Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.
We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
OVERVIEW
NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 850,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025.
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.
We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:
•Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
•Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
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•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.
We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
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.
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 June 30, 2026 and 2025.
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HOW WE PERFORMED AGAINST OUR SECOND QUARTER 2025 RESULTS
Three Months Ended June 30, 2026 vs. 2025
Income Before Income Taxes Income Tax (Expense) Benefit(3) Net Income
(in millions)
Second Quarter, 2025 $ 24.6 $ (3.4) $ 21.2
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income:
Rates 13.8 (3.5) 10.3
Electric retail volumes 7.3 (1.8) 5.5
Electric margin from the acquisition of the Colstrip Puget Interests 4.7 (1.2) 3.5
Natural gas retail volumes 3.5 (0.9) 2.6
Production tax credits, offset within income tax expense 1.4 (1.4) —
Electric transmission revenue 1.0 (0.3) 0.7
Non-recoverable Montana electric supply costs 0.8 (0.2) 0.6
Natural gas production step down (0.4) 0.1 (0.3)
Montana property tax tracker collections (0.2) 0.1 (0.1)
Other 1.1 (0.3) 0.8
Variance in expense items(2) impacting net income:
Operating, maintenance, and administrative, excluding merger-related costs (16.7) 4.2 (12.5)
Depreciation (4.6) 1.2 (3.4)
Interest expense (4.0) 1.0 (3.0)
Merger-related costs (3.3) 0.7 (2.6)
Property and other taxes not recoverable within trackers (2.0) 0.5 (1.5)
Other 1.5 1.7 3.2
Second Quarter, 2026 $ 28.5 $ (3.5) $ 25.0
Change in Net Income $ 3.8
(1) Exclusive of depreciation and depletion shown separately below
(2) Excluding fuel, purchased supply, and direct transmission expense
(3) Income tax expense calculation on reconciling items assumes a blended federal plus state effective tax rate of 25.3 percent.
Consolidated net income for the three months ended June 30, 2026 was $25.0 million as compared with $21.2 million for the same period in 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, depreciation expense, and interest expense.
SIGNIFICANT TRENDS AND REGULATION
Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2025 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows:
Montana Rate Review
In December 2025, the MPSC issued a final order approving our partial electric settlement agreement. The final order also suspended the 90/10 cost sharing mechanism of the Power Cost and Credit Adjustment Mechanism (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
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the construction of Yellowstone County Generating Station (YCGS). As a result, in the fourth quarter of 2025 we recorded a $30.9 million non-cash charge for the regulatory disallowance.
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 are expected to be reflected in our 2026 results.
Montana Large New Load Tariff Rule
In March 2026, we filed an application with the MPSC requesting approval of a Large New Load tariff rule (LNL Rule) to establish requirements and contract terms for providing electric service to bundled customers with new or expanded loads of five megawatts or greater, including data centers and other energy-intensive operations. This filing establishes a framework governing agreements between us and large new load customers and is intended to address the costs and operational considerations associated with serving those loads while protecting existing customers from cost shifting and other adverse impacts. Under this proposed framework, for the largest commitments, 50 megawatts or greater, we would file the executed Electric Service Agreement with the MPSC for review and approval before service begins. For customers with loads between 5 and 49 megawatts, the tariff's standardized process and mandatory protections apply, but individual agreements do not require case-specific MPSC approval filings. This application initiates a public regulatory proceeding that will include opportunities for review and public comment consistent with MPSC procedures.
Data Center Development
As previously disclosed, we have signed development agreements with both Sabey Data Centers and Atlas Power Holdings LLC to provide electric supply services for data centers being developed in Montana. In April 2026, we signed a development agreement with Quantica Infrastructure to evaluate the transmission infrastructure and generation resources needed to support their proposed need. The combined energy service requirement associated with these development agreements is currently expected to be 150 megawatts beginning in late 2027, with growth of up to approximately 1,500 megawatts or more by 2030. We are working with each of these parties to execute electric service agreements.
Resources and regulatory mechanisms, such as the LNL Rule discussed above, 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, AROs, 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 could provide a near-term cost-recovery mechanism to offset a portion of the 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.
During the three and six months ended June 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
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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. The FERC denied 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 case.
Generation Capacity in South Dakota
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.
Regional Transmission Development Activities
In December 2024, we signed a nonbinding memorandum of understanding (MOU) with North Plains Connector LLC, a wholly owned subsidiary of Grid United, to own 10 percent (300 megawatts) of the NPC Consortium project. The project is entering the permitting phase. Currently, construction is planned to commence in 2028, subject to receipt of regulatory approvals, with the project expected to be operational by 2032. Under the terms of the MOU, Grid United will continue to fund the development of the NPC and we will make our investment decision when the regulatory approvals and permits are in place. The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region.
We have also entered into a nonbinding letter of intent with Grid United to continue transmission development to further enhance the grid through the southwest corridor of Montana. Development to expand the southwest corridor of Montana through grid build out would represent a significant step in enhancing connectivity between Montana and the broader Western energy market - bolstering grid reliability, allowing for critical import capability, and enabling customers to access and benefit from emerging energy markets in the West.
South Dakota Wildfire Risk Mitigation
The South Dakota Legislature approved Senate Bill 36, and the Governor signed this bill into 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 third quarter of 2026.
RESULTS OF OPERATIONS
Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.
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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 and commercial customers. We measure this effect based on the number of customers, temperature variances, and the amount of electricity or natural gas historically used per degree of temperature. Degree-day, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees, is used to estimate the amount of energy required to maintain comfortable indoor temperature levels based on each day's average temperature. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.
Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.
Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.
OVERALL CONSOLIDATED RESULTS
Three Months Ended June 30, 2026 Compared with the Three Months Ended June 30, 2025
Consolidated net income for the three months ended June 30, 2026 was $25.0 million as compared with $21.2 million for the same period in 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, depreciation expense, and interest expense.
Consolidated gross margin for the three months ended June 30, 2026 was $106.6 million as compared with $94.5 million in 2025, an increase of $12.1 million, or 12.8 percent. This increase was primarily due to new rates and retail volumes. These 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.
Electric Natural Gas Total
2026 2025 2026 2025 2026 2025
(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues $ 324.2 $ 279.4 $ 68.4 $ 63.3 $ 392.6 $ 342.7
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 72.8 59.6 17.0 15.7 89.8 75.3
Less: Operating and maintenance 63.6 48.6 15.5 13.7 79.1 62.3
Less: Property and other taxes 39.1 37.3 11.0 10.9 50.1 48.2
Less: Depreciation and depletion 55.6 52.4 11.4 10.0 67.0 62.4
Gross Margin 93.1 81.5 13.5 13.0 106.6 94.5
Add back: Operating and maintenance 63.6 48.6 15.5 13.7 79.1 62.3
Add back: Property and other taxes 39.1 37.3 11.0 10.9 50.1 48.2
Add back: Depreciation and depletion 55.6 52.4 11.4 10.0 67.0 62.4
Utility Margin(1) $ 251.4 $ 219.8 $ 51.4 $ 47.6 $ 302.8 $ 267.4
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
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Three Months Ended June 30,
2026 2025 Change % Change
(dollars in millions)
Utility Margin
Electric $ 251.4 $ 219.8 $ 31.6 14.4 %
Natural Gas 51.4 47.6 3.8 8.0
Total Utility Margin(1) $ 302.8 $ 267.4 $ 35.4 13.2 %
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated utility margin for the three months ended June 30, 2026 was $302.8 million as compared with $267.4 million for the same period in 2025, an increase of $35.4 million, or 13.2 percent. Primary components of the change in utility margin include the following (in millions):
Utility Margin 2026 vs. 2025
Utility Margin Items Impacting Net Income
Base rates $ 13.8
Electric retail volumes 7.3
Electric margin from the acquisition of the Puget Interests 4.7
Natural gas retail volumes (including a $2.0 million increase due to acquisition of Energy West Operations) 3.5
Electric transmission revenue 1.0
Non-recoverable Montana electric supply costs 0.8
Natural gas production step down (0.4)
Montana property tax tracker collections (0.2)
Other 1.1
Change in Utility Margin Items Impacting Net Income 31.6
Utility Margin Items Offset Within Net Income
Operating expenses recovered in revenue, offset in operating and maintenance expense 2.4
Production tax credits, offset in income tax expense 1.4
Change in Utility Margin Items Offset Within Net Income 3.8
Increase in Consolidated Utility Margin(1) $ 35.4
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
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.
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 an interim basis pending further review by the MPSC. For the three months ended June 30, 2025, we recorded a decrease in pre-tax earnings of $0.8 million (10 percent of the PCCAM Base cost variance).
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Three Months Ended June 30,
2026 2025 Change % Change
(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance $ 79.1 $ 62.3 $ 16.8 27.0 %
Administrative and general 42.4 33.8 8.6 25.4
Property and other taxes 50.1 48.2 1.9 3.9
Depreciation and depletion 67.0 62.4 4.6 7.4
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 238.6 $ 206.7 $ 31.9 15.4 %
Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $238.6 million for the three months ended June 30, 2026, as compared with $206.7 million for the three months ended June 30, 2025. Primary components of the change include the following (in millions):
Operating Expenses
2026 vs. 2025
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Electric generation maintenance (Including $6.4 million and $3.7 million due to the acquisition of the Colstrip Puget Interests and Avista Interests, respectively) $ 9.0
Depreciation expense due to plant additions and higher depreciation rates 4.6
Merger-related costs, including consulting and legal fees 3.3
Wildfire mitigation expense, partly offset by higher base revenues 2.6
Property and other taxes not recoverable within trackers 2.0
Labor and benefits 1.7
Technology implementation and maintenance expenses 0.8
Insurance expense 0.3
Uncollectible accounts 0.2
Other 2.1
Change in Items Impacting Net Income 26.6
Operating Expenses Offset Within Net Income
Deferred compensation, offset in other income 3.0
Operating and maintenance expenses recovered in trackers, offset in revenue 2.4
Property and other taxes recovered in trackers, offset in revenue (0.1)
Change in Items Offset Within Net Income 5.3
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 31.9
We estimate property taxes throughout each year, and update those estimates based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases and decreases in the actual level of state and local taxes and fees and adjust our rates to recover the increase or decrease between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
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.
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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):
Three Months Ended June 30,
2026 2025
(in dollars) (in percent) (in dollars) (in percent)
Income before income taxes $ 28.5 $ 24.6
Income tax calculated at federal statutory rate 6.0 21.0 % 5.2 21.0 %
State income tax, net of federal provision 0.4 1.4 0.1 0.4
Tax Credits
Production tax credits (0.6) (2.1) (0.6) (2.4)
Impact of utility ratemaking on income taxes
Flow-through repairs deductions (4.4) (15.4) (2.8) (11.4)
Amortization of excess deferred income taxes (0.6) (2.1) (0.1) (0.4)
AFUDC, net (0.2) (0.7) (0.1) (0.4)
Plant and depreciation of flow through items 2.8 9.8 1.5 6.1
Nontaxable and nondeductible items 0.2 0.7 (0.3) (1.2)
Other (0.1) (0.4) 0.5 2.0
(2.5) (8.8) (1.8) (7.3)
Income Tax Expense and Effective Tax Rate $ 3.5 12.2 % $ 3.4 13.7 %
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.
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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.
Electric Natural Gas Total
2026 2025 2026 2025 2026 2025
(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues $ 686.3 $ 615.0 $ 203.9 $ 194.4 $ 890.2 $ 809.4
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 163.1 152.4 72.3 61.1 235.4 213.5
Less: Operating and maintenance 122.9 91.2 30.7 27.8 153.6 119.0
Less: Property and other taxes 78.3 70.6 22.2 20.6 100.5 91.2
Less: Depreciation and depletion 111.0 104.9 22.8 19.9 133.8 124.8
Gross Margin 211.0 195.9 55.9 65.0 266.9 260.9
Add back: Operating and maintenance 122.9 91.2 30.7 27.8 153.6 119.0
Add back: Property and other taxes 78.3 70.6 22.2 20.6 100.5 91.2
Add back: Depreciation and depletion 111.0 104.9 22.8 19.9 133.8 124.8
Utility Margin(1) $ 523.2 $ 462.6 $ 131.6 $ 133.3 $ 654.8 $ 595.9
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Six Months Ended June 30,
2026 2025 Change % Change
(dollars in millions)
Utility Margin
Electric $ 523.2 $ 462.6 $ 60.6 13.1 %
Natural Gas 131.6 133.3 (1.7) (1.3)
Total Utility Margin(1) $ 654.8 $ 595.9 $ 58.9 9.9 %
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
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):
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Utility Margin 2026 vs. 2025
Utility Margin Items Impacting Net Income
Base rates $ 37.5
Electric margin from the acquisition of the Puget Interests 10.2
Electric transmission revenue 5.4
Non-recoverable Montana electric supply costs 2.8
Electric retail volumes (4.9)
Montana property tax tracker collections (3.5)
Natural gas retail volumes (including a $5.2 million increase due to acquisition of Energy West Operations) (2.7)
Natural gas production step down (1.1)
Other 2.9
Change in Utility Margin Items Impacting Net Income 46.6
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes 5.1
Production tax credits, offset in income tax expense 4.0
Operating expenses recovered in revenue, offset in operating and maintenance expense 3.2
Change in Utility Margin Items Offset Within Net Income 12.3
Increase in Consolidated Utility Margin(1) $ 58.9
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
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).
Six Months Ended June 30,
2026 2025 Change % Change
(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance $ 153.6 $ 119.0 $ 34.6 29.1 %
Administrative and general 88.5 75.1 13.4 17.8
Property and other taxes 100.5 91.4 9.1 10.0
Depreciation and depletion 133.8 124.8 9.0 7.2
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 476.4 $ 410.3 $ 66.1 16.1 %
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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):
Operating Expenses
2026 vs. 2025
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Electric generation maintenance (including $12.7 million and $7.6 million due to the acquisition of the Colstrip Puget Interests and Avista Interests, respectively) 19.1
Depreciation expense due to plant additions and higher depreciation rates $ 9.0
Merger-related costs, including consulting and legal fees 6.7
Labor and benefits(1) 5.2
Wildfire mitigation expense, partly offset by higher base revenues 4.5
Property and other taxes not recoverable within trackers 4.0
Insurance expense 1.0
Technology implementation and maintenance expenses 1.0
Uncollectible accounts 0.7
Other 5.3
Change in Items Impacting Net Income 56.5
Operating Expenses Offset Within Net Income
Property and other taxes recovered in trackers, offset in revenue 5.1
Operating and maintenance expenses recovered in trackers, offset in revenue 3.2
Deferred compensation, offset in other income 2.0
Pension and other postretirement benefits, offset in other income(1) (0.7)
Change in Items Offset Within Net Income 9.6
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 66.1
(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.
Consolidated operating income for the six months ended June 30, 2026 was $178.4 million as compared with $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, lower non-recoverable Montana electric supply costs, and transmission revenues.
Consolidated interest expense was $80.2 million for the six months ended June 30, 2026 as compared with $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 AFUDC.
Consolidated other income was $7.6 million for the six months ended June 30, 2026 as compared to $4.0 million during 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 CREP informed by a MPSC ruling, and higher capitalization of AFUDC, partly offset by higher non-service component pension expense.
Consolidated income tax expense for the six months ended June 30, 2026 was $17.3 million as compared to $18.6 million in the same period of 2025. Our effective tax rate for the six months ended June 30, 2026 was 16.3% as compared with 15.9% for the same period in 2025.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
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Six Months Ended June 30,
2026 2025
(in dollars) (in percent) (in dollars) (in percent)
Income before income taxes $ 105.7 $ 116.8
Income tax calculated at federal statutory rate 22.2 21.0 % 24.5 21.0 %
State income tax, net of federal provision 1.4 1.3 0.9 0.8
Tax Credits
Production tax credits (1.1) (1.0) (2.7) (2.3)
Other — — 0.5 0.4
Impact of utility ratemaking on income taxes
Flow-through repairs deductions (12.0) (11.4) (10.8) (9.2)
Amortization of excess deferred income taxes (1.9) (1.8) (0.8) (0.7)
AFUDC, net (0.8) (0.8) (0.8) (0.7)
Plant and depreciation of flow through items 9.1 8.6 6.8 5.8
Changes in Unrecognized Tax Benefits
Interest and penalties — — 0.6 0.5
Nontaxable and nondeductible items 0.4 0.4 0.2 0.2
Other 0.0 0.0 0.2 0.1
(4.9) (4.7) (5.9) (5.1)
Income Tax Expense and Effective Tax Rate $ 17.3 16.3 % $ 18.6 15.9 %
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.
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ELECTRIC SEGMENT
We have various classifications of electric revenues, defined as follows:
•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory
mechanisms.
•Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Transmission: Reflects transmission revenues regulated by the FERC.
•Wholesale and other: Primarily represents revenues from wholesale electricity sales, as well as other miscellaneous electric revenues.
Three Months Ended June 30, 2026 Compared with the Three Months Ended June 30, 2025
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2026 2025 $ % 2026 2025 2026 2025
(in thousands)
Montana $ 98,447 $ 81,824 $ 16,623 20.3 % 594 571 337,611 333,302
South Dakota 17,983 16,235 1,748 10.8 121 113 51,990 51,663
Residential 116,430 98,059 18,371 18.7 715 684 389,601 384,965
Montana 110,833 93,910 16,923 18.0 761 754 77,961 77,173
South Dakota 30,341 27,737 2,604 9.4 252 246 13,274 13,182
Commercial 141,174 121,647 19,527 16.1 1,013 1,000 91,235 90,355
Industrial 10,831 9,888 943 9.5 667 684 81 80
Other 14,144 9,421 4,723 50.1 53 42 28,770 28,761
Total Retail Electric $ 282,579 $ 239,015 $ 43,564 18.2 % 2,448 2,410 509,687 504,161
Regulatory amortization (3,645) 10,325 (13,970) (135.3)
Transmission 29,141 28,147 994 3.5
Wholesale and Other 16,179 1,981 14,198 716.7
Total Revenues $ 324,254 $ 279,468 $ 44,786 16.0 %
Fuel, purchased supply and direct transmission expense(1) 72,836 59,603 13,233 22.2
Utility Margin(2) $ 251,418 $ 219,865 $ 31,553 14.4 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Cooling Degree Days 2026 as compared with:
2026 2025 Historic Average 2025 Historic Average
Montana 34 55 59 38% cooler 42% cooler
South Dakota 137 99 69 38% warmer 99% warmer
Heating Degree Days 2026 as compared with:
2026 2025 Historic Average 2025 Historic Average
Montana(1) 1,147 1,033 1,128 11% colder 2% colder
South Dakota 1,344 1,223 1,486 10% colder 10% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
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The following summarizes the components of the changes in electric utility margin for the three months ended June 30, 2026 and 2025 (in millions):
Utility Margin 2026 vs. 2025
Utility Margin Items Impacting Net Income
Base rates $ 13.8
Retail volumes 7.3
Electric margin from the acquisition of the Colstrip Puget Interests 4.7
Electric transmission revenue 1.0
Non-recoverable Montana electric supply costs 0.8
Montana property tax tracker collections (0.6)
Other 0.5
Change in Utility Margin Items Impacting Net Income 27.5
Utility Margin Items Offset Within Net Income
Operating expenses recovered in revenue, offset in operating and maintenance expense 2.5
Production tax credits, offset in income tax expense 1.4
Property and other taxes recovered in revenue, offset in property and other taxes 0.2
Change in Utility Margin Items Offset Within Net Income 4.1
Increase in Utility Margin(1) $ 31.6
(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 favorable weather in South Dakota and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana.
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 three months ended June 30, 2025, we recorded a decrease in pre-tax earnings of $0.8 million (10 percent of the PCCAM Base cost variance).
The change in regulatory amortization revenue is primarily due to timing differences between when we incur electric supply costs and property taxes 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.
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Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2026 2025 $ % 2026 2025 2026 2025
(in thousands)
Montana $ 218,885 $ 196,801 $ 22,084 11.2 % 1,377 1,473 337,395 332,820
South Dakota 41,212 38,527 2,685 7.0 299 308 52,005 51,727
Residential 260,097 235,328 24,769 10.5 1,676 1,781 389,400 384,547
Montana 217,315 190,862 26,453 13.9 1,550 1,600 78,190 77,296
South Dakota 61,738 57,051 4,687 8.2 521 530 13,256 13,156
Commercial 279,053 247,913 31,140 12.6 2,071 2,130 91,446 90,452
Industrial 22,695 19,988 2,707 13.5 1,369 1,388 81 80
Other 19,653 14,114 5,539 39.2 65 54 27,804 27,895
Total Retail Electric $ 581,498 $ 517,343 $ 64,155 12.4 % 5,181 5,353 508,731 502,974
Regulatory amortization 6,426 38,015 (31,589) (83.1)
Transmission 60,112 54,703 5,409 9.9
Wholesale and Other 38,272 4,890 33,382 682.7
Total Revenues $ 686,308 $ 614,951 $ 71,357 11.6 %
Fuel, purchased supply and direct transmission expense(1) 163,111 152,355 10,756 7.1
Utility Margin(2) $ 523,197 $ 462,596 $ 60,601 13.1 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Cooling Degree Days 2026 as compared with:
2026 2025 Historic Average 2025 Historic Average
Montana 34 55 59 38% cooler 42% cooler
South Dakota 137 99 69 38% warmer 99% warmer
Heating Degree Days 2026 as compared with:
2026 2025 Historic Average 2025 Historic Average
Montana(1) 3,752 4,553 4,523 18% warmer 17% warmer
South Dakota 4,906 5,230 5,601 6% warmer 12% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
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The following summarizes the components of the changes in electric utility margin for the six months ended June 30, 2026 and 2025 (in millions):
Utility Margin 2026 vs. 2025
Utility Margin Items Impacting Net Income
Base rates $ 37.5
Electric margin from the acquisition of the Puget Interests 10.2
Electric transmission revenue 5.4
Non-recoverable Montana electric supply costs 2.8
Retail volumes (4.9)
Montana property tax tracker collections (3.0)
Other 1.5
Change in Utility Margin Items Impacting Net Income 49.5
Utility Margin Items Offset Within Net Income
Production tax credits, offset in income tax expense 4.0
Property and other taxes recovered in revenue, offset in property and other taxes 3.9
Operating expenses recovered in revenue, offset in operating and maintenance expense 3.2
Change in Utility Margin Items Offset Within Net Income 11.1
Increase in Utility Margin(1) $ 60.6
(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.
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NATURAL GAS SEGMENT
We have various classifications of natural gas revenues, defined as follows:
•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Three Months Ended June 30, 2026 Compared with the Three Months Ended June 30, 2025
Revenues Change Dekatherms (Dkt) Avg. Customer Counts
2026 2025 $ % 2026 2025 2026 2025
(in thousands)
Montana $ 19,711 $ 17,968 $ 1,743 9.7 % 2,399 1,949 218,062 187,134
South Dakota 5,776 5,566 210 3.8 576 524 43,202 42,821
Nebraska 4,196 4,523 (327) (7.2) 371 391 37,963 37,907
Residential 29,683 28,057 1,626 5.8 3,346 2,864 299,227 267,862
Montana 12,211 10,499 1,712 16.3 1,548 1,181 30,582 26,613
South Dakota 4,141 3,920 221 5.6 674 593 7,713 7,549
Nebraska 1,994 2,346 (352) (15.0) 272 308 5,162 5,098
Commercial 18,346 16,765 1,581 9.4 2,494 2,082 43,457 39,260
Industrial 844 144 700 486.1 967 17 247 239
Other 268 270 (2) (0.7) 42 38 250 207
Total Retail Gas $ 49,141 $ 45,236 $ 3,905 8.6 % 6,849 5,001 343,181 307,568
Regulatory amortization 5,925 5,189 736 14.2
Transportation, wholesale and other 13,279 12,820 459 3.6
Total Revenues $ 68,345 $ 63,245 $ 5,100 8.1 %
Fuel, purchased supply and direct transmission expense(1) 16,987 15,668 1,319 8.4
Utility Margin(2) $ 51,358 $ 47,577 $ 3,781 7.9 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Heating Degree Days 2026 as compared with:
2026 2025 Historic Average 2025 Historic Average
Montana(1) 1,201 1,093 1,175 10% colder 2% colder
South Dakota 1,344 1,223 1,486 10% colder 10% warmer
Nebraska 871 959 1,134 9% warmer 23% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
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The following summarizes the components of the changes in natural gas utility margin for the three months ended June 30, 2026 and 2025:
Utility Margin 2026 vs. 2025
(in millions)
Utility Margin Items Impacting Net Income
Retail volumes (including a $2.0 million increase due to acquisition of Energy West Operations) $ 3.5
Montana property tax tracker collections 0.4
Natural gas production step down (0.4)
Other 0.6
Change in Utility Margin Items Impacting Net Income 4.1
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes (0.2)
Operating expenses recovered in revenue, offset in operating and maintenance expense (0.1)
Change in Utility Margin Items Offset Within Net Income (0.3)
Increase in Utility Margin(1) $ 3.8
(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 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.
40
Six Months Ended June 30, 2026 Compared with the Six Months Ended June 30, 2025
Revenues Change Dekatherms (Dkt) Avg. Customer Counts
2026 2025 $ % 2026 2025 2026 2025
(in thousands)
Montana $ 67,849 $ 69,386 $ (1,537) (2.2) % 8,591 8,466 218,022 187,066
South Dakota 20,300 21,136 (836) (4.0) 2,167 2,311 43,305 42,941
Nebraska 15,357 17,732 (2,375) (13.4) 1,492 1,773 38,070 38,023
Residential 103,506 108,254 (4,748) (4.4) 12,250 12,550 299,397 268,030
Montana 39,088 37,257 1,831 4.9 5,368 4,813 30,568 26,588
South Dakota 15,895 15,095 800 5.3 2,222 2,203 7,741 7,545
Nebraska 8,500 9,787 (1,287) (13.2) 1,044 1,254 5,182 5,122
Commercial 63,483 62,139 1,344 2.2 8,634 8,270 43,491 39,255
Industrial 1,635 628 1,007 160.4 1,772 86 246 238
Other 792 861 (69) (8.0) 125 132 243 207
Total Retail Gas $ 169,416 $ 171,882 $ (2,466) (1.4) % 22,781 21,038 343,377 307,730
Regulatory amortization 4,924 (4,247) 9,171 215.9
Transportation, wholesale and other 29,521 26,757 2,764 10.3
Total Revenues $ 203,861 $ 194,392 $ 9,469 4.9 %
Fuel, purchased supply and direct transmission expense(1) 72,277 61,113 11,164 18.3
Utility Margin(2) $ 131,584 $ 133,279 $ (1,695) (1.3) %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Heating Degree Days 2026 as compared with:
2026 2025 Historic Average 2025 Historic Average
Montana(1) 3,923 4,590 4,598 15% warmer 15% warmer
South Dakota 4,906 5,230 5,601 6% warmer 12% warmer
Nebraska 3,634 4,368 4,426 17% warmer 18% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
41
The following summarizes the components of the changes in natural gas utility margin for the six months ended June 30, 2026 and 2025:
Utility Margin 2026 vs. 2025
(in millions)
Utility Margin Items Impacting Net Income
Retail volumes (including a $5.2 million increase due to acquisition of Energy West Operations) $ (2.7)
Natural gas production step down (1.1)
Montana property tax tracker collections (0.5)
Other 1.4
Change in Utility Margin Items Impacting Net Income (2.9)
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property tax expense 1.2
Change in Utility Margin Items Offset Within Net Income 1.2
Decrease in Utility Margin(1) $ (1.7)
(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 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.
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LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 18 - Common Stock in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025 for further information regarding these dividend restrictions. As of June 30, 2026, we are in compliance with these provisions.
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.
As of June 30, 2026, our total net liquidity was approximately $339.2 million, including $4.2 million of cash and cash equivalents and $335.0 million of revolving credit facility availability with no letters of credit outstanding.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
Six Months Ended June 30,
2026 2025
Operating Activities
Net income $ 88.5 $ 98.2
Adjustments to reconcile net income to cash provided by operations 149.6 144.1
Changes in working capital 12.4 (22.1)
Other noncurrent assets and liabilities (17.3) (8.6)
Cash Provided by Operating Activities 233.2 211.6
Investing Activities
Property, plant and equipment additions (304.8) (221.0)
Investment in debt & equity securities (1.0) (5.8)
Cash Used in Investing Activities (305.8) (226.8)
Financing Activities
Issuance of long-term debt 375.0 500.0
Line of credit repayments, net (114.0) (103.0)
Dividends on common stock (82.1) (80.7)
Repayments on long-term debt (60.0) (300.0)
Repayment of short-term borrowings (50.0) —
Other financing activities, net (1.9) (3.6)
Cash Provided by Financing Activities 67.0 12.7
Decrease in Cash, Cash Equivalents, and Restricted Cash (5.6) (2.5)
Cash, Cash Equivalents, and Restricted Cash, beginning of period 30.7 29.0
Cash, Cash Equivalents, and Restricted Cash, end of period $ 25.1 $ 26.5
Operating Activities
43
As of June 30, 2026, cash, cash equivalents, and restricted cash were $25.1 million as compared with $30.7 million as of December 31, 2025 and $26.5 million as of June 30, 2025. Cash provided by operating activities totaled $233.2 million for the six months ended June 30, 2026 as compared with $211.6 million during the six months ended June 30, 2025. 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 six months ended June 30, 2026, and are affected by changes in working capital. The increase in cash provided by working capital is primarily due to a decrease in our net cash outflows for energy supply costs, as shown in the table below.
Uncollected energy supply costs (in millions)
Beginning of period End of period Net cash outflows
2025 $ 5.9 $ 28.6 $ (22.7)
2026 $ 44.8 $ 51.9 $ (7.1)
Decrease in net cash outflows $ 15.6
Investing Activities
Cash used in investing activities totaled $305.8 million during the six months ended June 30, 2026, as compared with $226.8 million during the six months ended June 30, 2025. Plant additions during the first six months of 2026 include maintenance additions of approximately $218.7 million and capacity related capital expenditures of $86.1 million. Plant additions during the first six months of 2025 included maintenance additions of approximately $149.4 million and capacity related capital expenditures of approximately $71.6 million.
Financing Activities
Cash provided by financing activities totaled $67.0 million during the six months ended June 30, 2026, as compared with $12.7 million during the six months ended June 30, 2025. During the six months ended June 30, 2026, cash provided by financing activities reflects proceeds from the issuance of debt of $375.0 million, partly offset by net repayments under our revolving lines of credit of $114.0 million, payment of dividends of $82.1 million, repayment of $60.0 million
of South Dakota First Mortgage bonds, and repayment of $50.0 million of the NWE Group Term Loan. During the six months ended June 30, 2025, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $500.0 million, partly offset by repayment of $300.0 million of Montana and South Dakota First Mortgage bonds, net repayments under our revolving lines of credit of $103.0 million and payment of dividends of $80.7 million.
Cash Requirements and Capital Resources
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.
Our material cash requirements are also related to investment in our business through our capital expenditure program. Our estimated capital expenditures are discussed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As of June 30, 2026, there have been no material changes in our estimated capital expenditures. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
Short-term Borrowings
44
For information on our recent short-term borrowings activity, see Note 6 - Financing Activities to the Condensed Consolidated Financial Statements included herein. For further information on our short-term borrowings, see Note 12 - Short-Term Borrowings and Credit Arrangements in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025.
Credit Facilities
Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.
For further information on our credit facilities, see Note 12 - Short-Term Borrowings and Credit Arrangements in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025.
As of June 30, 2026 and 2025, the outstanding balances of our credit facilities were $290.0 million and $310.0 million, respectively. As of July 24, 2026, the availability under our credit facilities was approximately $316.0 million, and there were no letters of credit outstanding.
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities.
For further information on our recent long-term debt activity, See Note 6 - Financing Activities to the Condensed Consolidated Financial Statements included herein.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of July 24, 2026, our current ratings with these agencies are as follows:
Issuer Rating Senior Secured Rating Senior Unsecured Rating Outlook
NorthWestern Energy Group
Fitch(1) BBB - BBB Stable
Moody’s - - - -
S&P BBB - - Positive
NW Corp
Fitch(1) BBB A- BBB+ Stable
Moody’s Baa2 A3 Baa2 Stable
S&P BBB A- - Positive
NWE Public Service
Fitch(1) BBB A- BBB+ Stable
Moody’s Baa2 A3 - Stable
S&P BBB A- - Stable
(1) This Fitch Issuer Rating represents the Issuer Default Rating.
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A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of June 30, 2026.
Total 2026 2027 2028 2029 2030 Thereafter
(in thousands)
Long-term debt(1) $ 3,499,660 $ 45,000 $ 225,000 $ 469,660 $ 33,000 $ 650,000 $ 2,077,000
Finance leases 9,436 854 1,750 1,838 1,930 2,026 1,038
Short-term borrowings 100,000 100,000 — — — — —
Estimated pension and other postretirement obligations(2) 45,620 7,196 10,206 9,806 9,306 9,106 N/A
Qualifying facilities liability(3) 140,896 27,697 56,665 56,534 — — —
Supply and capacity contracts(4) 3,693,058 216,836 368,342 344,818 344,536 315,957 2,102,569
Contractual interest payments on debt(5) 1,597,493 83,364 160,957 149,578 128,449 114,980 960,165
Commitments for significant capital projects(6) 112,226 103,936 7,572 718 — — —
Total Commitments(7) $ 9,198,389 $ 584,883 $ 830,492 $ 1,032,952 $ 517,221 $ 1,092,069 $ 5,140,772
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(1)Represents cash payments for long-term debt and excludes $12.5 million of debt discounts and debt issuance costs, net.
(2)We estimate cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.
(3)One QF requires us to purchase minimum amounts of energy at a price of $130 per MWH through 2028. Our estimated gross contractual obligation related to this QF is approximately $140.9 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $129.7 million.
(4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. 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.
(5)Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 4.99 percent on the outstanding balance through maturity of the facilities.
(6)Represents significant firm purchase commitments for construction of planned capital projects.
(7)The table above excludes potential tax payments related to uncertain tax benefits as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation and asset retirement obligations as the amount and timing of cash payments may be uncertain.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.
We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. This includes the accounting for the following: regulatory assets and liabilities, pension and postretirement benefit plans and income taxes. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025. As of June 30, 2026, there have been no material changes in these policies.
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