NWE 10-K & 10-Q changes, risk factors and insider trading
NorthWestern Energy Group, Inc. · Nasdaq · Electric & Other Services Combined · CIK 1993004 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Summary Risk Factors”
New heading “Regulatory, Legislative and Legal Risks”
New heading “Operational Risks”
New heading “Liquidity and Financial Risks”
New heading “Risks Related to the Merger”
New heading “Risks Relating to the Combined Company Following Completion of the Merger”
New heading “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.”
New heading “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.”
New heading “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.”
New heading “NorthWestern is subject to risk of the Merger having adverse impact on its credit rating while the Merger is pending.”
New heading “The market prices of NorthWestern Common Stock and other securities may be subject to fluctuation while the Merger is pending.”
New heading “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.”
New heading “NorthWestern will incur significant transaction and other costs in connection with the Merger.”
New heading “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.”
New heading “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.”
New heading “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.”
New heading “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.”
New heading “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.”
New heading “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.”
New heading “NorthWestern stockholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over management.”
New heading “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.”
New heading “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.”
New heading “Each of NorthWestern and Black Hills may have liabilities that are not known to the other party.”
New heading “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.”
New heading “The combined company may fail to realize all of the anticipated benefits of the Merger.”
New heading “The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.”
New heading “There is no guarantee that the combined company will declare and pay dividends following the Merger.”
New heading “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.”
New heading “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.”
New heading “Future sales or issuances of Black Hills Common Stock could have a negative impact on the Black Hills Common Stock price.”
New heading “Future disclosures relating to the Merger may not align with investor expectations.”
Largest changes
“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.”see in full comparison
“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. …”see in full comparison
“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.”see in full comparison
“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.”see in full comparison
“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.”see in full comparison
“NorthWestern is subject to risk of the Merger having adverse impact on its credit rating while the Merger is pending.”see in full comparison
Full comparison: every changed paragraph (163)
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
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 extensive and changing energy, and environmental laws and regulations, including legislative, judicial, and regulatory responses to climate change,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, climate change, 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. RecentlyIn promulgated2024, federalthe EPA released final rules under the Biden Administrationthat will potentially impose requirements on fossil fuel assets, buthowever, in 2025, the TrumpEPA Administrationissued multiple Notices of Proposed Rulemaking that would remove these additional requirements on fossil fuel assets. There is evaluatingno energy-relatedmandated regulationstimeline impactingfor reliabilityfinal andaction affordability.on Itthese is currently unclear whether the promulgated GHG or MATS Rules will be enforced, revised, or repealed.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.
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.
We are also at risk of unfavorable litigation outcomes related to zoning and environmental permits. See discussion related to YCGS below in “Management’s Discussion and Analysis – Significant Trends and Regulation.” Adverse litigation outcomes could cause us to delay or terminate projects, increase costs and impact our ability to service our customers.
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 and climate-relatedenvironmental-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.
In particular, as described more fully below in Note 18 - Commitments and Contingencies, we are a co-owner of Colstrip Unit 4. The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. On January 16, 2023 we entered into an agreement with Avista Corporation pursuant to which it will transfer to us its 15% project share in Units 3 and 4 on December 31, 2025. On July 30, 2024, we entered into an agreement with Puget Sound Energy pursuant to which it will transfer to us its 25% project share in Units 3 and 4 on December 31, 2025.
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. Worsening conditions as a result of climate change may increase the likelihood and magnitude of damages that may be caused by fires. Residential and commercial development into the wildland-urban interface has also led to an increasing trend in the degree of destruction from wildfires.
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.
Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change,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.
The physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate.
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.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.
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.
Management's Discussion & Analysis (MD&A)
New heading “Montana Rate Review”
New heading “Montana Large-Load Tariff”
New heading “Data Center Development”
New heading “Colstrip Acquisitions and Requests for Cost Recovery”
New heading “Generation Capacity in South Dakota”
New heading “Montana Wildfire Risk Mitigation”
Removed heading “Regulatory Update”
Removed heading “Electric Resource Planning - Montana”
Removed heading “Acquisition of Energy West Montana Assets”
Removed heading “Montana Data Centers”
Largest changes
“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. …”see in full comparison
“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. …”see in full comparison
“Yellowstone County 175 MW plant - Construction of the generation facility was substantially completed and the plant placed in service in October 2024. As of December 31, 2024, we have incurred $305.5 million of generation plant costs and $12.1 million of non-generation plant costs related to YCGS. The lawsuit challenging the YCGS air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and increased costs. …”see in full comparison
Full comparison: every changed paragraph (72)
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, employeesemployees, 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:
In 2024,2025, approximately 5852 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 recently entered into power purchase agreements with two solar projects totaling 160-megawatts that began delivering energy to our Montana customers in 2023. 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.
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.
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:
(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
Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenue, and income tax benefits from a change to the gas repairs safe harbor method and a reduction to our unrecognized tax benefits. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.
Regulatory Update
Rate reviews are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We regularly review the need for electric and natural gas rate relief in each state in which we provide service. Our ongoing rate review activity includes the following:
Montana Rate Review - In July 2024, we filed a Montana electric and natural gas rate review (2023 test year) with the MPSC. The filing requests a base rate annual revenue increase of $156.5 million ($69.4 million net with Property Tax and PCCAM tracker adjustments) for electric and $28.6 million for natural gas. Our request is based on a return on equity of 10.80 percent with a capital structure including 46.81 percent equity, and forecasted 2024 electric and natural gas rate base of $3.45 billion and $731.9 million, respectively. The electric rate base investment includes the 175-megawatt natural gas-fired Yellowstone County Generating Station, which was placed in service in October 2024.
In November 2024, the MPSC partially approved our requested interim rates, which are subject to refund, increasing electric and natural gas base rates by $18.4 million and $17.4 million, respectively, and decreasing our PCCAM base costs by $88.0 million, effective December 1, 2024.
In January 2025, intervenor testimony was filed and we anticipate filing our rebuttal testimony in March 2025. Based on the procedural schedule developed by the MPSC, a hearing on our rate review request is scheduled to commence on April 22, 2025. If a final order is not received by May 23, 2025, which is 270 days from acceptance of our filing, we intend to implement our requested rates as permitted by the MPSC regulations, which will be subject to refund until a final order is received.
South Dakota Natural Gas Rate Review - In June 2024, we filed a natural gas rate review (2023 test year) with the SDPUC for an annual increase to natural gas rates totaling approximately $6.0 million. Our request was based on a rate of return of 7.75 percent and rate base of $95.6 million. In December 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $4.6 million and an authorized rate of return of 6.91 percent. The approved settlement is based on a rate base of $96.2 million. Final rates were effective December 19, 2024.
Nebraska Natural Gas Rate Review - In June 2024, we filed a natural gas rate review (2023 test year) with the NPSC. The filing requests a base rate annual revenue increase of $3.6 million. Our request is based on a return on equity of 10.70 percent, a capital structure including 53.13 percent equity, and rate base of $47.4 million. Interim rates, which increased base natural gas rates $2.3 million, were implemented on October 1, 2024. Interim rates will remain in effect on a refundable basis until the NPSC issues a final order.
Electric Resource Planning - Montana
Yellowstone County 175 MW plant - Construction of the generation facility was substantially completed and the plant placed in service in October 2024. As of December 31, 2024, we have incurred $305.5 million of generation plant costs and $12.1 million of non-generation plant costs related to YCGS. The lawsuit challenging the YCGS air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and increased costs. On January 3, 2025, the Montana Supreme Court ordered that the YCGS air quality permit be reinstated. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.
Acquisition of Colstrip Interests - As previously disclosed, in January 2023 and in July 2024, we entered into definitive agreements, the firstagreements with Avista Corporation (Avista) and the second with Puget Sound Energy (Puget), to acquire their respective interests in Colstrip Units 3 &and 4 for $0. In particular, we agreed to acquire a 15% (222 megawatts) interest from Avista$0 and acompleted 25%these (370 megawatts) interest from Puget. These agreements are substantially similar and are both scheduled to close December 31, 2025, subject to the satisfaction of customary closing conditions and approvals contained within the agreements. Under the terms of the agreements, we will be responsible for operating costs startingacquisitions on January 1, 2026;2026. whileAccordingly, 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 decommissiondecommissioning 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.
Acquisition of Avista and Puget's interests would result in our ownership of 55 percent of the facility with the ability to guide operating and maintenance investments. This would provide capacity to help us meet our obligation to provide reliable and cost effective power to our customers in Montana, while allowing opportunity for us to identify and plan for newer lower or no-carbon technologies in the future.
EPA Rules
In April 2024, the EPA released GHG Rules for existing coal-fired facilities and new coal and natural gas-fired facilities as well as MATS Rules. Compliance with the rules will require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively. However, the Trump Administration is evaluating energy related regulations impacting reliability and affordability. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding these rules.
Acquisition of Energy West Montana Assets
In July 2024, we entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas utility distribution system and operations serving approximately 33,000 customers located near Great Falls, Cut Bank, and West Yellowstone, Montana for approximately $39.0 million, subject to certain working capital and other agreed upon closing adjustments. The transaction is subject to a number of customary closing conditions, including MPSC approval, and we expect the acquisition to be completed in the first half of 2025.
In August 2024, the U.S. Department of Energy awarded a $700.0 million grant through the Grid Resilience and Innovation Partnership (GRIP) program to advance the NPC Consortium project. The 415-mile, high-voltage direct-current transmission line is intended to connect Montana's Colstrip substation, of which we are the operator and a joint owner, to central North Dakota, bridging the eastern and western U.S. energy grids. The NPC Consortium includes potential upgrades to our jointly owned Colstrip Transmission System and $70.0 million of the award is earmarked for the Colstrip Transmission System Upgrade. The NPC project, estimated to be a $3.6 billion investment, aims to enhance grid reliability, support renewable energy integration, and provide additional capacity across multiple states. We collaborated with Grid United, the Montana Department of Commerce, and other regional utilities on the successful GRIP grant application.
In addition to the Colstrip Transmission System Upgrade, 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 phasephase. andCurrently, initiating regulatory filings with approvals targeted in 2026. Constructionconstruction is expectedplanned 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 investmake 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.
President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. This Executive Order has delayed, for up to 90 days, the disbursement of the funds granted by the U.S. Department of Energy for the NPC Consortium project.
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.
Montana Data Centers
In December 2024, we announced two separate nonbinding letters of intent to provide electric supply services for data centers being developed in Montana. The combined energy service requirement is expected to be 75 megawatts beginning in early 2026 with growth of up to 400 megawatts or more by 2030. Our strategic acquisition of additional interest in Colstrip Units 3 & 4 beginning in 2026, the construction of the YCGS, and our balanced energy portfolio have enabled us to serve new large energy supply customers while continuing to provide our current customers with affordable and reliable energy.
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. OverApproximately $2.2$2.3 billionbillion, or 8270 percentpercent, of our capital forecast above is projected to be spent on our distribution and transmission system. BeginningIn 2025, we completed the installation, which began in 2021, we began installingof automated metering infrastructure in Montana. We expect this project to be substantially complete in 2025, with a total cost of approximately $105.0 million, of which approximately $10.0 million remains and is reflected in the five year capital forecast above.
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 usingbased degree-days,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.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.
Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023, an increase of $30.0 million. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenue, and income tax benefits related to the gas repairs safe harbor method and a reduction in our unrecognized tax benefits. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.
Consolidated grossnet marginincome in 20242025 was $460.8$181.1 million as compared with $416.3$224.1 million in 2023,2024, ana increasedecrease of $44.5$43.0 million or 10.7 percent.million. This increasedecrease was primarily due to newhigher baseoperating ratesexpenses, inincluding Montanaa 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 Southdepreciation, Dakota,interest electric transmission revenue, Montana interim rates, subject to refund, andexpense, Montana property tax tracker collections. These were offset in party bycollections, non-recoverable Montana electric supply costs, and higher income tax expense due to a less favorable QFuncertain liabilitytax adjustment,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 andtransmission revenue, natural gas retailtransportation volumes,revenues, and depreciation.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.
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.
Lower electric residential and commercial retail volumes were driven by unfavorable weather in South Dakota impacting residential demand and lower commercial demand in all jurisdictions as compared to the prior year, partly offset by higher industrial demand and customer growth. Lower natural gas retail volumes were driven by unfavorable weather in all jurisdictions partly offset by customer growth.
Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility (QF) costs) arewere 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). ForAs part of the twelveMPSC's monthsfinal endedorder Decemberon 31,our 2023,Montana weelectric overrate collectedreview supplythey costssuspended the 90/10 cost sharing mechanism of $32.9the millionPCCAM resulting inon a reductiontemporary tobasis ourpending underfurther collectionreview of costs, and recorded an increase in pre-tax earnings of $7.0 million, which was inclusive of a $3.2 million increase in pre-tax earnings related toby the retroactive application of higher PCCAM Base rates to July 1, 2022.MPSC.
The less favorable adjustment to our electric QF liability (unrecoverable costs associated with contracts covered by the Public Utility Regulatory Policies Act of 1978 (PURPA) as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, due to a favorable adjustment in the prior year, decreasing the QF liability by $4.2 million, reflecting annual actual contract price escalation for the 2023-2024 contract year, which was less than previously estimated. The 2023-2024 contract year was the last year of the contract that contains variable pricing terms.
Consolidated operating income in 20242025 was $323.3$325.8 million as compared with $300.5$323.3 million in 2023.2024. This increase was primarily due to new base rates in Montana and South Dakota,rates, electric transmission revenue, Montananatural interimgas rates,transportation subject to refund,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.collections, These were offset in part byand non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, depreciation, operating, and administrative and general costs.
Consolidated interest expense in 20242025 was $131.7$150.4 million, as compared with $114.6$131.7 million in 2023.2024. This increase was due to higher borrowings and interest rates, partly offset by higherlower capitalization of AFUDC.
Consolidated other income in 20242025 was $23.0$12.1 million, as compared with $15.8$23.0 million in 2023.2024. This increasedecrease was primarily due to lower capitalization of AFUDC, a prior year reversal of $2.3 million reversal offrom a previously expenseddisclosed Community Renewable Energy ProjectCREP penalty due to a favorable legal ruling, higher capitalization of AFUDC,and a decrease$1.3 inmillion expense current year accrual related to an estimated penalty for the non-serviceCREP costinformed componentby ofa pensionrecent expense,MPSC andruling, partly offset by an increase in the value of deferred$2.5 sharesmillion held in trust for deferred compensation, offset in partdriven by a $2.5prior millionyear non-cash impairment of an alternative energy storage equity investment.
Consolidated income tax benefitexpense in 20242025 was $9.4$6.5 million, as compared to an income tax expensebenefit of $7.5$9.4 million in 2023.2024. Our effective tax rate for the twelve months ended December 31, 20242025 was (4.4)3.5 percent as compared with 3.7(4.4) percent for the same period of 2023.2024. As further discussed in Note 1214 - 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. Income tax expense for the twelve months ended December 31, 2023, includes a one-time $3.2 million expense for the reduction of previously claimed alternative minimum tax credits as well as a $3.2 million benefit related to a reduction in our unrecognized tax benefits.
(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.
Lower electric residential and commercialElectric retail volumes were driven by unfavorablefavorable weather in South Dakota impacting residential demanddemand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in allSouth jurisdictionsDakota, asand compared to the prior year, partly offset by higherlower industrial demand and customer growth.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.
What changed in the latest 10-Q
Risk Factors
Refer to the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025 for disclosure of the risk factors that could have a significant impact on our business, financial condition, results of operations or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not changed materially since such disclosure.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
New heading “Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025”
New heading “Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025”
New heading “Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025”
Largest changes
“Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025”see in full comparison
“Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025”see in full comparison
“Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025”see in full comparison
“Consolidated other income was $4.5 million for the three months ended June 30, 2026 as compared with $0.1 million for the same period of 2025. This increase was primarily due to an increase in the value of deferred shares held in trust for deferred compensation, a prior year $1.0 million expense accrual related to an estimated penalty for the previously disclosed Community Renewable Energy Project (CREP) informed by a MPSC ruling, and higher capitalization of AFUDC.”see in full comparison
Consolidated other income wassee in full comparison$3.1$7.6 million for thethreesix months endedMarchJune31,30, 2026 as comparedwithto$3.9$4.0 millionforduring the same period of 2025. Thisdecreaseincrease was primarily due tohigherannon-service component pension expense and a decreaseincrease in the value of deferred shares held in trust for deferredcompensationcompensation, a prior year $1.0 million expense accrual related to an estimated penalty for the previously disclosed CREP informed by a MPSC ruling, and higher capitalization of AFUDC, partly offset by highercapitalizationnon-serviceofcomponentAFUDC.pension expense.
“Consolidated interest expense was $40.3 million for the three months ended June 30, 2026 as compared with $36.3 million for the same period of 2025. This increase was due to higher borrowings and interest rates partly offset by higher capitalization of Allowance for Funds Used During Construction (AFUDC).”see in full comparison
Full comparison: every changed paragraph (72)
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 a 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 Accounting Standards Codification 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. Subject to the approval of the Merger from the MPSC and satisfaction or waiver of the other remaining closing conditions, we anticipate the transaction closing by year-end 2026. See Note 2 - Pending Merger with Black Hills Corporation to the Condensed Consolidated Financial Statements included herein for additional information regarding this pending Merger.
As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three and six months ended MarchJune 31,30, 2026 and 2025.
Consolidated net income for the three months ended MarchJune 31,30, 2026 was $63.5$25.0 million as compared with $76.9$21.2 million for the same period in 2025. This decreaseincrease was primarily due to new rates and retail volumes,volumes. These were offset in part by operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, depreciation expense, and interest expense. These were offset in part by new rates, transmission revenues, and lower non-recoverable Montana electric supply costs.
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, for which we have requested an effective date of July 1, 2025, to align with the PCCAM tracker year. Any subsequent modifications by the MPSC to their final order willare expected to be reflected in our 2026 results.
During the three and six months ended MarchJune 31,30, 2026, power prices in the Pacific Northwest associated with these designated power sales contracts included within our PCCAM tariff waiver were insufficient to contribute to the recovery of the operating and maintenance expenses associated with the Avista Interests.
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. Unlike the Avista Interests, we do not currently need this capacity to serve existing customers in Montana. As such, the Puget Interests are held by our FERC regulated subsidiary to isolate the costs associated with this acquired interest from our Montana retail customers. 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. In February 2026, the FERC approved both the cost-based rates and the contract rates retroactive to January 1, 2026. In March 2026, two MPSC commissioners, in their individual capacity, filed a motion with the FERC requesting a rehearing that largely reiterated arguments previously rejected by the FERC. We anticipate that theThe FERC will rule ondenied this motion by operation of law. In June 2026, the two MPSC commissioners appealed the decision to the Ninth Circuit. We have intervened in the second quarter of 2026. If the FERC denies the motion, its order will stand. If the FERC grants the motion, it could reopen all or some portion of the proceedings.case.
The Southwest Power Pool (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. As of June 30, 2026, we have recorded $42.3 million within Other noncurrent assets on the Condensed Consolidated Balance Sheets for non-refundable milestone payments to secure the turbines that will be used at this facility.
The South Dakota Legislature approved Senate Bill 36, and the Governor signed this bill into law,law in March 2026. It precludes common law strict liability claims for utility operations alleged to have caused wildfire-related damages; establishes a statutory standard of care, supplanting common law causes of action and other theories of recovery; and creates a rebuttable presumption that a valid and current wildfire mitigation plan is reasonable preparation for, and mitigation of, wildfire risk. 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 a qualified utility acted with willful and wanton misconduct and the qualified utility's willful and wanton misconduct was the actual and proximate cause of damages to the plaintiff. We anticipate filing our wildfire mitigation plan with the SDPUC in the secondthird halfquarter of 2026.
Three Months Ended MarchJune 31,30, 2026 Compared with the Three Months Ended MarchJune 31,30, 2025
Consolidated net income for the three months ended MarchJune 31,30, 2026 was $63.5$25.0 million as compared with $76.9$21.2 million for the same period in 2025. This decreaseincrease was primarily due to new rates and retail volumes,volumes. These were offset in part by operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, depreciation expense, and interest expense. These were offset in part by new rates, transmission revenues, and lower non-recoverable Montana electric supply costs.
Consolidated gross margin for the three months ended MarchJune 31,30, 2026 was $160.3$106.6 million as compared with $166.2$94.5 million in 2025, aan decreaseincrease of $5.9$12.1 million, or 3.512.8 percent. This decreaseincrease was primarily due to new rates and retail volumes,volumes. operatingThese expenses,were offset in part by higher operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, and depreciation expense. These were offset in part by new rates, transmission revenues, and lower non-recoverable Montana electric supply costs.
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated utility margin for the three months ended MarchJune 31,30, 2026 was $352.0$302.8 million as compared with $328.4$267.4 million for the same period in 2025, an increase of $23.6$35.4 million, or 7.213.2 percent. Primary components of the change in utility margin include the following (in millions):
Electric retail volumes were impacted by favorable weather in South Dakota and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana. Natural gas retail volumes were impacted by favorable weather in Montana and South Dakota, the acquisition of the Energy West operations in July 2025, and customer growth, partly offset by unfavorable weather in Nebraska.
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Electric retail volumes were driven by unfavorable weather partly offset by customer growth. Natural gas retail volumes were driven by unfavorable weather partly offset by customer growth and the acquisition of Energy West operations.
Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility (QF) costs) were allocated 90 percent to Montana customers and 10 percent to shareholders. Effective February 1, 2026 the cost sharing mechanism of the PCCAM was suspended on aan temporaryinterim basis pending further review by the MPSC. For the three months ended MarchJune 31,30, 2026,2025, we under-collected supply costs of $20.7 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance for January 2026). For the three months ended March 31, 2025, we under-collected supply costs of $24.3 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $2.7$0.8 million (10 percent of the PCCAM Base cost variance).
Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $237.8$238.6 million for the three months ended MarchJune 31,30, 2026, as compared with $203.7$206.7 million for the three months ended MarchJune 31,30, 2025. Primary components of the change include the following (in millions):
Consolidated operating income for the three months ended June 30, 2026 was $64.2 million as compared with $60.8 million in the same period of 2025. This increase was primarily due to new rates and retail volumes. These were offset in part by operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, and depreciation expense.
Consolidated interest expense was $40.3 million for the three months ended June 30, 2026 as compared with $36.3 million for the same period of 2025. This increase was due to higher borrowings and interest rates partly offset by higher capitalization of Allowance for Funds Used During Construction (AFUDC).
Consolidated other income was $4.5 million for the three months ended June 30, 2026 as compared with $0.1 million for the same period of 2025. This increase was primarily due to an increase in the value of deferred shares held in trust for deferred compensation, a prior year $1.0 million expense accrual related to an estimated penalty for the previously disclosed Community Renewable Energy Project (CREP) informed by a MPSC ruling, and higher capitalization of AFUDC.
Consolidated income tax expense was $3.5 million for the three months ended June 30, 2026 as compared to $3.4 million for the same period of 2025. Our effective tax rate for the three months ended June 30, 2026 was 12.2% as compared with 13.7% for the same period in 2025.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (dollars in millions):
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. 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.
Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025
Consolidated net income for the six months ended June 30, 2026 was $88.5 million as compared with $98.2 million for the same period in 2025. This decrease was primarily due to retail volumes, Montana property tax collections, operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, depreciation expense, and interest expense. These were offset in part by new rates, lower non-recoverable Montana electric supply costs, and transmission revenues.
Consolidated gross margin for the six months ended June 30, 2026 was $266.9 million as compared with $260.9 million in 2025, an increase of $6.0 million, or 2.3 percent. This increase was primarily due to new rates, lower non-recoverable Montana electric supply costs, and transmission revenues. These were offset in part by retail volumes, Montana property tax collections, operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, and depreciation expense.
Consolidated utility margin for the six months ended June 30, 2026 was $654.8 million as compared with $595.9 million for the same period in 2025, an increase of $58.9 million, or 9.9 percent. Primary components of the change in utility margin include the following (in millions):
Electric retail volumes were impacted by unfavorable weather in all jurisdictions partly offset by customer growth in all jurisdictions. Natural gas retail volumes were impacted by unfavorable weather in all jurisdictions, partly offset by customer growth in all jurisdictions and the acquisition of the Energy West operations in July 2025.
Effective February 1, 2026 the cost sharing mechanism of the PCCAM was suspended on an interim basis pending further review by the MPSC. For the six months ended June 30, 2026, we recorded a decrease in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance). For the six months ended June 30, 2025, we recorded a decrease in pre-tax earnings of $3.5 million (10 percent of the PCCAM Base cost variance).
Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $476.4 million for the six months ended June 30, 2026, as compared with $410.3 million for the six months ended June 30, 2025. Primary components of the change include the following (in millions):
Consolidated operating income for the threesix months ended MarchJune 31,30, 2026 was $114.1$178.4 million as compared with $124.7$185.5 million in the same period of 2025. This decrease was primarily due to retail volumes, Montana property tax collections, operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, and depreciation expense. These were offset in part by new rates, transmission revenues, and lower non-recoverable Montana electric supply costs.costs, and transmission revenues.
Consolidated interest expense was $39.9$80.2 million for the threesix months ended MarchJune 31,30, 2026 as compared with $36.5$72.8 million for the same period of 2025. This increase was due to higher borrowings and interest rates partly offset by higher capitalization of Allowance for Funds Used During Construction (AFUDC).AFUDC.
Consolidated other income was $3.1$7.6 million for the threesix months ended MarchJune 31,30, 2026 as compared withto $3.9$4.0 million forduring the same period of 2025. This decreaseincrease was primarily due to higheran non-service component pension expense and a decreaseincrease in the value of deferred shares held in trust for deferred compensationcompensation, a prior year $1.0 million expense accrual related to an estimated penalty for the previously disclosed CREP informed by a MPSC ruling, and higher capitalization of AFUDC, partly offset by higher capitalizationnon-service ofcomponent AFUDC.pension expense.
Consolidated income tax expense was $13.8 million for the threesix months ended MarchJune 31,30, 2026 was $17.3 million as compared to $15.2$18.6 million forin the same period of 2025. Our effective tax rate for the threesix months ended MarchJune 31,30, 2026 was 17.9%16.3% as compared with 16.5%15.9% for the same period in 2025.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (dollars in millions):
Three Months Ended MarchJune 31,30, 2026 Compared with the Three Months Ended MarchJune 31,30, 2025
(1) Exclusive of depreciation and depletion.
(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 three months ended MarchJune 31,30, 2026 and 2025 (in millions):
Electric retail volumes were drivenimpacted by unfavorablefavorable weather partlyin offsetSouth byDakota and customer growth in all jurisdictions.jurisdictions, partly offset by unfavorable weather in Montana.
Effective February 1, 2026 the cost sharing mechanism of the PCCAM was suspended on aan temporaryinterim basis pending further review by the MPSC. For the three months ended MarchJune 31,30, 2026,2025, we under-collected supply costs of $20.7 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance for January 2026). For the three months ended March 31, 2025, we under-collected supply costs of $24.3 million resulting in an increase to our under collection of costs, and recorded decrease in pre-tax earnings of $2.7$0.8 million (10 percent of the PCCAM Base cost variance).
Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025
(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.
The following summarizes the components of the changes in electric utility margin for the six months ended June 30, 2026 and 2025 (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 impacted by unfavorable weather in all jurisdictions partly offset by customer growth in all jurisdictions.
Effective February 1, 2026 the cost sharing mechanism of the PCCAM was suspended on an interim basis pending further review by the MPSC. For the six months ended June 30, 2026, we recorded a decrease in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance). For the six months ended June 30, 2025, we recorded a decrease in pre-tax earnings of $3.5 million (10 percent of the PCCAM Base cost variance).
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.
Three Months Ended MarchJune 31,30, 2026 Compared with the Three Months Ended MarchJune 31,30, 2025
(1) Exclusive of depreciation and depletion.
(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 three months ended MarchJune 31,30, 2026 and 2025:
Natural gas retail volumes were impacted by favorable weather in Montana and South Dakota, the acquisition of the Energy West operations in July 2025, and customer growth, partly offset by unfavorable weather in Nebraska.
Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025
(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.
The following summarizes the components of the changes in natural gas utility margin for the six months ended June 30, 2026 and 2025:
(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 drivenimpacted by unfavorable weather in all jurisdictions, partly offset by customer growth in all jurisdictions and the acquisition of the Energy West operations.operations in July 2025.
NWE insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-10-01 | Horsfall Jan Robert |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-10-01 | Yingling Jeffrey W. |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-10-01 | Edwards Sherina M. |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-10-01 | Goodin David L |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-10-01 | Ide Britt E |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-10-01 | Larson Kent T |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-10-01 | Sullivan Linda G |
Grant/award | 804 | $68.38 | $55.0K |
| 2026-10-01 | Yazdi Mahvash |
Grant/award | 548 | $68.38 | $37.5K |
| 2026-08-06 | Horsfall Jan Robert |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-08-04 | Yingling Jeffrey W. |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-07-09 | Yazdi Mahvash |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-07-09 | Ide Britt E |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-07-09 | Goodin David L |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-07-09 | Edwards Sherina M. |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-07-09 | Larson Kent T |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-07-09 | Sullivan Linda G |
Grant/award | 768 | $71.62 | $55.0K |
| 2026-07-06 | Yazdi Mahvash |
Grant/award | 524 | $71.62 | $37.5K |
| 2026-05-11 | Yingling Jeffrey W. |
Grant/award | 569 | $65.94 | $37.5K |
| 2026-05-11 | Horsfall Jan Robert |
Grant/award | 569 | $65.94 | $37.5K |
Well-known investors holding NWE (13F)
None of the 59 investors we track reported a position in their latest 13F.