Planning Reserve Margin (PRM) requirements in response to growing reliability concerns. As a result, SPP is requiring additional accredited capacity by 2030 to meet the updated PRM targets. In October 2025, we submitted a project with the SPP under their Expedited Resource Adequacy Study program for the construction of a 131 MW natural gas generating facility located in Aberdeen, South Dakota, to meet regional capacity needs by 2030. Anticipated costs for this project are approximately $300.0 million.

NATURAL GAS OPERATIONS

Montana

Our regulated natural gas utility business in Montana, which is conducted through NW Corp, includes production, storage, transmission and distribution. During 2025, we distributed natural gas to approximately 249,400 customers in 123 Montana communities over a system that consists of approximately 5,900 miles of underground distribution pipelines. We also serve a smaller distribution company that provides service to approximately 1,417 customers. We transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of approximately 51 Bcf during the year ended December 31, 2025.

We have connections in Montana with five major, unaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Black Hills Energy, and Many Islands Pipeline. Thirteen compressor sites provide more than 51,400 horsepower on the transmission line and an additional 16,586 horsepower at our storage fields, capable of moving more than 400,000 dekatherms per day. In addition, we own and operate two transmission pipelines through our subsidiaries, Canadian-Montana Pipe Line Corporation and Havre Pipeline Company, LLC.

Natural gas is used primarily for residential and commercial heating, and as fuel for three electric generating facilities. The demand for natural gas largely depends upon weather conditions. Our Montana retail natural gas supply requirements for the year ended December 31, 2025, were approximately 22.8 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2025, were approximately 10.8 Bcf. We have contracted with several major producers and marketers with varying contract durations to provide the anticipated supply to meet ongoing requirements. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, short-term market purchases and owned production. Our portfolio approach to natural gas supply is intended to enable us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in significant natural gas producing regions in the United States, primarily the Rocky Mountains (Colorado), Montana, and Alberta, Canada.

Owned Production and Storage - Since 2010, we have acquired gas production and gathering system assets as a part of an overall strategy to provide rate stability and customer value: as we own these assets, which are regulated, our customers are better protected from potential price spikes in the market. As of December 31, 2025, these owned reserves totaled approximately 25.3 Bcf and are estimated to provide approximately 2.76 Bcf in 2026, or approximately 14 percent of our expected annual retail natural gas load in Montana. In addition, we own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 17.85 Bcf and maximum aggregate daily deliverability of approximately 194,000 dekatherms.

South Dakota and Nebraska

Through NWE Public Service, we provide natural gas to approximately 51,200 customers in 82 South Dakota communities and approximately 43,400 customers in 4 Nebraska communities. In South Dakota, we also transport natural gas for nine gas-marketing firms and three large end-user accounts. In Nebraska, we transport natural gas for four gas-marketing firms and one large end-user account. We delivered approximately 31.0 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.8 Bcf of third-party transportation volume on our Nebraska distribution system during 2025.

Our South Dakota natural gas supply requirements for the year ended December 31, 2025, were approximately 6.3 Bcf. We contract with a third party under an asset management agreement to manage transportation and storage of supply to minimize cost and price volatility to our customers. In Nebraska, our natural gas supply requirements for the year ended December 31, 2025, were approximately 4.1 Bcf. We contract with a third party under an asset management agreement that includes pipeline capacity, supply, and asset optimization activities. To supplement firm gas supplies in South Dakota and Nebraska, we contract for firm natural gas storage services to meet the heating season and peak day requirements of our customers.

Municipal Natural Gas Franchise Agreements

We have municipal franchises to provide natural gas service in the communities we serve in Nebraska and South Dakota. The terms of the franchises vary by community. The maximum term permitted under Nebraska law for these franchises is 25 years while the maximum term permitted under South Dakota law is 20 years. Our policy generally is to seek renewal or extension of a franchise in the last year of its term. We continue to serve those customers while we obtain formal renewals. In the 2025 Montana legislative session, new language was enacted eliminating the requirement for gas franchise agreements. Under this law, utility providers may construct and maintain natural gas lines within the public rights-of-way without obtaining a franchise agreement. Two of our South Dakota franchises and two of our franchises in Nebraska, which account for approximately 32,613 or 34 percent of our South Dakota and Nebraska natural gas customers, are scheduled to reach the end of their fixed term during the next five years. We do not anticipate termination of any of these franchises.

GOVERNMENT REGULATION

Our provision of utility service is regulated by the MPSC, the SDPUC, the NPSC, and the FERC. We are also regulated by many other state and federal agencies. For example, because our operations impact land, waterways and the air, we are subject to a wide range of regulations administered by the federal EPA, the U.S. Fish & Wildlife Service, and parallel state agencies regulating environmental and natural resources in Montana, South Dakota and Nebraska. Another example relates to our provision of natural gas service. The U.S. Department of Transportation through the Pipeline and Hazardous Materials Safety Administration, along with its state partners, regulates natural gas pipeline and natural gas storage field safety. As a publicly-traded company, we are subject to the SEC’s requirements regarding financial reporting, disclosures, and laws and regulations protecting investors. We are subject to the Occupational Safety and Health Administration (OSHA), which regulates workplace safety. We are also subject to local zoning laws and regulations.

As detailed below, the rates we charge our utility customers are set through approval by the regulatory commission with jurisdiction in each of our respective service territories. Base rates are the rates that are intended to allow us the opportunity to collect from our customers total revenues (revenue requirements) equal to our cost of providing delivery and rate-based supply services, plus a reasonable rate of return on invested capital. We have both electric and natural gas base rates and cost tracking clauses. We may ask the respective regulatory commission to increase base rates from time to time. Rate increase requests are normally reviewed based on historical data and any resulting approvals may not always keep pace with increasing costs. For more information on current regulatory matters, see Note 5 - Regulatory Matters, to the Consolidated Financial Statements.

The following is a summary of our rate base (amounts we earn a return on) and authorized rates of return in each jurisdiction, estimated as of December 31, 2025:

(1) The revenue requirement associated with the FERC regulated portion of Montana electric transmission and ancillary services are included as revenue credits to our MPSC jurisdictional customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns.

(2) The Montana gas revenue requirement includes a step-down which approximates annual depletion of our natural gas production assets included in rate base.

(3) This jurisdiction was acquired in 2025 as part of the acquisition of Energy West Operations. For additional information regarding this acquisition, see Note 4 - Acquisition of Energy West Operations to the Consolidated Financial Statements included herein.

(4) This table excludes insignificant jurisdictions for Montana propane delivery, Havre Pipeline Company, and Cut Bank Gas natural gas delivery.

(5) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms.

MPSC Regulation

Nearly all of our Montana operations are subject to the jurisdiction of the MPSC with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations, including when we issue, assume, or guarantee securities in Montana, or when we create liens on our regulated Montana properties. We have an obligation to provide service to our customers with an opportunity to earn a regulated rate of return.

Electric Supply Tracking Mechanism - The PCCAM tracks, for recovery through utility rates, the cost of power purchased and fuel used to generate electricity. The PCCAM incorporates sharing of a portion of the business risk or benefit associated with the energy supply costs with 90 percent of the variance above or below the established base revenues and actual costs collected from or refunded to customers. As part of its December 2025 order, the MPSC has suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. See Note 5 - Regulatory Matters within the Consolidated Financial Statements for further information. Certain PCCAM rates are adjusted on a quarterly basis for volumes and costs during each July to June 12-month tracking period based on the established base revenues and actual costs collected from or refunded to customers. Customer prices may be adjusted annually to absorb the difference for the annual tracking period. Annual filings are based on a July through June 12-month tracking period, and are subject to review by the MPSC to determine if electric supply procurement activities were prudent. If the MPSC subsequently determines that a procurement activity was imprudent, recovery of such costs may be disallowed.

Natural Gas Supply Tracker - Rates for our Montana natural gas supply are set by the MPSC. Certain supply rates are adjusted on a monthly basis for volumes and costs during each July to June 12-month tracking period based on the established base revenues and actual costs collected from or refunded to customers. Customer prices may be adjusted annually to absorb the difference for the annual tracking period. Annual filings are based on a July through June 12-month tracking period, and are subject to review by the MPSC to determine if natural gas supply procurement activities were prudent. If the MPSC subsequently determines that a procurement activity was imprudent, recovery of such costs may be disallowed.

Montana Property Tax Tracker - We file an annual property tax tracker (including other state/local taxes and fees) with the MPSC for an automatic rate adjustment, which reflects the incremental property taxes since our last base rate filing adjusted for the associated income tax benefit.

SDPUC Regulation

Our South Dakota operations are subject to SDPUC jurisdiction with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our electric and natural gas operations. Our retail electric rates, approved by the SDPUC, provide several options for residential, commercial and industrial customers, including dual-fuel, interruptible, special all-electric heating, and other special rates. Our retail natural gas tariffs include gas transportation rates for transportation through our distribution systems by customers and natural gas marketers from the interstate pipelines at which our systems take delivery to the end-user. Such transporting customers nominate the amount of natural gas to be delivered daily. On a daily basis, we monitor usage for these customers and balance it against their respective supply agreements.

Adjustment Clauses - An electric adjustment clause provides for quarterly adjustment based on differences in the delivered cost of energy, delivered cost of fuel, ad valorem taxes paid and commission-approved fuel incentives. A purchased gas adjustment provision in our natural gas rate schedules permits the monthly adjustment of charges to customers to reflect increases or decreases in purchased gas, gas transportation, and ad valorem taxes. The adjustment clauses for both electric and gas utilities go into effect upon filing, and are deemed approved within 10 days after the information filing unless the SDPUC Staff requests changes during that period.

Phase In Rate Plan Rider - Effective July 1, 2025, we received approval to begin recovering costs for Aberdeen Generating Station Units 3 & 4 through our Phase in Rate Plan Rider. This tariff allows recovery of capital investments without filing a general electric rate review. SDPUC approval of the plan and associated project cost recovery are required. An update to this plan is required to be filed with the SDPUC by June 1 of each year.

NPSC Regulation

Our Nebraska natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated by the NPSC. High volume customers are not subject to such regulation, but can file complaints if they allege discriminatory treatment. Under the Nebraska State Natural Gas Regulation Act, a regulated natural gas utility may propose a change in rates to its regulated customers, if it files an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the proposed rate change if the affected communities representing more than 50 percent of the affected ratepayers agree to direct negotiations, or it may proceed to have the NPSC review the filing and make a determination. Our tariffs have been approved by the NPSC, and the NPSC has adopted certain rules governing the terms and conditions of service of regulated natural gas utilities. Our retail natural gas tariffs provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for biannual, or more often if needed, adjustments based on changes in gas supply and interstate pipeline transportation costs.

FERC Regulation

We are subject to FERC's jurisdiction and regulations with respect to rates for electric transmission service and electricity sold at wholesale, hydro licensing and operations, the issuance of certain securities, incurrence of certain long-term debt, and compliance with mandatory reliability standards, among other things. Under FERC's open access transmission policy, as owners of transmission facilities, we are required to provide open access to our transmission facilities under filed tariffs at cost-based rates. In addition, we are required to comply with FERC's Standards of Conduct for Transmission Providers.

Our Montana wholesale transmission customers, such as cooperatives, industrial customers, and other customers that have third-party commodity supply providers, receive transmission delivery service under our OATT, which is on file with FERC. The OATT defines the terms, conditions, and rates of our Montana transmission service, including ancillary services. These transmission rates are adjusted annually through formula rates. Our South Dakota transmission operations are in the SPP, and transmission service is provided under the SPP OATT. These transmission rates are adjusted annually through formula rates.

The electricity sold from NW Colstrip 370, which has a 25 percent ownership interest in Colstrip Units 3 & 4, is subject to the FERC's jurisdiction and regulations with respect to rates for electricity sold at wholesale. We have submitted a request to the FERC for approval of cost-based rates and expect this rate approval to be effective in the first quarter of 2026. We have signed a contract to sell the dispatchable capacity and associated energy from NW Colstrip 370 through late 2027. This contract is subject to the approval by the FERC.

Our natural gas transportation pipelines are generally not subject to FERC's jurisdiction, although we are subject to state regulation. We conduct limited interstate transportation in Montana and South Dakota that is subject to FERC jurisdiction, and FERC has allowed the MPSC and SDPUC to set the rates for this interstate service. We have capacity agreements in South Dakota and Nebraska with interstate pipelines that are also subject to FERC jurisdiction.

Our hydroelectric generating facilities are licensed by the FERC and operated in accordance with the terms of those licenses and applicable FERC regulations. As part of the relicensing process, federal law authorizes FERC to issue a new license to the current licensee, to a different licensee, or, alternatively, permits the U.S. government to assume ownership and operation of the facility. If the existing licensee is not granted a new license, it is entitled to compensation equal to its net investment in the facility, not to exceed the fair value of the property taken, plus reasonable severance damages for other property adversely affected by the loss of the license.

Reliability Standards - We must comply with the standards and requirements that apply to the NERC functions for which we have registered in both the MRO for our South Dakota operations and the WECC for our Montana operations. WECC and the MRO have responsibility for monitoring and enforcing compliance with the FERC-approved mandatory reliability standards within their respective regions. We expect that the reliability standards will continue to evolve and change as a result of modifications, guidance, and clarification following industry implementation and ongoing audits and enforcement.

COMPETITION

We are subject to public policies that promote competition and development of energy markets. Certain of our industrial and large commercial customers have the ability to choose their electric supplier and may generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region. Customers have the opportunity to supply their own power with distributed generation including solar generation, and in Montana, can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. These incentives and federal tax subsidies make distributed generating resources viable potential competitors to our electric service business.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. Our wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use our transmission systems to serve their load. There is also competition for available transmission capacity to meet our electric supply needs to serve customers.

ENVIRONMENTAL

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, and protection of natural resources and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are issued, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

In 2024, the EPA released final rules that will potentially impose requirements on fossil fuel assets, however, in 2025, the EPA issued multiple Notices of Proposed Rulemaking that would remove these additional requirements on fossil fuel assets. There is no mandated timeline for final action on these rules. If the MATS Rules are implemented and enforced as currently written, between now and 2028 total compliance costs for the Colstrip plant are estimated to range from $350 million to $665 million, of which we would be responsible for our proportionate share. This estimate has been developed by the Colstrip operator and represents an initial high-level scoping estimate that will require significant refinement to narrow the range of costs, which is currently underway. Without change, implementation of existing environmental regulations have the potential to limit or curtail our operations, including the burning of fossil fuels at our coal-fired and some natural gas power plants. While we strive to comply with all environmental regulations applicable to our operations, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to energy and environmental laws and regulations, or new administrative or judicial interpretations or enforcement decisions regarding them.

For more information on environmental regulations and contingencies and related capital expenditures, see Note 20 - Commitments and Contingencies, to the Consolidated Financial Statements.

CORPORATE INFORMATION AND WEBSITE

We were incorporated in Delaware on May 30, 2023. Our Internet address is https://www.northwesternenergy.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, along with our annual report to shareholders and other information related to us, are available, free of charge, on our Internet website as soon as reasonably practicable after we electronically file those documents with, or otherwise furnish them to, the SEC. This information is available in print to any shareholder who requests it. Requests should be directed to: Investor Relations, NorthWestern Energy Group, 3010 W. 69th Street, Sioux Falls, South Dakota 57108 and our telephone number is (605) 978-2900. References to our website in this report are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this report.

HUMAN CAPITAL RESOURCES

Our ability to achieve the objectives of our business strategy and serve our customers within our service territory depends on employing and continually investing in the development of skilled individuals at all levels of our organization. We aspire to be an employer of choice and a great workplace by offering competitive salaries and benefits and providing a safe working environment where employees can grow personally and in their careers. We value diversity, foster inclusion and encourage a healthful work–life balance that includes taking personal time and giving back to the communities we live and work in. Our success comes when employees feel purpose in the work they do and empowered to take initiative, voice their opinions, and build on their experiences within our company and our communities.

As of December 31, 2025, we had 1,667 employees. Of these, 1,353 employees were in Montana and 314 were in South Dakota or Nebraska. Of our Montana employees, 489, or 36 percent are covered by five unions under eight collective bargaining agreements. All eight of these collective bargaining agreements are set to expire in 2026 and are currently under renegotiation. Of our South Dakota and Nebraska employees, 167, or 53 percent, are covered by a collective bargaining agreement that is set to expire in 2026 and is now being renegotiated. We consider our relations with employees and union leadership to be positive and respectful.

Talent Management

Attraction and retention of skilled employees is key to our ongoing success. We invest resources in maintaining a culture that supports the ongoing development of our workforce. This includes an integrated learning and performance management system which includes annual performance reviews that link goals and competencies together so that managers are able to provide a holistic view to employees in regards to their performance against goals as well as key competencies as they relate to their role in the organization. This process provides opportunities to develop and enhance skills and knowledge, and enables our employees to grow professionally and perform their duties in a safe and efficient manner. This structured training and development is intended to provide employees a consistent learning experience, and maximizes learning retention and background knowledge. We offer tuition reimbursement to promote continued professional growth for current employees, and a scholarship program for students attending universities, colleges, and technical schools in our service area to assist in developing current and future skills sets needed by our employees. We support annual pre-apprentice scholarships, recruit and hire suitable candidates from the program, serve as industry advisors on the program board and have donated training assets to support the program.

Hiring, promotions, work assignments, or other decisions related to the terms and conditions of employment are made by considering skills, experience, proven track record of performance, and other traits that serve to create a team with varied strengths and backgrounds. Our workforce reflects the available talent in the communities we serve. In compliance with current mandates, our employment data is tested annually by a third party. This testing determined that there is no current need to establish corrective placement goals.

Compensation and Benefits

Our overarching compensation philosophy is structured to be consistent with our peers, and to align the long-term interests of our employees, executives, shareholders, and customers so the pay appropriately reflects performance in achieving financial and non-financial operating objectives. We offer a competitive pay and benefits package, which is benchmarked on an annual basis to external market data. Beyond base pay and incentive compensation, we offer competitive, cost-effective, and well- rounded benefits, which aligns with our desire to be an employer of choice. From considerable employer retirement contributions, to generous paid time off, to health care and well-being programs, our benefits are designed to meet the varied needs of our employees.

We are committed to internal pay equity, and the Human Resources Committee of the Board of Directors monitors the relationship between the pay our executive officers receive and the pay our non-managerial employees receive. During 2025 and 2024, the compensation for our Chief Executive Officer (CEO) was approximately 36 and 34 times, respectively, the compensation of our median employee.

We believe that a significant portion of an executive’s pay should be at risk in the form of performance-based incentive awards that are only paid if the individual and company performance targets are met. For 2025, approximately 82 percent of the targeted compensation of our CEO and about 63 percent of the targeted compensation of our other named executive officers is at risk in the form of performance-based incentive awards or time-based awards tied to the value of equity. Our Board of Directors establishes the metrics and targets for these incentive awards, based upon advice from the Board of Directors’ independent compensation consultant. In addition, our compensation practices have led to a relatively low CEO to median employee ratio of approximately 36 to 1 for 2025.

We engage nationally recognized outside compensation and benefits consulting firms to independently evaluate the effectiveness of our compensation and benefits programs and to provide benchmarking against our peers within the industry. We provide pay equity between our employees performing equal or substantially similar work. We engage a third party to review our pay equity and share the results with our Board of Directors. Our most recent study was performed in 2024, with no corrective action required.

Health and Safety

As stewards of critical infrastructure, providers of energy service, and members of the communities we serve, our top service value is the safety and well-being of our employees and customers. We integrate safety and health into every aspect of our business, continuously monitoring various areas related to safety practices and policies. Key metrics include the recordable incident rate (the number of work-related injuries per 100 employees over a one-year period) and the lost time incident rate (the number of employees who miss work due to work-related injuries per 100 employees over a one-year period). During the years ended December 31, 2025 and 2024, our recordable incident rates were 1.73 and 1.65, respectively, and lost time incident rates were 0.54 and 0.57, respectively, on a company wide basis.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

(1) As of February 6, 2026.

(2) Michael Cashell has announced that he will retire from the Company in April of 2026.

Officers are elected annually by, and hold office at the pleasure of, the Board of Directors (Board), and do not serve a “term of office” as such.

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.

Summary Risk Factors

The following is a summary of some of the risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flows in the future. You should read this summary together with the more detailed description of each risk factor contained below.

Regulatory, Legislative and Legal Risks

• Our ability to recover prudently incurred costs and earn authorized returns depends on regulatory outcomes;
• Changes in laws, energy policies, or regulatory frameworks may increase costs or limit growth;
• Environmental compliance requirements may require significant investments, which may or may not be recoverable, or early retirements of certain generating facilities;
• Exposure to litigation may delay projects or restrict operations;
• Reliability and safety compliance failures could result in substantial penalties; and
• Mandated QF purchases may increase costs and limit investment flexibility.

Operational Risks

• Utility operations involve hazards that may cause outages, injuries, or environmental harm;
• Increasing fire risk may lead to significant claims or penalties;
• System constraints may limit reliable service or access to lower-cost supply;
• Reliance on market purchases exposes us to price volatility and counterparty risks;
• Weather variability impacts loads, supply, hydrology, and financial performance;
• Fuel supply disruptions may increase costs or reduce generation availability;
• Decreasing customer usage may reduce revenues and increase system costs;
• Cyber and physical security threats may disrupt operations or compromise data;
• Supply-chain delays, inflation, and labor shortages may impair operations; and
• Workforce challenges may affect safety, operations, and project execution.

Liquidity and Financial Risks

• Insurance coverage may be insufficient for certain risks;
• Capital projects and acquisitions carry permitting, cost, and recovery risks;
• Access to capital markets may be constrained by interest rates or volatility;
• Energy transition policies and technologies present financial and operational risks;
• Credit rating downgrades would increase borrowing costs and collateral needs;
• QF minimum energy obligations may expose us to higher replacement power costs;
• Changes in tax laws may affect earnings and cash flows;
• Counterparty defaults may impact liquidity;
• Pension and benefit plan performance may increase costs; and
• We rely on subsidiary dividends subject to regulatory constraints.

Risks Related to the Merger

• The fixed exchange ratio creates variability in merger consideration value;
• Required approvals may delay, condition, or prevent merger completion;
• Deal protections and termination fees may discourage alternatives;
• Merger uncertainty may impact stock price, ratings, and operations; and
• Merger-related litigation may cause delays or additional costs.

Risks Relating to the Combined Company Following Completion of the Merger

• Integration challenges may delay or reduce anticipated synergies;
• NorthWestern shareholders will have reduced ownership and voting influence;
• Significant indebtedness may increase refinancing and interest-rate risks;
• Goodwill created in the merger may be subject to impairment;
• Tax attribute limitations may reduce expected NOL benefits;
• Future dividends are not assured; and
• Issuance of new Black Hills Common Stock could negatively impact the Black Hills Common Stock price

Regulatory, Legislative and Legal Risks

Our profitability depends on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We are subject to potential unfavorable litigation, and state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs or collect them in a timely manner, which could adversely impact our results of operations and liquidity.

We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and rates that we can charge customers. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital and rates are generally set through a process called a rate review (or rate case) in which the utility commission analyzes our costs incurred during a historical test year and decides whether they may be included in our base rates. In addition to formal general rate reviews, we also have cost tracking mechanisms that are intended to allow us to recover prudently incurred costs. There can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in rates that allow us the opportunity to earn our authorized return or provide for timely and full recovery of such costs. In 2025, the MPSC disallowed $30.9 million of capital costs that they deemed were not prudently incurred related to the construction of YCGS. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Differing schedules and regulatory practices between our state commissions and FERC expose us to the risk that we may not fully recover our costs due to timing of filings, specific calculations and issues such as cost allocation methodologies. We are required to have FERC approved cost based rates or FERC approved contract rates in order to sell electricity in the wholesale market. Absent these rates, we may be subject to refund of some or all of the revenue collected. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Adverse regulatory rulings could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on our common stock.

We are subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.

We are subject to regulations under a wide variety of U.S. federal and state regulations and policies. Regulation affects almost every aspect of our business. Changes to federal and state laws and regulations are continuous and ongoing and the federal administration, the U.S. Congress, state legislatures and state administrations may enact and implement new laws and regulations that could adversely and materially affect us. For example, legislation and regulations may be enacted that require or facilitate alternative generation or storage which, in turn, could result in customers using less of our energy or facilities which could reduce our revenues and our growth opportunities. We cannot predict future changes in laws and regulations, how they will be implemented and interpreted, or the ultimate effect that this changing environment will have on us. There can be no assurance that laws, regulations and policies will not be changed in ways that have a material adverse effect on our operations, financial condition, results of operations, and cash flows.

We are subject to extensive and changing energy, and environmental laws and regulations with which compliance may be difficult and costly.

Our operations are subject to laws and regulations imposed by federal, state and local government authorities regarding energy policy, permitting/siting for energy projects, the environment, air and water quality, GHG emissions, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations.

In response to recent regulatory and judicial decisions and international accords, GHG emissions, most significantly CO2, could be restricted in the future as a result of federal or state legal requirements or litigation relating to GHG emissions. In 2024, the EPA released final rules that will potentially impose requirements on fossil fuel assets, however, in 2025, the EPA issued multiple Notices of Proposed Rulemaking that would remove these additional requirements on fossil fuel assets. There is no mandated timeline for final action on these rules. If these promulgated GHG and MATS Rules are implemented and enforced as currently written, they may affect our ability to reliably serve our customers and we could be subject to significant additional compliance costs that would affect our future financial position, results of operations, and cash flows if such costs are not recovered through regulated rates. Such changes also could affect the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.

To the extent that costs exceed our estimated environmental liabilities, or we are not successful in recovering remediation costs or costs to comply with the proposed or any future changes in rules or regulations, our results of operations and financial position could be adversely affected. Certain environmental laws and regulations also provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities.

In addition, there is a risk of environmental damage claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.

We are also at risk of unfavorable litigation outcomes related to zoning and environmental permits. In 2023, due to lawsuits filed by the Montana Environmental Information Center and Sierra Club alleging that the environmental analysis conducted by the MDEQ prior to the issuance of the YCGS air quality construction permit was inadequate, the Montana District Court issued an order vacating our YCGS air quality permit pending the MDEQ addressing the identified deficiencies. While we eventually were successful in staying this order, and the air quality permit was subsequently reinstated, due to this litigation we paused construction for approximately three months, causing us to incur substantial additional costs. Adverse litigation outcomes, such as this, could cause us to delay or terminate projects, increase costs and impact our ability to service our customers.

Early closure of our owned and jointly owned electric generating facilities due to environmental risks, litigation or public policy changes could have a material adverse impact on our results of operations and liquidity.

While a majority of our Company-wide electric supply portfolio is carbon-free, it does include fossil-fuel resources. Environmental advocacy groups, certain investors and other third parties oppose the operation of fossil-fuel generation, expressing concerns about the environmental-related impacts from fossil fuels. This opposition may increase in scope and frequency depending on a number of variables, including the course of Federal and State laws and environmental regulations and the financial resources devoted to opposition efforts. These risks include litigation against us due to GHG or other emissions or coal combustion residuals disposal and storage; activist shareholder proposals; and increased activism before our regulators. We cannot predict the effect that any such opposition may have on our ability to operate and recover the costs of our generating facilities. In addition, defense costs associated with litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

In particular, as described more fully below in Note 20 - Commitments and Contingencies to the Consolidated Financial Statements included herein, we are a co-owner of the coal-fired Colstrip Units 3 & 4 generating facility. The remaining depreciable life of our investments in Colstrip Units 3 & 4 is through 2042.

Increased risks of regulatory penalties could negatively impact our business.

We must comply with established reliability standards and requirements including Critical Infrastructure Protection Reliability Standards, which apply to NERC functions. NERC reliability standards protect the nations’ bulk power system against potential disruptions from cyber and physical security breaches. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Penalties for the most severe violations can reach nearly $1.2 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.

Additionally, the Pipeline and Hazardous Materials Safety Administration, Occupational Safety and Health Administration and other federal or state agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.

Federally mandated purchases of power from QFs, and integration of power generated from those projects in our system, may increase costs to our customers and decrease system reliability, limit our ability to make generation investments and adversely affect our business.

We are generally obligated under federal law to purchase power from certain QF projects, regardless of current load demand, availability of lower cost generation resources, transmission availability or market prices. Although some of these resources include a battery component, they are primarily intermittent generation whose prices may be in excess of market prices during times of lower customer demand, and may not be able to generate electricity during peak times. These resources typically do not meet the requirements set forth in our supply plans for resource procurement. These requirements to purchase supply that is inconsistent with customer need may have multiple impacts, including increasing the likelihood and frequency that we will be required to reduce output from owned generation resources, negatively impacting our ability to make our own generation investments and increasing the likelihood that we will need to upgrade or build additional transmission facilities to serve QF projects. Any of these results would increase costs to customers and impact our investment plan. Further, balancing load and power generation on our system is challenging, and we expect that operational costs will increase as a result of integration of these intermittent, non-dispatchable generation projects. If we are unable to timely recover those costs, those increased costs may negatively affect our liquidity, results of operations and financial condition.

In addition, requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs that are inconsistent with resource plans developed based on a lowest cost and least risk basis while placing upward pressure on overall customer bills. This may impact our investment plans and financial condition. Finally, the requirement to procure power from these QF sources may impact our transmission system and require additional transmission facilities to be developed in order to integrate these resources, which also can impact overall customer bills.

Operational Risks

Our electric and natural gas operations involve numerous activities that may result in accidents, fires, system outages and other operating risks and costs that are unique to our industry.

Inherent in our electric transmission and distribution and natural gas transmission and distribution operations are a variety of hazards and operating risks, such as breakdown or failure of equipment or processes, interruptions in fuel supply, supply chain interruptions, labor disputes, operator error, and catastrophic events such as fires, electric contacts, leaks, explosions, floods and intentional acts of destruction. For our natural gas lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks could be significant. These risks could cause a loss of human life, facility shutdown or significant damage to property, service interruption, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others.

Fire risk is significant in the western United States, including in our service territory. Various factors in recent years have contributed to increasing fire risk including dead and dying trees, warmer air temperatures, drought, wind, forest management practices, and land management practices. These factors increase the risk of a fire in both forests and grasslands. In forested areas, this issue has been heightened by mountain pine beetle and other infestations weakening and killing trees in our service territory. Residential and commercial development into the wildland-urban interface has also led to an increasing trend in the degree of destruction from wildfires.

Fires alleged to have been caused by our equipment potentially expose us to significant penalties and/or damage awards based on claims of strict liability, negligence, gross negligence, inverse condemnation, nuisance, trespass and others. Our equipment has been alleged to be involved in igniting wildfires although none have had a material adverse effect on our financial condition or results of operations.

For our electric generating facilities, operational risks include facility shutdowns due to breakdown or failure of equipment or processes, interruptions in fuel supply, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation, litigation or regulation. The loss of a major electric generating facility would require us to find other sources of supply or ancillary services, if available, and expose us to higher purchased power costs and potential litigation which may not be recovered from customers.

We maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Additionally, during peak-load periods our electric and natural gas systems in Montana are constrained. These constraints limit our ability to transmit electric energy within Montana and access electric energy from outside the service area. Our electric transmission facilities are also interconnected with those of third parties, and thus operation of these facilities could be adversely affected by unexpected or uncontrollable events. Our natural gas system is also constrained, which limits our on-system deliverability and the ability to transport gas. We are similarly exposed to risk of interconnection with third-party pipelines and are dependent upon their operation to serve customers. These transmission constraints and events could result in failure to provide reliable service to customers due to the inability to deliver energy supply resources, or could result in significant cost increases due to the inability to access lower cost sources of energy supply.

Our electric and natural gas portfolios rely significantly on market purchases. This exposure adversely affects our ability to manage our operational requirements to reliably serve our customers, while exposing us to market volatility, which ultimately could adversely affect our results of operations and liquidity.

We are obligated to supply power to retail customers and certain wholesale customers and procure natural gas to supply fuel for our natural gas fired generation. Our need to acquire flexible energy supply and capacity in the market to meet our electric and natural gas load serving obligations exposes us to certain risks including the ability to reliably serve customers and significant uncertainty in the cost of supply, which may not be recoverable. We rely upon a combination of base-load supply from our owned and long-term contracted generation and market purchases to serve customers. During peak periods, power demand could exceed, and has exceeded, the available capacity of our owned and long-term contracted generation capacity, requiring us to purchase capacity and energy from the market. In the past, we have relied upon both in-state and out-of-state power purchase agreements for grid reliability and to physically serve customers. A significant number of base-load generation facilities, which may also serve to meet peak requirements, in the state and region have been retired or are scheduled to be retired in the next five to ten years.

This includes Colstrip Units 1 and 2, representing 614 MWs of generation on a capacity basis, which ceased operations in January 2020. A decrease in the state and region’s electric capacity, whether for operational reasons or litigation outcomes, may impair the reliability of the grid, particularly during peak demand periods. There can be no assurance that there will be available counterparties to contract with to serve our customers' needs, or that these counterparties will fulfill their obligations to us. There is also no assurance that the transmission capacity required to import market purchases will be available on transmission systems owned by us or by third parties. In addition, the suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us. These conditions could result in an inability to physically deliver electricity to our customers. Losing electric service during extreme conditions carries significant consequences, as without our services our customers may be subjected to dire circumstances.

Commodity pricing is an inherent risk component of our business operations and our financial results. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our costs are recoverable, as discussed above. The prevailing market prices for electricity may fluctuate substantially over relatively short periods of time, potentially adversely impacting our results of operations, financial condition and cash flows due to our need for market purchases and the sharing component of the Montana PCCAM. During recent periods, we have had a significant under-collection of these costs impacting our results of operations and cash flows. As described more fully below in Note 5 - Regulatory Matters to the Consolidated Financial Statements included herein, while the MPSC has suspended the sharing component of the Montana PCCAM beginning on February 1, 2026, pending further review, there can be no assurances that a final order will be issued eliminating this sharing component.

In addition, our natural gas system serves both retail customers and the needs of natural gas fired electric generation. The natural gas system has capacity constraints that expose us to risks to be able to deliver natural gas during periods of peak demand.

Fluctuations in actual weather conditions, generation availability, transmission constraints, and generation reserve margins may all have an impact on market prices for energy and capacity and the electricity consumption of our customers on a given day. Extreme weather conditions may force us to purchase electricity in the short-term market on days when weather is unexpectedly severe, and the pricing for market energy may be significantly higher on such days than the cost of electricity in our existing generation and contracts. Unusually mild weather conditions could leave us with excess power which may be sold in the market at a loss if the market price is lower than the cost of electricity in our existing contracts.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events, could adversely affect our ability to manage our operational requirements to serve our customers, and ultimately adversely affect our results of operations and liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters or cool summers could adversely affect our results of operations and financial position. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas. Our sensitivity to weather volatility is significant due to the absence of regulatory mechanisms, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs.

Severe weather impacts, including but not limited to, blizzards, thunderstorms, high winds, microbursts, floods, fires, tornadoes and snow or ice storms can disrupt energy generation, transmission and distribution. We derive a significant portion of our energy supply from hydroelectric facilities, and the availability of water can significantly affect operations. Higher temperatures may decrease the Montana snowpack and impact the timing of run-off and may require us to purchase replacement power. Dry conditions, which exist in the West and in our service territory, also increase the threat of fires, which could threaten our communities and electric distribution and transmission lines and facilities. In addition, fires that are alleged to have been caused by our system could expose us to substantial property damage and other claims. Any damage caused as a result of fires could negatively impact our financial condition, results of operations or cash flows.

Extreme weather conditions, especially those of prolonged duration, create high energy demand on our own and/or other systems and increase the risk we may be unable to reliably serve customers, causing brownouts and/or blackouts of our electric systems, and loss of gas supply. Risk of losing electricity or gas supply during extreme weather carries significant consequences as without our services our customers may be subjected to dire circumstances. Additionally, extreme weather conditions may raise market prices as we buy short-term energy to serve our own system. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. In addition, we may not recover all costs related to mitigating these physical and financial risks.

Our results of operations may be impacted by disruptions to fuel supply or the electric grid that are beyond our control.

We are exposed to risks related to performance of contractual obligations by our suppliers, which includes parties transporting natural gas. We are dependent on coal and natural gas for a significant portion of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short- and long-term contracts. We have certain supply and transportation contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply and deliver coal and natural gas to us. For instance, there currently is litigation pending relating to adequacy of certain permits for the Rosebud Mine in Montana, which supplies coal to Colstrip and contains significant quantities of coal. In order to operate the Colstrip facility through its currently identified depreciable life of 2042, it will be necessary to identify and contract for coal supply subsequent to expiration of our current contract in 2033. Moreover, the suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply or transport coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather, availability of equipment and labor shortages. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm, generator or transmission facility outage on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position, results of operations and cash flows.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions or response to price increases. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.

Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, and the use of distributed generation resources or other emerging technologies for electricity. Advances in distributed generation technologies that produce power, including fuel cells, micro-turbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production. Customer-owned generation itself reduces the amount of electricity purchased from utilities and may have the effect of inappropriately increasing rates generally and increasing rates for customers who do not own generation, unless retail rates are designed to collect distribution grid costs across all customers in a manner that reflects the benefit from their use. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy.

Decreasing use per customer (driven, for example, by appliance and lighting efficiency) and the availability of cost-effective distributed generation, put downward pressure on load growth. There can be no assurance that load growth from large-load customers, such as data centers, will be realized. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, market participants, transmission availability, the availability of generation, and the ongoing development of the Western EIM, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations. Failure to maintain the security of personally identifiable information could adversely affect us.

Business Operations - We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber attacks, physical security breaches and other disruptive activities of individuals or groups, and theft of our critical infrastructure information. Our generation, transmission and distribution facilities are deemed critical infrastructure and provide the framework for our service infrastructure. Cyber crime, which includes the use of malware, phishing attempts, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years. The advancement of artificial intelligence and large language models has given rise to additional vulnerabilities and potential entry points for cyber crime. Our assets and the information technology systems on which they depend are direct targets of, or are indirectly affected by, cyber attacks and other disruptive activities, including those that impact third party facilities that are interconnected to us. Any significant interruption of these assets or systems could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential and other data could be compromised.

Security threats continue to evolve and transform. The risk of cyber-based attacks is heightened due to recent geopolitical events as well as employees working and accessing our technology infrastructure remotely. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, to confidential data, or to disrupt operations. With the continuing rise in ransomware and other cyber-based threats we continuously analyze our technology platforms and monitoring for signs of potential intrusions. There is also a risk of exposure of confidential or proprietary data through the inadvertent use of open artificial intelligence tools. We periodically engage with our vendors, suppliers and contractors to establish that they are taking appropriate measures. None of these attempts has individually or in the aggregate resulted in a security incident with a material impact on our financial condition or results of operations. However, despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact.

These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for electricity, natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.

Personally Identifiable Information - Our information systems and those of our third-party vendors contain confidential information, including information about customers and employees. Customers, shareholders, and employees expect that we will adequately protect their personal information. The regulatory environment surrounding information security and privacy is increasingly demanding. A data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject us to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies. It could also reduce the value of proprietary information, and harm our reputation.

We maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We may have difficulty cost-effectively completing certain operations activities and construction projects due to inflationary pressures or if our third-party business partners are unable to deliver ordered supplies or complete contracted services timely, including workforce shortages or macro supply chain disruptions.

We place significant reliance on our third-party business partners to supply materials, equipment and labor necessary for us to operate our utility and reliably serve current customers and future customers. As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, potential tariffs on imported products, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases.

Should these economic conditions and issues continue, we could have difficulty completing the operational activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations.

Failure to attract and retain an appropriately qualified workforce could affect our operations.

We require skilled labor to perform specialized utility functions. Turnover of key employees without appropriate replacements may lead to operating challenges and increased costs. Some of the challenges include lack of resources, loss of knowledge, and time required for replacement employees to develop necessary skills. Wage inflation nationally and increased competitive labor markets may make it difficult to attract employees. Failure to identify qualified replacement employees could result in decreased productivity and increased safety costs. If we are unable to attract and retain an appropriately qualified workforce, our operations could be negatively affected. We are also subject to multiple collective bargaining agreements. Future negotiation of these collective bargaining agreements could lead to work stoppages or other disruptions to our operations, which could adversely affect our financial condition and results of operations.

Liquidity and Financial Risks

We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers. Additionally, insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which we may be subject, including liability and losses associated with wildfires, natural gas and storage field explosions, cyber-security breaches, environmental hazards and natural disasters.

Our plans for future expansion through the acquisition of assets, capital improvements to existing assets, generation investments, and transmission grid expansion involve substantial risks.

Our business strategy includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The completion of generation and natural gas investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to permitting, financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.

Acquisitions include a number of risks, including but not limited to, regulatory approval, regulatory conditions, additional costs, the assumption of material liabilities, the diversion of our attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, and securing adequate capital to support the transaction. The regulatory process in which rates are determined may not result in rates that produce full recovery of our investments, or a reasonable rate of return. Uncertainties also exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to successfully integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

Access to capital markets is critical to our operations and our capital structure. Increasing interest rates could have a material negative impact on our financial condition.

We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, U.S. and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms. We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time-to-time. For example, we have $105 million of secured long-term debt and $150 million of short-term borrowings maturing in 2026. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

We are subject to financial risks associated with the transition to a lower carbon economy.

The risks related to our transition to a lower-carbon economy, creates financial risk. Transition risks represent those risks related to the social and economic changes needed to shift toward a lower carbon future. These risks are often interconnected, representing policy and regulatory changes, technology and market risks, and risks to our reputation and financial performance.

Potential regulation associated with climate change legislation could pose financial risks to us. Although the U.S. is no longer a party to the United Nations' "Paris Agreement" on climate change, other potential legislation and regulation discussed above, could result in enforceable GHG emission reduction requirements that could lead to increased compliance costs for us.

As we expand our energy generation asset mix, the ability to integrate renewable technologies into our operations and maintain reliability and affordability is a risk. The intermittency of renewables remains a critical challenge particularly as cost- efficient energy storage is still in development. Other technology risks include the need for significant upfront financial investments, lengthy development timelines, and the uncertainty of integration and scalability across our entire service territory.

There are also increasing risks for energy companies from shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change who may elect in the future to shift some or all of their investments into entities that emit lower levels of GHG emissions or into non-energy related sectors. Institutional investors and lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable investing and lending practices and some of them may elect not to provide funding for fossil fuel energy companies. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

We may be subject to financial risks from private party litigation relating to GHG emissions. Defense costs associated with such litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. We continue to maintain our investment grade credit ratings. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms and would increase our borrowing costs. Higher interest rates on borrowings with variable interest rates could also have an adverse effect on our results of operations.

Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to make up the difference.

As part of a stipulation in 2002 with the MPSC and other parties, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH through June 2029. This obligation is reflected in the electric QF liability, which reflects the unrecoverable costs associated with these specific QF contracts per the stipulation. The annual minimum energy requirement is achievable under normal operations of these facilities, including normal periods of planned and forced outages. However, to the extent the supplied power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to purchase the difference from other sources. The anticipated source for any shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted rates. To the extent the cost of replacement power is higher than contracted rates, our results of operations, cash flows and financial position could be adversely affected.

Changes in tax law may significantly impact our business.

We are subject to taxation by the various taxing authorities at the federal, state and local levels where we operate. Similar to the Tax Cuts and Jobs Act, sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate will affect our utility customers and the time period over which that change will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates and therefore may impact our results of operations, cash flows and financial position.

We are subject to counterparty credit risk.

We enter into transactions to buy and sell power, natural gas, and transmission service. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. Certain of these contracts may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in our credit ratings may lead to additional collateral posting requirements.

We are a participant in the energy markets, including the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation. The EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the EIM and any such credit losses could be socialized to all EIM participants, including us. A significant failure of a participant in the EIM to make payments when due on its obligations could have a ripple effect on various of our counterparties in the power and gas markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of our counterparties to perform on their obligations.

We also extend credit to our customers in the ordinary course of business in each of our operating segments. Our customers' ability to pay depends on a variety of factors including macroeconomic conditions, local economic conditions, including unemployment rates, and industry conditions in which our commercial and industrial customers operate. Increased customer delinquencies and bad debts could adversely impact our operating results and liquidity.

Poor investment performance of plan assets of our defined benefit pension and postretirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

We have a holding company structure and rely on cash from our subsidiaries to pay dividends.

As a holding company, our primary assets are our investments in our subsidiaries, NW Corp and NWE Public Service. Substantially all operations are conducted by NW Corp (and its subsidiaries) and NWE Public Service. We depend on earnings, cash flows and dividends from our subsidiaries to pay dividends on our common stock. Regulatory, contractual and legal limitations, as well as subsidiary capital requirements, affect the ability of a subsidiary to pay dividends up to the parent entity and thereby could restrict or influence our ability or decision to pay dividends on our common stock, which could adversely affect our stock price.

Risks Related to the Merger

Because the exchange ratio is fixed and because the market prices of NorthWestern Common Stock and Black Hills Common Stock will fluctuate, NorthWestern shareholders cannot be certain of the market value of the Merger consideration they will receive in the Merger or the difference between the market value of the Merger consideration they will receive in the Merger and the market value of NorthWestern Common Stock immediately prior to the Merger.

The exchange ratio in the Merger is fixed and will not be adjusted in the event of any change in the stock prices of NorthWestern or Black Hills prior to the Merger. There may be a significant amount of time between the dates when the shareholders of NorthWestern or Black Hills vote on the Merger Agreement at the special meeting of each company and the date when the Merger is completed. The absolute and relative prices of shares of NorthWestern Common Stock and Black Hills Common Stock may vary significantly between the date the Merger Agreement, the date hereof, the date of the meetings and the date of the completion of the Merger. These variations may be caused by, among other things, changes in the businesses, operations, results or prospects of NorthWestern or Black Hills, market expectations of the likelihood that the Merger will be completed and the timing of completion, the prospects of post-merger operations, general market and economic conditions and other factors. In addition, it is impossible to predict accurately the market price of the Black Hills Common Stock to be received by NorthWestern shareholders after the completion of the Merger. Accordingly, the prices of NorthWestern Common Stock and Black Hills Common Stock on the date hereof and on the date of the meetings may not be indicative of their prices immediately prior to completion of the Merger and the price of the combined company common stock after the Merger is completed.

The ability of NorthWestern and Black Hills to complete the Merger is subject to various closing conditions, including the receipt of approval of NorthWestern and Black Hills stockholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect NorthWestern or Black Hills or cause the Merger to be abandoned. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of NorthWestern common stock or other securities and the future business and financial results of NorthWestern.

To complete the Merger, NorthWestern and Black Hills stockholders must vote to approve a number of proposals related to the Merger and the Merger Agreement. Further, the Merger is subject to the satisfaction or waiver of certain closing conditions, including, (1) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (the HSR Act), and approval from the FERC and certain state regulatory commissions, in each case on such terms and conditions that would not result in a material adverse effect on the combined company; (2) the absence of any court order or regulatory injunction prohibiting completion of the Merger; (3) the authorization for listing of shares of Black Hills Common Stock to be issued in connection with the Merger on the New York Stock Exchange (NYSE) or other mutually-agreed stock exchange; (4) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (5) compliance by each party in all material respects with its covenants under the Merger Agreement; (6) the absence of a material adverse effect on each party; and (7) receipt by each party of an opinion relating to the anticipated tax-free treatment of the Merger. If the foregoing conditions are not satisfied or waived, one or both of NorthWestern or Black Hills would not be required to complete the Merger.

NorthWestern and Black Hills have not yet obtained stockholder approval or all of the regulatory consents and approvals required to complete the Merger. Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger. NorthWestern and Black Hills will be unable to complete the Merger until the waiting period under the HSR Act has expired or been terminated and the required governmental approvals have been received. Regulatory authorities may impose certain requirements or obligations as conditions for their approval. The Merger Agreement may require NorthWestern and/or Black Hills to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither NorthWestern nor Black Hills will be obligated to complete the Merger.

There can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge. Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed. NorthWestern or Black Hills may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

The special meetings at which the NorthWestern stockholders and the Black Hills stockholders will vote on the transactions contemplated by the Merger Agreement may take place before all regulatory approvals have been obtained and, in cases where they have not been obtained, before the terms of any conditions to obtain such regulatory approvals that may be imposed are known. As a result, if stockholder approval of the transactions contemplated by the Merger Agreement is obtained at such meetings, NorthWestern may make decisions after the meetings to waive a condition or approve certain actions required to obtain the necessary approvals without seeking further stockholder approval. Such actions could have an adverse effect on the combined company.

If NorthWestern and Black Hills are unable to complete the Merger, or there is a significant delay in completing the Merger, NorthWestern would be subject to a number of risks, including the following:

• NorthWestern would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies and future cost savings;
• the attention of management of NorthWestern may have been diverted to the Merger rather than to its own operations and the pursuit of other opportunities that could have been beneficial to NorthWestern;
• the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with the combined company;
• NorthWestern will have been subject to certain restrictions on the conduct of its business, which may prevent NorthWestern from making certain acquisitions or dispositions or pursuing certain business opportunities while the Merger is pending;
• the trading price of NorthWestern Common Stock or other securities may decline to the extent that the current market prices reflect a market assumption that the Merger will be completed; and
• the parties may be liable for damages to one another, or have to pay a termination fee, under the Merger Agreement.

NorthWestern can provide no assurance that the various closing conditions will be satisfied and that the required governmental approvals and other approvals will be obtained, or that any required conditions will not materially adversely affect the combined company following the Merger. In addition, NorthWestern can provide no assurance that these conditions will not result in the abandonment or delay of the Merger. The occurrence of any of these events individually or in combination could have a material adverse effect on NorthWestern's results of operations and the trading price of NorthWestern's Common Stock or other securities.

The Merger Agreement contains provisions that limit NorthWestern's ability to pursue alternatives to the Merger, could discourage a potential acquirer of NorthWestern from making a favorable alternative transaction proposal and, in certain circumstances, could require NorthWestern to pay a termination fee to Black Hills.

Under the Merger Agreement, NorthWestern and Black Hills have agreed, subject to certain exceptions with respect to unsolicited proposals, not to directly or indirectly solicit competing acquisition proposals or to enter into discussions concerning, or provide confidential information in connection with, any unsolicited alternative acquisition proposals. Additionally, the NorthWestern board of directors and the Black Hills board of directors are each required to recommend the approval of the applicable transaction-related proposals to its respective stockholders, subject to certain exceptions. Prior to the approval of the transaction-related proposals by their respective stockholders, the NorthWestern board of directors or the Black Hills board of directors may change its recommendation in response to an unsolicited proposal for an alternative transaction, if such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that the proposal constitutes or would reasonably be expected to lead to a “Superior Black Hills Proposal” or “Superior NorthWestern Proposal”, as applicable (as such terms are defined in the Merger Agreement), and that failure to take such action would be inconsistent with their fiduciary duties under applicable law to the applicable company and its stockholders under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. Prior to the approval of the transaction-related proposals by their respective stockholders, the NorthWestern board of directors and the Black Hills board of directors may also change its recommendation upon the occurrence of a “Black Hills Intervening Event” or “NorthWestern Intervening Event”, as applicable (as such terms are defined in the Merger Agreement), and such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that failing to change its recommendation would be inconsistent with its fiduciary duties under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. The Merger Agreement is subject to a “force-the-vote” provision, which means neither NorthWestern nor Black Hills would have an independent right to terminate the Merger Agreement to accept a superior proposal. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of NorthWestern from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher market value than the market value proposed to be received or realized in the Merger, or might result in a potential acquirer proposing to pay a lower price than it would otherwise have proposed to pay. As a result of these restrictions, NorthWestern may not be able to enter into an agreement with respect to a more favorable alternative transaction, or may be able to do so only by incurring potentially significant liability to Black Hills.

The Merger Agreement contains certain customary termination rights for each of NorthWestern and Black Hills; provided, that, either party would be required to pay to the other a termination fee equal to $100 million upon termination of the Merger Agreement in certain circumstances involving (i) a change in recommendation by such party’s board of directors (including, in certain circumstances, the failure of such party to publicly reaffirm its recommendation upon request) or (ii) a party entering into a definitive agreement in respect of a competing transaction within twelve months of termination of the Merger Agreement in certain circumstances involving a potential competing acquisition proposal.

NorthWestern is subject to risk of the Merger having adverse impact on its credit rating while the Merger is pending.

NorthWestern cannot be assured that its credit ratings will not be lowered as a result of the Merger or for any other reason, including the failure to consummate the Merger. Any reduction in NorthWestern's credit ratings, or the criteria used by rating agencies to determine such ratings, could adversely affect its ability to complete the Merger, its access to capital, its cost of capital and its other operating costs, and its ability to refinance or repay NorthWestern's existing debt and complete new financings, which could have a material adverse effect on NorthWestern's business, financial condition, results of operations or the trading price of its common stock or other securities.

The market prices of NorthWestern Common Stock and other securities may be subject to fluctuation while the Merger is pending.

The market price of NorthWestern Common Stock and other securities may fluctuate significantly while the Merger is pending, and any adverse developments related to the Merger or otherwise could result in holders of NorthWestern Common Stock or other securities losing some or all of the value of their investment. In addition, if the stock market experiences significant price and volume fluctuations, such fluctuations could be exacerbated by the pendency of the Merger, which could adversely affect the market for, or liquidity of, NorthWestern Common Stock or other securities, regardless of NorthWestern's actual operating performance.

Because the Merger Agreement contemplates that Black Hills will issue shares of Black Hills Common Stock to NorthWestern’s stockholders based upon a fixed exchange ratio (subject to certain adjustments for reclassifications, stock splits, and stock dividends), developments with respect to Black Hills and its shares of common stock may affect NorthWestern Common Stock irrespective of their relevance to standalone NorthWestern and even though NorthWestern may have no control over, or knowledge of, such developments. As a result, the market price of NorthWestern Common Stock during the pendency of the Merger may not accurately reflect the value of NorthWestern absent the Merger.

NorthWestern is subject to contractual restrictions in the Merger Agreement that may hinder its operations while the Merger is pending. The corollary restrictions applicable to Black Hills may not prevent Black Hills from taking actions that are adverse to NorthWestern or its stockholders.

The Merger Agreement includes certain customary restrictions with respect to the operation of NorthWestern's and Black Hills' respective businesses between the date of the Merger Agreement and the consummation of the Merger. These restrictions may prevent NorthWestern from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the Merger or termination of the Merger Agreement.

Despite these mutual restrictions, NorthWestern and Black Hills will continue to operate their businesses independently of one another during the pendency of the Merger. The restrictions in the Merger Agreement, which are subject to numerous exceptions, may not be adequate to prevent Black Hills from taking actions that are adverse to NorthWestern or its stockholders.

NorthWestern will incur significant transaction and other costs in connection with the Merger.

NorthWestern has incurred and expects to incur additional significant costs associated with the Merger, including transaction fees and costs of combining the operations of the two companies. Additional unanticipated costs also may be incurred in the integration of the businesses of NorthWestern and Black Hills. Any net benefit from any anticipated elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not be achieved in the near term or at all. Transaction costs could have a material adverse impact on the results of operations of NorthWestern, and the failure to achieve the anticipated benefits and efficiencies from the Merger, or the incurrence of additional expenses, could have a material adverse impact on the results of operations of the combined company and its ability to pay dividends after closing. In turn, the current or future market value of NorthWestern Common Stock or other securities could be adversely impacted.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees of NorthWestern and Black Hills, which could adversely affect the future business and operations of the combined company following the Merger.

Each of NorthWestern and Black Hills depends on the experience and industry knowledge of its officers and other key employees to execute its business plans. The success of the combined company after the Merger will depend in part on its ability to retain key management personnel and other key employees. Current and prospective employees of NorthWestern and Black Hills may experience uncertainty about their roles within the combined company following the Merger or other concerns regarding the timing and completion of the Merger or the operations of the combined company following the Merger, any of which may have an adverse effect on the ability of NorthWestern and Black Hills to retain or attract key management and other key personnel. If NorthWestern or Black Hills is unable to retain personnel, including NorthWestern’s or Black Hills’ key management, who are critical to the future operations of the companies, NorthWestern and Black Hills could face disruptions in their operations, loss of existing customers, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs. In addition, the loss of key NorthWestern and Black Hills personnel could diminish the anticipated benefits of the Merger. No assurance can be given that the combined company, following the Merger, will be able to retain or attract key management personnel and other key employees of NorthWestern and Black Hills to the same extent that NorthWestern and Black Hills have previously been able to retain or attract their own employees.

The business relationships of NorthWestern and Black Hills may be subject to disruption due to uncertainty associated with the Merger, which could have a material effect on the business, financial condition, cash flows and results of operations of NorthWestern or Black Hills pending the combined company and following the Merger.

Parties with which NorthWestern or Black Hills do business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with NorthWestern or Black Hills following the Merger. NorthWestern’s and Black Hills’ business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties with whom they do business may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than NorthWestern or Black Hills following the Merger. These disruptions could have a material and adverse effect on the business, financial condition, cash flows and results of operations, of NorthWestern or Black Hills, regardless of whether the Merger is completed, as well as a material and adverse effect on the combined company’s ability to realize the expected cost savings and other benefits of the Merger. The risk, and adverse effects, of any disruption could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement.

The Merger may not be accretive to NorthWestern's or Black Hills' earnings and may cause dilution to the combined company's earnings per share, which may negatively affect the current or future market price of NorthWestern Common Stock or other securities.

Expectations that the Merger will be accretive to earnings per share are based on preliminary estimates any of which may prove to be incorrect or may change materially. NorthWestern and Black Hills may encounter additional transaction and integration-related costs other than those they currently anticipate, may fail to realize all of the benefits anticipated in the Merger or may be subject to other factors that affect preliminary estimates or the ability of either company to realize operational efficiencies. Any of these factors could cause a decrease in NorthWestern's and Black Hills' earnings per share, or negatively affect the current or future market price of NorthWestern Common Stock or other securities.

If the Merger does not qualify as a “reorganization” within the meaning of Section 368(a) of the Code, certain NorthWestern stockholders may be required to pay substantial U.S. federal, state and/or local income taxes.

The Merger is intended to qualify as a “reorganization” within the meaning of Section 368(a) of the Code, and it is a condition to each party’s obligation to complete the Merger that it receive an opinion from counsel, dated as of the closing date of the Merger, to the effect that, on the basis of facts, representations and assumptions set forth or referred to in such opinion, the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Code. However, the foregoing opinions of counsel will each be based on, among other things, the law in effect as of the date of the opinions, certain representations made by NorthWestern and Black Hills and certain assumptions, all of which must be consistent with the state of facts existing at the time of the Merger. If there is a change in law after the date of the opinions, or if any of these representations and assumptions are, or become, inaccurate or incomplete, an opinion may be invalid, and the conclusions reached therein could be jeopardized. In addition, no ruling has been or will be sought from the U.S. Internal Revenue Service

(IRS) as to the U.S. federal income tax consequences of the Merger and the other transactions contemplated by the Merger Agreement. There can be no assurance that the IRS will not assert, or that a court will not sustain, a position contrary to the conclusion set forth in any such opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Code.

If the Merger does not qualify as a “reorganization” within the meaning of Section 368(a) of the Code, each NorthWestern stockholder will recognize gain or loss, for U.S. federal—and applicable state and local—income tax purposes equal to the value of the Black Hills stock received in the Merger (plus any cash received in respect of fractional shares) minus the stockholder’s adjusted tax basis in the stockholder’s NorthWestern stock. Depending on the amount of gain, if any, that is recognized, a NorthWestern stockholder that is subject to U.S. federal, state, or local income taxes may incur a significant income tax liability.

NorthWestern and/or Black Hills may be subject to litigation challenging the Merger while it is pending, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.

Lawsuits in connection with the Merger while it is pending may be filed against NorthWestern, Black Hills, any parties to the Merger Agreement and/or their respective directors and officers, which could prevent or delay the consummation of the Merger and/or result in additional costs to us. The ultimate resolution of any such lawsuit cannot be predicted with certainty, and an adverse ruling in any such lawsuit may cause the Merger to be delayed or not to be completed and/or result in additional costs to NorthWestern and Black Hills, which could cause NorthWestern and Black Hills not to realize some or all of the anticipated benefits of the Merger. The defense or settlement of any lawsuit that remains unresolved at the time the Merger is consummated may adversely affect the combined company’s business, financial condition, results of operations and cash flows. NorthWestern cannot currently predict the outcome of or reasonably estimate the possible loss or range of loss from any such lawsuit.

Risks Relating to the Combined Company Following Completion of the Merger

Failure to successfully combine the businesses of NorthWestern and Black Hills in the expected time frame or at all may adversely affect the future results of the combined company, and, consequently, the value of the Black Hills common stock to be received by the NorthWestern shareholders in the Merger.

The success of the Merger will depend, in part, on the ability of the combined company to realize in a timely fashion the anticipated benefits and efficiencies from combining the businesses of NorthWestern and Black Hills. The process of integration may reveal that benefits and efficiencies are less than anticipated and may result in additional expenses, all of which could reduce the anticipated benefits of the Merger.

Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including:

• whether United States federal and state public utility, antitrust and other regulatory authorities whose approval is required to complete the Merger impose conditions on the Merger, which may have an adverse effect on the combined company, including its ability to achieve the anticipated benefits of the Merger;
• the ability of the two companies to combine certain of their operations or take advantage of expected growth opportunities;
• general market and economic conditions;
• general competitive factors in the marketplace; and
• higher than expected costs required to achieve the anticipated benefits of the Merger.

Failure to achieve the anticipated benefits and efficiencies from the Merger, or the occurrence of additional expenses, could have a material adverse impact on the results of operations of the combined company and its ability to pay dividends after closing. In turn, the market value of the combined company’s common stock could be adversely impacted.

NorthWestern stockholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over management.

It is currently anticipated that NorthWestern stockholders and Black Hills stockholders will hold approximately 44 percent and 56 percent, respectively, of the combined company’s common stock then-issued and outstanding after the completion of the Merger. Consequently, NorthWestern stockholders, as a group, will have reduced ownership and voting power in the combined company compared to their current ownership and voting power in NorthWestern. As a result of the reduced ownership percentages, current NorthWestern stockholders will have less influence on the management and policies of the combined company than they had with NorthWestern. Further, provisions of the Merger Agreement will result in individuals designated by Black Hills, and not previously subject to a vote of NorthWestern stockholders, holding six out of eleven positions on the combined company board of directors and there will be changes to the management of the combined company.

The market price of the combined company's Common Stock after the completion of the Merger may be affected by factors different from those that historically have affected or currently affect NorthWestern Common Stock.

Upon completion of the Merger, NorthWestern stockholders who receive Merger consideration will become holders of Black Hills Common Stock, which will trade on the NYSE or other mutually-agreeable exchange under a new name and ticker to be announced. NorthWestern's business differs from that of Black Hills and certain adjustments may be made to the combined company as a result of the Merger. The financial position of the combined company after completion of the Merger may differ from NorthWestern's financial position before the completion of the Merger, and the results of operations and/or cash flows of the combined company after the completion of the Merger may be affected by factors different from those currently affecting the financial position or results of operations and/or cash flows of NorthWestern and Black Hills, respectively. Accordingly, the market price of the combined company's common stock after the completion of the Merger may be affected by factors different from those currently affecting the market prices of NorthWestern Common Stock and Black Hills Common Stock, respectively, in the absence of the Merger. In addition, general fluctuations in stock markets could adversely affect the market for, or liquidity of, the combined company's common stock, regardless of the combined company’s actual operating performance.

The failure to integrate the businesses and operations of NorthWestern and Black Hills successfully in the expected time frame may adversely affect the combined company's future results.

NorthWestern and Black Hills have operated and, until the completion of the Merger, will continue to operate independently. Following the completion of the Merger, their respective businesses may not be integrated successfully. It is possible that the integration process could result in the loss of key NorthWestern employees or key Black Hills employees; the loss of customers, service providers, vendors or other business counterparties, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the Merger; or higher-than-expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. Specifically, the following challenges, among others, must be addressed in integrating the operations of NorthWestern and Black Hills in order to realize the anticipated benefits of the Merger:

• combining the companies’ operations and corporate functions and the resulting difficulties associated with managing a larger, more complex, diversified business;
• combining the businesses of NorthWestern and Black Hills in a manner that permits the combined company to achieve the cost savings and operating synergies anticipated to result from the Merger;
• avoiding delays in connection with the completion of the Merger or the integration process;
• integrating personnel from the two companies and minimizing the loss of key employees;
• identifying and eliminating redundant functions and assets;
• harmonizing the companies’ operating practices, employee development and compensation programs, internal controls and other policies, procedures and processes;
• maintaining existing agreements with customers, service providers, vendors and other business counterparties and avoiding delays in entering into new agreements with prospective customers, service providers, vendors and other business counterparties;
• addressing possible differences in business backgrounds, corporate cultures and management philosophies;
• consolidating the companies’ operating, administrative and information technology infrastructure and financial systems; and
• establishing the combined company’s headquarters in Rapid City, South Dakota.

In addition, at times the attention of certain members of either company’s or both companies’ management and resources may be focused on completion of the Merger and the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may be beneficial, which may disrupt each company’s ongoing operations and the operations of the combined company. Furthermore, following the Merger, the board of directors and executive leadership of the combined company will consist of former directors from each of NorthWestern and Black Hills and former executive officers from each of NorthWestern and Black Hills, respectively. Combining the boards of directors and management teams of each company into a single board and a single management team could require the reconciliation of differing priorities and philosophies.

Each of NorthWestern and Black Hills may have liabilities that are not known to the other party.

Each of NorthWestern and Black Hills may have liabilities that the other party failed, or was unable, to discover in the course of performing its respective due diligence investigations. NorthWestern and Black Hills may learn additional information about the other party that materially adversely affects it, such as unknown or contingent liabilities and liabilities related to compliance with applicable laws. As a result of these factors, the combined company may incur additional costs and expenses and may be forced to later write-down or write-off assets, restructure operations or incur impairment or other charges that could result in the combined company reporting losses. Even if NorthWestern's and Black Hills' respective due diligence has identified certain risks, unexpected risks may arise and previously known risks may materialize in a manner not consistent with its expectations. If any of these risks materialize, this could adversely affect the combined company’s financial condition and results of operations and could contribute to negative market perceptions about, or price movements of, the combined company’s common stock following the Merger.

Each of NorthWestern and Black Hills and their respective subsidiaries has substantial amounts of indebtedness. Consequently, the combined company will have substantial indebtedness following the Merger. As a result, the rating of the combined company’s indebtedness could be downgraded, and it may be difficult for the combined company to pay or refinance its debts or take other actions, and the combined company may need to divert its cash flow from operations to debt service payments.

The combined company’s debt service obligations with respect to this indebtedness could have an adverse impact on its earnings and cash flows for as long as the indebtedness is outstanding.

The combined company’s indebtedness could also have important consequences to holders of the common stock of the combined company. For example, it could:

• make it more difficult for the combined company to pay or refinance its debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause the combined company to not have sufficient cash flows from operations to make its scheduled debt payments;
• require a substantial portion of the combined company’s cash flows from operations to be used for debt service payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes;
• result in a downgrade in the rating of the combined company’s indebtedness, which could limit its ability to borrow additional funds or increase the interest rates applicable to its indebtedness;
• increase the risk of default on debt obligations of the combined company;
• limit the flexibility of the combined company in planning for or reacting to changes in its business and the industry in which it operates;
• increase the exposure of the combined company to a rise in interest rates, which would generate greater interest expense or the costs of obtaining applicable interest rate fluctuation hedges; or
• require that additional or more stringent terms, conditions or covenants be placed on the combined company.

There can be no assurance that the combined company will be able to repay or refinance such borrowings and obligations.

In addition, the Merger will result in NorthWestern becoming a wholly owned subsidiary of Black Hills. The combined company may decide to incur additional indebtedness at subsidiaries of Black Hills, which could have an effect on outstanding securities, including because such subsidiary indebtedness is “structurally senior” to the indebtedness of its parent company with respect to the assets of such subsidiary.

The combined company may fail to realize all of the anticipated benefits of the Merger.

The success of the Merger will depend, in part, on the combined company’s ability to realize the anticipated benefits and cost savings from combining Black Hills’ and NorthWestern’s businesses and operational synergies. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that are not foreseen, in which case, among other things, the Merger may not be accretive to free cash flow and may not generate significant discretionary cash flow to return to shareholders via share buybacks or other means. Some of the assumptions that NorthWestern and Black Hills have made, such as the achievement of the anticipated benefits related to the geographic, commodity and asset diversification and the expected size, scale, inventory and financial strength of the combined company, may not be realized. The integration process may, for each of NorthWestern and Black Hills, result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. In addition, there could be potential unknown liabilities and unforeseen expenses associated with the Merger that could adversely impact the combined company.

The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.

Following the Merger, the size, geographic footprint and complexity of the combined company will increase significantly compared to the business of each of NorthWestern and Black Hills. The combined company’s future success will depend, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and geographies and associated increased costs and complexity. The combined company may also face increased scrutiny from, and/or additional regulatory requirements of, governmental authorities as a result of the significant increase in the size, geographic footprint and complexity of its business. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings or other benefits currently anticipated from the Merger.

There is no guarantee that the combined company will declare and pay dividends following the Merger.

Although each of NorthWestern and Black Hills has returned capital to its respective stockholders in the past, including through cash dividends on their respective shares of common stock, the board of directors of the combined company may determine not to declare dividends or use other means to return capital to its stockholders in the future or may reduce the amount, proportion or rate of capital returned to its stockholders through dividends or other means in the future. Decisions on whether, when, by what means and in what amounts to return capital to its stockholders will remain in the discretion of the board of directors of the combined company (as reconstituted following the Merger). Any dividend payment or share repurchase amounts will be determined by the board of directors of the combined company from time to time, and it is possible that the board of directors of the combined company may increase or decrease the amount of dividends paid or shares repurchased in the future, or determine not to declare dividends and/or repurchase shares in the future, at any time and for any reason. We expect that any such decisions will depend on the combined company’s financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that the board of directors of the combined company deems relevant, including, but not limited to:

• whether the combined company has enough discretionary cash flow to return capital to its stockholders due to its cash requirements, capital spending plans, cash flows or financial position;
• the combined company’s desire to maintain or improve the credit ratings on its debt; and
• applicable restrictions under South Dakota law. Stockholders should be aware that they have no contractual or other legal right to dividends that have not been declared.

The combined company is expected to record a significant amount of goodwill as a result of the Merger, and such goodwill could become impaired in the future.

Accounting standards in the United States require that one party to the Merger be identified as the acquirer. In accordance with these standards, the Merger will be accounted for as an acquisition of NorthWestern’s Common Stock by Black Hills and will follow the acquisition method of accounting for business combinations. NorthWestern's assets and liabilities will be consolidated with those of Black Hills on the combined company’s financial statements. The excess of the consideration transferred over the fair values of NorthWestern’s assets and liabilities will be recorded as goodwill.

The combined company will be required to assess goodwill for impairment at least annually. To the extent goodwill becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on the combined company's future operating results and statements of financial position which may, in turn, have a material adverse effect on the trading price or liquidity of the combined company's securities.

The combined company's ability to utilize NorthWestern's and/or Black Hills' historic net operating loss carryforwards and certain other tax attributes may be limited.

As of December 31, 2025, NorthWestern had U.S. federal net operating loss carryforwards (NOLs) of approximately $452.2 million, which do not expire. As of December 31, 2025, Black Hills had NOLs of approximately $380.1 million, which also do not expire. However, the NOLs of each of NorthWestern and Black Hills can only be used to offset 80% of U.S. federal taxable income. The combined company's ability to utilize these NOLs and other tax attributes to reduce future taxable income following the closing of the Merger depends on many factors, including its future income, which cannot be assured, and which will be determined after the Merger on a consolidated basis with that of NorthWestern and Black Hills. It is possible that the amount of NOLs and other tax attributes that the combined company is able to utilize in any tax period ending after the closing of the Merger may be less than the amount that NorthWestern and Black Hills together (or either of them separately) would have been able to use had the Merger not taken place.

Additionally, Section 382 of the Code (Section 382) and Section 383 of the Code generally impose an annual limitation on the amount of NOLs and certain other tax attributes that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs with respect to NorthWestern and/or Black Hills, utilization of NorthWestern and/or Black Hills' NOLs would be subject to an annual limitation under Section 382, generally determined by multiplying (1) the fair market value of its stock at the time of the ownership change by (2) the long-term tax-exempt rate published by the IRS for the month in which the ownership change occurs, subject to certain adjustments. Any unused annual limitation may be carried over to later years.

The completion of the Merger may cause NorthWestern and/or Black Hills to undergo an ownership change under Section 382, which would trigger a limitation (calculated as described above) on NorthWestern's ability to utilize its and/or Black Hills' historic NOLs and other tax attributes.

Future sales or issuances of Black Hills Common Stock could have a negative impact on the Black Hills Common Stock price.

Under the terms of the Merger Agreement, NorthWestern stockholders will receive a fixed exchange ratio of 0.98 shares of Black Hills Common Stock for each share of NorthWestern Common Stock they own at the close of the Merger. Based on the 61,422,945 shares of NorthWestern Common Stock outstanding as of January 26, 2026, Northwestern stockholders would receive approximately 60,194,486 shares of Black Hills Common Stock upon the closing of the Merger. The treatment of outstanding equity awards of each of NorthWestern and Black Hills will vary depending on the type of award, its terms and conditions, and determinations made or to be made by each company or its board of directors, but additional shares, or cash in respect of share equivalents, would be issued to settle equity awards, and such shares are not reflected in the share totals included in the preceding sentence. The Black Hills Common Stock that NorthWestern stockholders will receive upon the exchange of NorthWestern Common Stock for the Merger consideration or in settlement of outstanding equity awards generally may be sold immediately in the public market. It is possible that some former NorthWestern stockholders may seek to sell some or all of the shares of Black Hills Common Stock they receive as Merger consideration, and the Merger Agreement contains no restriction on the ability of former NorthWestern stockholders to sell such shares of Black Hills Common Stock following completion of the Merger. Other Black Hills stockholders may also seek to sell shares of Black Hills Common Stock held by them following completion of the Merger. These sales or other dispositions of a significant number of shares of Black Hills Common Stock (or the perception that such sales or other dispositions may occur), coupled with the increase in the outstanding number of shares of Black Hills Common Stock as a result of the Merger (as well as any increase resulting from future issuances of Black Hills Common Stock), may affect the market for Black Hills Common Stock in an adverse manner and may cause the price of Black Hills Common Stock to fall.

Future disclosures relating to the Merger may not align with investor expectations.

In connection with the Merger, Black Hills filed a registration statement on Form S-4, including a prospectus and joint proxy statement for the NorthWestern stockholders' meeting and the Black Hills stockholders' meeting. Information contained in such registration statement and other future disclosures relating to the Merger, which include (among other things) detailed background about the process leading the Merger, prospective financial information reviewed by the NorthWestern and Black Hills board of directors in connection with the Merger, and updated historical financial information of NorthWestern and Black Hills and pro forma financial information of the combined company, may not align with investor expectations. Such disclosures, the anticipation of such disclosures, or reactions to such disclosures could have an adverse effect on the business of NorthWestern and trading price or liquidity of NorthWestern Common Stock or other securities. Persons making investment decisions about NorthWestern securities prior to such disclosures will be required to do so without the benefit of such information and with the risk that such information may not align with their expectations or that it may have an unexpected impact on NorthWestern or the trading price or liquidity of its securities.

Cybersecurity Risk

As a fully integrated electric and gas utility, we operate and participate in regional markets and are interconnected with other entities. The operation of these systems depends on information technology systems we own and operate as well as third party systems and service providers. Strategic business partners are also leveraged to support our mission. As an operator of critical infrastructure, nefarious actors may find us a valuable target if they wish to disrupt our operations and negatively impact our customers. The systems and partnerships described above are all potential targets for a cyber-incident. Any significant interruption or failure of our information systems due to cyber-attacks or incidents could hinder our ability to fulfill our critical business functions. This could adversely affect our business, our financial condition, operating results or liquidity. Through the year ending on December 31, 2025, there have been no cybersecurity incidents that have had a material impact, or any impact, on our business strategy, operations, or financial condition.

Risk Management and Strategy

We utilize a comprehensive, defense in depth approach to cybersecurity risk, which helps us to continually assess, identify and manage enterprise-wide material cybersecurity risks. Our cybersecurity risk management is integrated into our overall Enterprise Risk Management (ERM) process and is reviewed at least quarterly. Our cybersecurity strategy focuses on maintaining the confidentiality, integrity and availability of data. We leverage frameworks established by the National Institute of Standards and Technology and the Center for Information Security for our information and cybersecurity governance program. We have a comprehensive cybersecurity threat detection and monitoring program for our technology and network infrastructure, which leverages various systems, processes, and operational measures to monitor, detect, and respond to cyber incidents. Our cybersecurity processes, including our threat detection, monitoring, and response protocols are subject to ongoing vulnerability testing, and comparison to industry practices. An Incident Response and Disaster Recovery Plan is maintained and exercised. The plan includes a process to identify, protect, detect, respond to and recover from cybersecurity threats and incidents. Resiliency and recoverability are paramount in the plan. This includes a clearly defined escalation process within the plan to ensure management and the Board of Directors are notified if an incident or series of events warrant escalation.

Our strategy includes employee training and awareness on cybersecurity risks and related best practices, simulated phishing campaigns, required password complexity, the use of multi-factor authentication, information security protocols, modern end point protection against threats, patching strategy, the execution of tabletop exercises on a periodic basis, established policies and protocols for cyber incident response planning and reporting, and ongoing internal cybersecurity testing.

As part of engaging a new third party provider, we assess their security standards, require security terms and conditions and work with risk management to ensure insurance coverage is adequate for the exposure risk. Service providers and vendors must adhere to security requirements such as security incident or data breach notification and response protocols, appropriate data encryption requirements, and data disposal. Our cyber incident monitoring process includes dialog with any third party or business partner potentially impacted by a disclosed incident. In addition, we leverage third party consultants to perform penetration (PEN) studies. These independent third party assessments provide valuable insight to enhance our cybersecurity posture.

Board Governance

Our Board of Directors reviews the cybersecurity program through risk review and cybersecurity reporting on at least a quarterly basis. The Audit Committee oversees our ERM program, including cybersecurity protocols. The Safety, Environmental, Technology and Operations (SETO) Committee provides oversight and review of technology policy and strategy as it relates to cybersecurity issues impacting company operations. Both the Audit Committee and the SETO Committee include Directors with diverse experience in technology, finance, enterprise risk, and security providing effective assessment and oversight of cybersecurity risk. Of note, one member of the Board has bolstered their understanding of technology and security issues by obtaining a certificate in cybersecurity oversight.

Roles and Responsibilities of Management

Our cyber security team, which reports to the Vice President - Technology, has primary responsibility for cybersecurity strategy and assessing cyber risk. The Vice President - Technology is responsible for informing the Chief Executive Officer and other Officers, as necessary, about cybersecurity incidents, covering prevention, detection, mitigation, and remediation efforts as they are detected by the cyber security team. Collectively, our cyber security team holds numerous industry certifications related to cybersecurity and have experience in desktop support, networking, application administration and programming.

Our material properties include electric generating facilities, electric transmission and distribution lines, and natural gas production, transmission and distribution lines, which are described in Item 1 under Electric Operations and Natural Gas Operations. Substantially all of our NW Corp Montana electric and natural gas assets are subject to the lien of NW Corp's Montana First Mortgage Bond indenture. Substantially all of our South Dakota and Nebraska electric and natural gas assets are subject to the lien of NWE Public Service's South Dakota Mortgage Bond indenture.

We discuss details of our legal proceedings in Note 20 - Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information is about costs or potential costs that may be material to our financial results.

The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2025 compared to the year ended December 31, 2024, on both a consolidated basis and on a segment basis. For a discussion of our financial results and cash flows for the year ended December 31, 2024 compared with the year ended December 31, 2023, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024.

This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 22 - Segment and Related Information, to the Consolidated Financial Statements.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.

We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.

OVERVIEW

NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 850,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2025, 2024 and 2023. Following is a discussion of our strategy and significant trends.

On August 18, 2025, we entered into the Merger Agreement with Black Hills and Merger Sub that provides for an all-stock merger of equals between NorthWestern and Black Hills. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern, with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume the new corporate name of Bright Horizon Energy as the resulting parent company of the combined corporate group. The Merger will combine the strengths of both companies, resulting in an organization with greater scale, financial stability, and operational expertise. It is designed to create a stronger, more resilient energy company focused on delivering safe, reliable, and affordable energy solutions to customers. Under the provisions of ASC Topic 805, which requires the identification of an acquirer in a business combination, Black Hills is the accounting acquirer. Pursuant to the Merger Agreement, at the effective time of the Merger, each share of common stock of NorthWestern issued and outstanding as of immediately prior to closing will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of Black Hills Common Stock. See Note 3 - Pending Merger with Black Hills Corporation to the Consolidated Financial Statements included herein for additional information regarding this pending Merger.

We work to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:

• Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
• Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
• Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.

We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.

In 2025, approximately 52 percent of our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 41 percent for the total U.S. electric power industry. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050. Our vision for the future builds on the progress we have made, including our hydroelectric system in Montana, which is 100 percent carbon free and is readily available capacity. For us, wind generation is a close second and continues to grow. While utility-scale solar energy has not been a significant portion of our energy mix to date, we expect solar to further evolve along with advances in energy storage. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system.

HOW WE PERFORMED IN 2025 COMPARED TO OUR 2024 RESULTS

(in millions)

(1) Exclusive of depreciation and depletion shown separately below.

(2) Excluding fuel, purchased supply, and direct transmission expense.

Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024. This decrease was primarily due to higher operating expenses, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review, merger-related costs, and depreciation, interest expense, Montana property tax tracker collections, non-recoverable Montana electric supply costs, and higher income tax expense due to a less favorable uncertain tax position release and a prior year income tax benefit from a gas repairs safe harbor method change. These were partly offset by higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes.

SIGNIFICANT TRENDS AND REGULATION

Montana Rate Review

In July 2024, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates. In December 2025, the MPSC issued a final order approving the natural gas settlement agreement and partial electric settlement agreement. Among other things, the approved partial electric settlement agreement provides for the deferral and annual recovery of incremental operating costs related to wildfire mitigation and insurance expenses through the Wildfire Mitigation Balancing Account.

The details of this final order are set forth below:

Returns, Capital Structure & Revenue Increase Resulting From Final Order ($ in millions)

(1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.

(2) This PCCAM reduction of $94.5 million represents the reduction in revenue at the previously approved 2021 PCCAM base of $208.3 million using the 2023 Montana rate review test period loads.

The final order provides for an update to the PCCAM by adjusting the base costs from $208.3 million to $119.0 million. It also suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. Within this final order, the MPSC disallowed a portion of the capital costs related to the construction of YCGS. As a result, in the fourth quarter of 2025 we recorded a $30.9 million non-cash charge for the regulatory disallowance within Operating and maintenance on the Consolidated Statements of Income and a corresponding reduction to Property, plant, and equipment, net on the Consolidated Balance Sheets. As of December 31, 2025, we have deferred $7.7 million of base rate revenues collected that will be refunded to customers.

In January 2026, we filed a Motion for Reconsideration (Motion) as it relates to this final order. Among other things, our Motion requests that the MPSC reconsider their prudence conclusions regarding the capital costs associated with the construction of YCGS and clarification as to the effective date of the PCCAM sharing mechanism suspension, of which we have requested an effective date of July 1, 2025, to align with the PCCAM tracker year.

Montana Large-Load Tariff

The MPSC requested information on our plan to serve potential large-load customers and related resource adequacy issues. We responded in March 2025, outlining our policy and legal positions, emphasizing the importance of economic development for Montana and our commitment to serving our existing customers. We expect to submit a filing with the MPSC during the first half of 2026 to address data center development discussed below, incorporating rate design that prevents cost shifting of infrastructure upgrades needed to serve large-load customers to other retail customers.

Data Center Development

In July 2025, we entered into a nonbinding letter of intent with Quantica Infrastructure to evaluate the transmission infrastructure and generation resources needed to support their proposed need. We had previously disclosed, in December 2024, two separate nonbinding letters of intent with Sabey Data Centers (Sabey) and Atlas Power Holdings LLC (Atlas) to provide electric supply services for data centers being developed in Montana. The combined energy service requirement associated with these letters of intent is currently expected to be 175 megawatts beginning in late 2027, or earlier, with growth of up to 1,100 megawatts or more by 2030. We have signed development agreements with both Sabey and Atlas and are working with each of these parties to execute electric service agreements.

Resources and regulatory mechanisms to be utilized for serving these requests are pending further evaluation and regulatory considerations.

Colstrip Acquisitions and Requests for Cost Recovery

As previously disclosed, we entered into definitive agreements with Avista and Puget to acquire their respective interests in Colstrip Units 3 and 4 for $0 and completed these acquisitions on January 1, 2026. Accordingly, we are responsible for the associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates until requested in a future Montana rate review. Puget and Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests.

Avista Interests - The 222 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Avista (Avista Interests) on January 1, 2026, was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan. Noting the costs associated with operating this resource are not currently reflected in utility customer rates, in August 2025, we filed a temporary PCCAM tariff waiver request with the MPSC that would provide a near-term cost-recovery mechanism expected to largely offset approximately $18.0 million in annual incremental operating and maintenance costs associated with the Avista Interests. This waiver requested that the MPSC allow us to keep 100 percent of the net revenue associated with certain designated power sales contracts up to the amount of the operating and maintenance expenses we incur associated with our Avista Interests. Furthermore, the waiver request indicated that any net revenues from the designated contracts exceeding the operating and maintenance expenses associated with our Avista Interests would continue to flow back to retail customers. In January 2026, the MPSC approved our PCCAM tariff waiver request on an interim basis with final approval or denial subject to the ongoing PCCAM docket process.

Puget Interests - The 370 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Puget (Puget Interests) on January 1, 2026, increases our ownership share of the facility to 55 percent and provides an increase in voting share in determining strategic direction and investment decisions at the facility. While we expect our future opportunity to serve growing customer demand, including large-load customers, may be supported by this resource, in October 2025, we signed a contract to sell the dispatchable capacity and associated energy from the Puget Interests beginning January 1, 2026, through late 2027. Revenues from this agreement are expected to largely offset the estimated $30.0 million of annual incremental operating and maintenance costs associated with the Puget Interests. In addition, in October 2025, we submitted a request to the FERC for approval of cost-based rates for our subsidiary that will own the Puget Interests. We expect this rate approval to be effective in the first quarter of 2026. If our request for rates effective January 1, 2026 is not approved, we could incur refund liability for contract revenues received during the unauthorized period.

Generation Capacity in South Dakota

The SPP has recently updated its resource accreditation and PRM requirements in response to growing reliability concerns. As a result, SPP is requiring additional accredited capacity by 2030 to meet the updated PRM targets. In October 2025, we submitted a project with the SPP under their Expedited Resource Adequacy Study program for the construction of a 131 MW natural gas generating facility located in Aberdeen, South Dakota, to meet regional capacity needs by 2030. Anticipated costs for this project are approximately $300.0 million.

Regional Transmission Development Activities

In December 2024, we signed a nonbinding memorandum of understanding (MOU) with North Plains Connector LLC, a wholly owned subsidiary of Grid United, to own 10 percent (300 megawatts) of the NPC Consortium project. The project is entering the permitting phase. Currently, construction is planned to commence in 2028, subject to receipt of regulatory approvals, with the project expected to be operational by 2032. Under the terms of the MOU, Grid United will continue to fund the development of the NPC and we will make our investment decision when the regulatory approvals and permits are in place. The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region.

We have also entered into a nonbinding letter of intent with Grid United to continue transmission development to further enhance the grid through the southwest corridor of Montana. Development to expand the southwest corridor of Montana through grid build out would represent a significant step in enhancing connectivity between Montana and the broader Western energy market - bolstering grid reliability, allowing for critical import capability, and enabling customers to access and benefit from emerging energy markets in the West.

Montana Wildfire Risk Mitigation

The Montana Legislature approved House Bill 490 in April 2025. It precludes common law strict liability claims for damages related to wildfire and electric activities or wildfire mitigation activities; establishes a statutory standard of care, supplanting common law causes of action and other theories of recovery; and creates a rebuttable presumption that an electric facilities provider acted reasonably if it substantially followed an approved wildfire mitigation plan. The legislation also defines the availability of damages by allowing noneconomic personal injury damages only when there is bodily injury and punitive damages only when an injured party proves by clear and convincing evidence that an electric facilities provider's actions were grossly negligent or intentional. The MPSC approved our wildfire mitigation plan in November 2025. The wildfire mitigation plan for the Colstrip transmission system was submitted to the MPSC on November 7, 2025, and we anticipate a decision in the first quarter of 2026.

SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES

Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions):

Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments. For additional information related to our electric supply resource plans, see Item 1. Business, where we discuss electric resource planning for our Montana and South Dakota jurisdictions.

Distribution and Transmission Modernization and Maintenance - The primary goals of our infrastructure investments are to reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. We are taking a proactive and pragmatic approach to replacing these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications. Approximately $2.3 billion, or 70 percent, of our capital forecast above is projected to be spent on our distribution and transmission system. In 2025, we completed the installation, which began in 2021, of automated metering infrastructure in Montana.

RESULTS OF OPERATIONS

Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential customers. We measure this effect based on the number of customers, temperature variances, and the amount of electricity or natural gas historically used per degree of temperature. Degree-day, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees, is used to estimate the amount of energy required to maintain comfortable indoor temperature levels based on each day's average temperature. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.

Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.

OVERALL CONSOLIDATED RESULTS

Year Ended December 31, 2025 Compared with Year Ended December 31, 2024

Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024, a decrease of $43.0 million. This decrease was primarily due to higher operating expenses, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review, merger-related costs, and depreciation, interest expense, Montana property tax tracker collections, non-recoverable Montana electric supply costs, and higher income tax expense due to a less favorable uncertain tax position release and a prior year income tax benefit from a gas repairs safe harbor method change. These were partly offset by higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes.

Consolidated gross margin in 2025 was $484.3 million as compared with $460.8 million in 2024, an increase of $23.5 million or 5.1 percent. This increase was primarily due to higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. These were partly offset by higher operating expenses, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review and depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs.

(in millions)

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

(in millions)

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Consolidated utility margin in 2025 was $1,200.8 million as compared with $1,080.1 million in 2024, an increase of $120.7 million, or 11.2 percent.

Primary components of the change in utility margin include the following (in millions):

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in South Dakota, and lower industrial demand. Natural gas retail volumes were driven by the acquisition of Energy West, favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.

Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding QF costs) were allocated 90 percent to Montana customers and 10 percent to shareholders. For the twelve months ended December 31, 2025, we under-collected supply costs of $73.9 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $8.2 million (10 percent of the PCCAM Base cost variance). For the twelve months ended December 31, 2024, we under-collected supply costs of $8.0 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.9 million (10 percent of the PCCAM Base cost variance). As part of the MPSC's final order on our Montana electric rate review they suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC.

(in millions)

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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $874.9 million in 2025, as compared with $756.7 million in 2024. Primary components of the change include the following (in millions):

(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.

Consolidated operating income in 2025 was $325.8 million as compared with $323.3 million in 2024. This increase was primarily due to new rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. These were partly offset by higher operating, administrative, and general costs, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review and merger-related costs, depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs.

Consolidated interest expense in 2025 was $150.4 million, as compared with $131.7 million in 2024. This increase was due to higher borrowings and interest rates, partly offset by lower capitalization of AFUDC.

Consolidated other income in 2025 was $12.1 million, as compared with $23.0 million in 2024. This decrease was primarily due to lower capitalization of AFUDC, a prior year reversal of $2.3 million from a previously disclosed CREP penalty due to a favorable legal ruling, and a $1.3 million expense current year accrual related to an estimated penalty for the CREP informed by a recent MPSC ruling, partly offset by an increase of $2.5 million driven by a prior year non-cash impairment of an alternative energy storage equity investment.

Consolidated income tax expense in 2025 was $6.5 million, as compared to an income tax benefit of $9.4 million in 2024. Our effective tax rate for the twelve months ended December 31, 2025 was 3.5 percent as compared with (4.4)

percent for the same period of 2024. As further discussed in Note 14 - Income Taxes, income tax expense for the twelve months ended December 31, 2025, includes a $10.4 million benefit related to a reduction in our unrecognized tax benefits, inclusive of $3.0 million of previously accrued interest ($7.4 million net of interest). Income tax benefit for the twelve months ended December 31, 2024, includes a $21.0 million benefit related to a reduction in our unrecognized tax benefits, inclusive of $4.1 million of previously accrued interest ($16.9 million net of interest). Additionally, during the twelve months ended December 31, 2024, we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission and distribution property. This resulted in an income tax benefit of $7.0 million during 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years.

We currently estimate our effective tax rate will range between 14.0 percent to 18.0 percent in 2026. Based on the significant NOL income tax position we have, we anticipate paying minimal cash for income taxes into 2029.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

ELECTRIC OPERATIONS

We have various classifications of electric revenues, defined as follows:

• Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
• Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
• Transmission: Reflects transmission revenues regulated by the FERC.
• Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.

Year Ended December 31, 2025 Compared with Year Ended December 31, 2024

(in thousands)

(1) Included within this line is our lighting customer class, which we have historically counted each lighting district as one customer. We have retrospectively modified our customer counts to now reflect each lighting service as a customer as that better aligns with the MWH usage of this customer class.

(2) Exclusive of depreciation and depletion.

(3) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

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(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2025 and 2024 (in millions):

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in South Dakota, and lower industrial demand.

For the twelve months ended December 31, 2025, we under-collected supply costs of $73.9 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $8.2 million (10 percent of the PCCAM Base cost variance). For the twelve months ended December 31, 2024, we under-collected supply costs of $8.0 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.9 million (10 percent of the PCCAM Base cost variance). As part of the MPSC's final order on our Montana electric rate review they suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC.

The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

NATURAL GAS OPERATIONS

We have various classifications of natural gas revenues, defined as follows:

• Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
• Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
• Wholesale: Primarily represents transportation and storage for others.

Year Ended December 31, 2025 Compared with Year Ended December 31, 2024

(in thousands)

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2025 and 2024 (in millions):

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Natural gas retail volumes were driven by the acquisition of Energy West, favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 18 - Common Stock to the Consolidated Financial Statements for more information regarding these dividend restrictions.

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

As of December 31, 2025, our total consolidated net liquidity was approximately $229.8 million, including $8.8 million of cash and $221.0 million of revolving credit facility availability with no letters of credit outstanding.

Cash Flows

The following table summarizes our consolidated cash flows (in millions):

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Operating Activities

As of December 31, 2025, cash, cash equivalents, and restricted cash were $30.7 million as compared with $29.0 million as of December 31, 2024. Cash provided by operating activities totaled $394.5 million for the year ended December 31, 2025 as compared with $406.8 million for the year ended December 31, 2024. The changes in cash flows from operating activities generally follow the results of operations, as discussed above in the consolidated results of operations for the year ended December 31, 2025, and are affected by changes in working capital. The decrease in cash provided by operating activities is primarily due to merger transaction costs, lower collections of accounts receivable balances due to timing of colder weather, and an increase in our net cash outflows for energy supply costs, as shown in the table below, partly offset by the proceeds from production tax credits transferred.

Investing Activities

Cash used in investing activities totaled $570.7 million during the year ended December 31, 2025, as compared with $554.5 million during 2024. Plant additions during 2025 include capital maintenance additions of approximately $372.7 million and capacity related capital expenditures of approximately $151.8 million. Plant additions during 2024 included capital maintenance additions of approximately $324.0 million and capacity related capital expenditures of approximately $225.3 million. During the year ended December 31, 2025, we completed the acquisition of the Energy West Operations for $35.9 million. See Note 4 - Acquisition of Energy West Operations to the Consolidated Financial Statements included herein for additional information regarding this acquisition. As discussed above in the “Significant Infrastructure Investments and Initiatives” section, our capital expenditures are forecasted to be $683.0 million in 2026.

Financing Activities

Cash provided by financing activities totaled $177.9 million during the year ended December 31, 2025 as compared with $151.5 million during the year ended December 31, 2024. During the year ended December 31, 2025, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $602.1 million and short-term borrowings of $50.0 million, partly offset by repayment of $300.0 million of Montana and South Dakota First Mortgage bonds, payment of dividends of $161.4 million, and net repayments under our revolving lines of credit of $9.0 million. During the year ended December 31, 2024, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $215.0 million, short-term borrowings of $100.0 million, and net issuances under our revolving lines of credit of $95.0 million, partly offset by payment of dividends of $158.6 million and repayment of $100.0 million of Montana First Mortgage Bonds.

Cash Requirements and Capital Resources

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.

Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to be $683 million in 2026, $643 million in 2027, and $667 million in 2028. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt issuances and future rate increases. In order to fund South Dakota generation investment equity issuances are expected beginning in 2027. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.

Short-term Borrowings

For further information on our short-term borrowings, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein. NorthWestern Energy Group has $150.0 million of short-term borrowings maturing in 2026, which we intend to refinance.

Credit Facilities

Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.

For further information on our credit facilities, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein.

The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2025 (in millions):

As of February 6, 2026, availability under our revolving credit facilities was approximately $229.0 million, and there were no letters of credit outstanding.

Long-term Debt and Equity

We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $105.0 million of long-term debt maturing in 2026, which we intend to refinance.

For further information on our long-term debt, see Note 13 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein.

We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.

For further information regarding equity, see Note 18 - Common Stock to the Consolidated Financial Statements included herein.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service (Moody's), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of February 6, 2026, our current ratings with these agencies are as follows:

(1) This Fitch Issuer Rating represents the Issuer Default Rating.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2025. See additional discussion in Note 20 - Commitments and Contingencies to the Consolidated Financial Statements.

(in thousands)

(1) Represents cash payments for long-term debt and excludes $12.7 million of debt discounts and debt issuance costs, net.

(2) We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(3) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $124 to $130 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $168.6 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $152.8 million.

(4) We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts (exclusive of the qualifying facilities liability discussed above). These commitments range from one to 24 years.

The majority of our energy supply costs incurred under these contracts are recoverable through rate mechanisms, as further described in Note 6 - Regulatory Assets and Liabilities.

(5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 5.07 percent on the outstanding balance through maturity of the credit facilities.

(6) Represents significant firm purchase commitments for construction of planned capital projects.

(7) The table above excludes potential tax payments related to unrecognized tax benefits as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 20 - Commitments and Contingencies) and AROs (see Note 8 - Asset Retirement Obligations) as the amount and timing of cash payments may be uncertain.

Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $13.5 million and $15.8 million as of December 31, 2025 and 2024, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced.

CRITICAL ACCOUNTING ESTIMATES

Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.

We have identified the policies and related procedures below that contain accounting estimates that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations.

Regulatory Assets and Liabilities

Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets.

While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 6 - Regulatory Assets and Liabilities to the Consolidated Financial Statements for further discussion.

Pension and Postretirement Benefit Plans

We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 16 - Employee Benefit Plans to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

• Discount rates used in determining the future benefit obligations;
• Expected long-term rate of return on plan assets; and
• Mortality assumptions.

We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions.

We set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year projected benefit cash flow from our plans. Based on this analysis as of December 31, 2025, our discount rate for both NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan is 5.20 percent and 5.65 percent, respectively.

In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Our expected long-term rate of return on assets assumptions are 4.96% percent and 6.3% percent on the NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan, respectively, for 2026.

Cost Sensitivity

The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):

Accounting Treatment

We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees.

Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service.

Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates.

The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As of December 31, 2025, we have not recorded any unrecognized tax benefits. The resolution of tax matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows. See Note 14 - Income Taxes to the Consolidated Financial Statements for further discussion.

NEW ACCOUNTING STANDARDS

See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.

Interest Rate Risk

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facilities. Our credit facilities bear interest at rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. As of December 31, 2025, we had $404.0 million in borrowings under our revolving credit facilities. A 1.0 percent increase in interest rates would increase our annual interest expense by approximately $4.0 million.

Commodity Price Risk

We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases and sales, including forward contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is mitigated because these commodity costs are included in our Montana, South Dakota and Nebraska cost tracking mechanisms and are recoverable from customers subject to a regulatory review for prudency.

Counterparty Credit Risk

We are exposed to counterparty credit risk related to the ability of counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. If counterparties seek financial protection under bankruptcy laws, we are exposed to greater financial risks. We are also exposed to counterparty credit risk related to providing transmission service to our customers under our OATT, under gas transportation agreements, and contracts for electricity sales in wholesale energy markets. We have risk management policies in place to limit our transactions to high quality counterparties. We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of December 31, 2025, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Annual Report on Internal Control over Financial Reporting

The management of NorthWestern is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board regarding the preparation and fair presentation of published financial statements.

All internal controls over financial reporting, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention or overriding of controls. Therefore, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Our management, including our chief executive officer and chief financial officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2025. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on our evaluation, management concluded that, as of December 31, 2025, our internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. Their report appears on page F-3.