What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2026-02-12 compared with 2025-02-13 · 176 added, 154 removed, 490 unchanged (40% of the section changed)

18 unchanged sentences

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.

13 unchanged sentences

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.

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.

8 unchanged sentences

14.0 (3.5) 10.5

Montana interim rates (subject to refund) 4.8 (1.2) 3.6

Montana natural gas transportation 2.3 (0.6) 1.7

Montana property tax tracker collections 1.1 (0.3) 0.8

Production tax credits, offset within income tax benefit (expense)

Non-recoverable Montana electric supply costs

(7.9) 2.0 (5.9)

QF liability adjustment

Montana natural gas transportation 4.8 (1.2) 3.6

Electric retail volumes

4.3 (1.1) 3.2

1 unchanged sentence

2.0 (0.5) 1.5

Electric retail volumes

Montana property tax tracker collections (14.2) 3.6 (10.6)

Non-recoverable Montana electric supply costs

(7.3) 1.8 (5.5)

3 unchanged sentences

(37.7) 9.5 (28.2)

Non-cash regulatory disallowance of certain YCGS capital costs

(30.9) 7.8 (23.1)

(21.9) 5.5 (16.4)

Interest expense

(18.7) 4.7 (14.0)

Merger-related costs

(9.3) — (9.3)

Property and other taxes not recoverable within trackers

(2.1) 0.5 (1.6)

Release of unrecognized tax benefits (inclusive of related interest previously accrued)

Gas repairs safe harbor method change

Release of unrecognized tax benefits - current year

Release of unrecognized tax benefits - prior year

— (16.9) (16.9)

Prior year Gas repairs safe harbor method change

— (7.0) (7.0)

Other (10.1) 3.7 (6.4)

4 unchanged sentences

Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024.

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.

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

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 1 8 - 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 first with Avista Corporation (Avista) and the second with Puget Sound Energy (Puget), to acquire their respective interests in Colstrip Units 3 & 4 for $0.

In particular, we agreed to acquire a 15% (222 megawatts) interest from Avista and a 25% (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 starting on January 1, 2026;

while 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 decommission and demolition costs associated with the existing facilities that comprise their interests.

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.

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 1 8 - 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.

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)

Return on Equity (ROE)

9.65 % 9.60 %

Equity Capital Structure

47.84 % 47.84 %

$ 105.5 $ 18.0

Property Tax (tracker base adjustment) (1)

Total Revenue Increase Through Final Order

(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 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 phase and initiating regulatory filings with approvals targeted in 2026.

Construction is expected to commence in 2028, 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 invest when the regulatory approvals and permits are in place.

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.

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.

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 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.

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

5 unchanged sentences

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.

Over $2.2 billion or 82 percent of our capital forecast above is projected to be spent on our distribution and transmission system.

Beginning in 2021, we began installing 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.

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

6 unchanged sentences

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 using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees.

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.

8 unchanged sentences

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

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.

Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024, a decrease of $43.0 million.

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 new base rates in Montana and South Dakota, electric transmission revenue, Montana interim rates, subject to refund, and Montana property tax tracker collections.

These were offset in party by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, and depreciation.

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 Natural Gas Total

31 unchanged sentences

Electric transmission revenue due to market conditions and rates 14.0

Montana interim rates (subject to refund) 4.8

Montana natural gas transportation 4.8

Electric retail volumes 4.3

Natural gas retail volumes ($4.2 million due to acquisition of Energy West Operations) 2.0

Montana property tax tracker collections (14.2)

Non-recoverable Montana electric supply costs

QF liability adjustment

Natural gas retail volumes (4.0)

Electric retail volumes (0.9)

Change in Utility Margin Impacting Net Income 97.0

1 unchanged sentence

Property and other taxes recovered in revenue, offset in property and other taxes 16.3

Operating expenses recovered in revenue, offset in operating and maintenance expense 2.4

Production tax credits, offset in income tax expense 6.6

Operating expenses recovered in revenue, offset in operating and maintenance expense 0.8

Change in Items Offset Within Net Income 23.7

2 unchanged sentences

See "Non-GAAP Financial Measure" above.

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) are allocated 90 percent to Montana customers and 10 percent to shareholders.

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, 2023, we over collected supply costs of $32.9 million resulting in a reduction to our under collection 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 to the retroactive application of higher PCCAM Base rates to July 1, 2022.

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.

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.

Year Ended December 31,

11 unchanged sentences

Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income

Non-cash regulatory disallowance of certain YCGS capital costs

Depreciation expense due to plant additions and higher depreciation rates 21.9

Labor and benefits (1)

Electric generation maintenance 9.9

Merger-related costs, primarily including consulting and legal fees 9.3

Wildfire mitigation expense, partly offset by higher base revenues 8.9

Insurance expense, primarily due to increased wildfire risk premiums 7.8

Labor and benefits (1)

Technology implementation and maintenance 3.5

Property and other taxes not recoverable within trackers 2.1

Uncollectible accounts 1.1

Litigation outcome (Pacific Northwest Solar) (2.4)

Electric generation maintenance 2.0

Non-cash impairment of alternative energy storage investment (1.7)

Technology implementation and maintenance 1.5

Uncollectible accounts (1.4)

Change in Items Impacting Net Income 101.9

1 unchanged sentence

Property and other taxes recovered in trackers, offset in revenue 16.3

Pension and other postretirement benefits, offset in other income (1)

Operating and maintenance expenses recovered in trackers, offset in revenue 2.4

Deferred compensation, offset in other income 2.1

Operating and maintenance expenses recovered in trackers, offset in revenue 0.8

Pension and other postretirement benefits, offset in other income (1)

Change in Items Offset Within Net Income 16.3

3 unchanged sentences

Consolidated operating income in 2025 was $325.8 million as compared with $323.3 million in 2024.

This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenue, Montana interim rates, subject to refund, and Montana property tax tracker collections.

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.

Consol idated 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 higher capitalization of AFUDC.

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 increase was primarily due to a $2.3 million reversal of a previously expensed Community Renewable Energy Project penalty due to a favorable legal ruling, higher capitalization of AFUDC, a decrease in the non-service cost component of pension expense, and an increase in the value of deferred shares held in trust for deferred compensation, offset in part by a $2.5 million non-cash impairment of an alternative energy storage equity investment.

Consolidated income tax benefit in 2024 was $9.4 million, as compared to an income tax expense of $7.5 million in 2023.

Our effective tax rate for the twelve months ended December 31, 2024 was (4.4) percent as compared with 3.7 percent for the same period of 2023.

As further discussed in Note 12 - Income Taxes , 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).

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.

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.

We currently estimate our effective tax rate will range between 14.0 percent to 18.0 percent in 2026.

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Year Ended December 31,

(in dollars) (in percent) (in dollars) (in percent)

Income before income taxes $187.6 $214.7

Income tax calculated at federal statutory rate 39.4 21.0 % 45.1 21.0 %

Permanent or flow through adjustments:

State income taxes, net of federal provisions 0.4 0.2 0.6 0.3

Flow-through repairs deductions (23.1) (10.8) (25.9) (12.9)

Release of unrecognized tax benefits (2024 is inclusive of $4.1 million of related interest previously accrued)

State income tax, net of federal provision

(1.5) (0.8) 0.4 0.2

Production tax credits (5.9) (3.2) (11.1) (5.2)

Gas repairs safe harbor method change (7.0) (3.3) — —

Other 0.7 0.4 0.7 0.3

Impact of utility ratemaking on income taxes

Flow-through repairs deductions (31.0) (16.5) (23.1) (10.8)

Amortization of excess deferred income taxes (3.2) (1.7) (2.9) (1.4)

Prior year permanent return to accrual adjustments (0.4) (0.2) — —

(1.3) (0.7) (2.6) (1.2)

Plant and depreciation of flow through items 16.8 9.0 9.4 4.4

Unregulated Tax Cuts and Jobs Act excess deferred income taxes — — (3.4) (1.7)

Reduction to previously claimed alternative minimum tax credit

Other, net 1.2 0.7 (0.3) (0.1)

Gas repairs safe harbor method change — — (7.0) (3.3)

Changes in Unrecognized Tax Benefits

Release of unrecognized tax benefits (7.4) (4.0) (16.9) (7.9)

Interest and penalties

(3.0) (1.6) (1.5) (0.7)

Income Tax (Benefit) Expense $ (9.4) (4.4) % $ 7.5 3.7 %

Nontaxable and nondeductible items 2.9 1.5 0.4 0.2

Other 0.0 0.1 (0.3) 0.0

(32.9) (17.5) % (54.5) (25.4) %

Income Tax Expense (Benefit) and Effective Tax Rate $ 6.5 3.5 % $ (9.4) (4.4) %

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.

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Industrial 43,128 46,637 (3,509) (7.5) 2,789 2,924 80 80

Other 32,811 32,756 55 0.2 146 134 6,544 6,443

34,510 32,811 1,699 5.2 147 146 28,564 28,608

Total Retail Electric $ 1,090,813 $ 1,069,040 $ 21,773 2.0 % 10,630 10,721 504,937 497,537

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$ 963,387 $ 871,123 $ 92,264 10.6 %

(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.

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2025 2024 Historic Average 2024 Historic Average

Montana 485 441 448 10% warmer 8% warmer

South Dakota 778 1,035 752 25% cooler 3% warmer

Montana 392 485 460 19% cooler 15% cooler

South Dakota 938 778 751 21% warmer 25% warmer

Heating Degree Days 2025 as compared with:

2025 2024 Historic Average 2024 Historic Average

7,033 7,237 7,554 3% warmer 7% warmer

South Dakota 6,501 7,665 7,724 15% warmer 16% warmer

7,044 7,033 7,486 remained flat 6% warmer

South Dakota 6,943 6,501 7,696 7% colder 10% warmer

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

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Electric transmission revenue due to market conditions and rates 14.0

Montana interim rates (subject to refund) 2.8

Retail volumes 4.3

Montana property tax tracker collections (10.8)

Non-recoverable Montana electric supply costs (7.3)

QF liability adjustment (4.2)

Retail volumes (0.9)

Change in Utility Margin Items Impacting Net Income 71.9

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Property and other taxes recovered in revenue, offset in property and other taxes 12.7

Operating expenses recovered in revenue, offset in operating and maintenance expense 1.7

Production tax credits, offset in income tax expense 6.6

Operating expenses recovered in revenue, offset in operating and maintenance expense 1.1

Change in Items Offset Within Net Income 20.4

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Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

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, as further explained above in the consolidated results of operations for the twelve months ended December 31, 2024.

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.

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Regulatory amortization (305) 19,017 (19,322) (101.6)

Wholesale and other 44,057 45,271 (1,214) (2.7)

Transportation, wholesale and other 57,528 44,057 13,471 30.6

Total Revenues $ 340,603 $ 313,197 $ 27,406 8.8 %

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7,207 7,265 7,697 1% warmer 6% warmer

South Dakota 6,501 7,665 7,724 15% warmer 16% warmer

Nebraska 5,241 5,893 6,085 11% warmer 14% warmer

South Dakota 6,943 6,501 7,696 7% colder 10% warmer

Nebraska 5,719 5,241 6,061 9% colder 6% warmer

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

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Montana natural gas transportation 4.8

Montana interim rates (subject to refund) 2.0

Retail volumes (4.0)

Retail volumes ($4.2 million due to acquisition of Energy West Operations)

Montana property tax tracker collections

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Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Lower retail volumes were driven by unfavorable weather in all jurisdictions partly offset by customer growth.

Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

LIQUIDITY AND CAPITAL RESOURCES

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Property, plant and equipment additions (524.5) (549.3)

Acquisition of Energy West Operations (35.9) —

Other investing activity

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Financing Activities

Proceeds from issuance of common stock, net — 73.6

Issuance of long-term debt 602.1 215.0

Issuance of short-term borrowings 50.0 100.0

Repayments on long-term debt (300.0) (100.0)

Dividends on common stock (161.4) (158.6)

Line of credit borrowings (repayments), net

Line of credit (repayments) borrowings , net (9.0) 95.0

Financing costs (4.5) (1.1)

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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.

As shown in the table below, this decrease in operating cash flows is primarily due to minimal net cash inflows for energy supply costs in the current period due to the timely recovery of energy supply costs compared to significant net cash inflows in 2023 from the recovery of previously under-collected energy supply costs.

Net under-collected supply costs (in millions)

Beginning of year End of year Net cash inflows

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.

Net under-collected energy supply costs (in millions)

Beginning of year End of year Net cash inflows (outflows)

2024 $ 7.8 $ 5.9 $ 1.9

2025 $ 5.9 $ 44.8 $ (38.9)

Improvement in annual net cash inflows

Increase in net cash outflows $ (40.8)

Investing Activities

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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.

Additionally, as discussed above in the "Significant Trends and Regulation" section, we anticipate investing $39.0 million for the acquisition of the Energy West Montana Assets in 2025.

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, 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 1.00 percent, $100.0 million of Montana First Mortgage Bonds.

During the year ended December 31, 2023, cash provided by financing activities reflects net proceeds from the issuance of long-term debt of $300.0 million and proceeds received from the issuance of common stock of $73.6 million, partly offset by payment of dividends of $154.1 million and net repayments under our revolving lines of credit of $132.0 million.

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.

Cash Requirements and Capital Resources

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We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt issuances and future rate increases.

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.

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.

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

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BBB - BBB Stable

BBB - - Stable

BBB - - Positive

BBB A- BBB+ Stable

Baa2 A3 Baa2 Stable

BBB A- - Stable

BBB A- - Positive

NWE Public Service

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These commitments range from one to 24 years.

The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC, as further described in Note 3 - Regulatory Matters .

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 Liab ilities .

(5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate.

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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.

We have unrecognized tax benefits of approximately $9.6 million as of December 31, 2024.

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis