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What changed in NorthWestern Energy Group, Inc.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of NorthWestern Energy Group, Inc.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+333 added−187 removedSource: 10-K (2026-02-12) vs 10-K (2025-02-13)

Top changes in NorthWestern Energy Group, Inc.'s 2025 10-K

333 paragraphs added · 187 removed · 135 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

72 edited+15 added−12 removed39 unchanged
Biggest changeThe following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions): Year Ended December 31, 2024 2023 Income Before Income Taxes $ 214.7 $ 201.6 Income tax calculated at federal statutory rate 45.1 21.0 % 42.4 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) (21.0) (9.8) (3.2) (1.6) Production tax credits (11.1) (5.2) (10.3) (5.1) Gas repairs safe harbor method change (7.0) (3.3) — — Amortization of excess deferred income taxes (2.9) (1.4) (2.2) (1.1) Prior year permanent return to accrual adjustments (0.4) (0.2) — — Plant and depreciation of flow through items 9.4 4.4 6.6 3.3 Unregulated Tax Cuts and Jobs Act excess deferred income taxes — — (3.4) (1.7) Reduction to previously claimed alternative minimum tax credit — — 3.2 1.6 Other, net 1.2 0.7 (0.3) (0.1) (54.5) (25.4) (34.9) (17.3) Income Tax (Benefit) Expense $ (9.4) (4.4) % $ 7.5 3.7 % 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. 50 ELECTRIC OPERATIONS We have various classifications of electric revenues, defined as follows: • Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms. • Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin.
Biggest changeThe following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions): Year Ended December 31, 2025 2024 (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 % State income tax, net of federal provision (1.5) (0.8) 0.4 0.2 Tax Credits Production tax credits (5.9) (3.2) (11.1) (5.2) 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) AFUDC, net (1.3) (0.7) (2.6) (1.2) Plant and depreciation of flow through items 16.8 9.0 9.4 4.4 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) 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. 62 ELECTRIC OPERATIONS We have various classifications of electric revenues, defined as follows: • Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms. • Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin.
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).
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).
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses. 52 NATURAL GAS OPERATIONS We have various classifications of natural gas revenues, defined as follows: • Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms. • Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin.
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses. 64 NATURAL GAS OPERATIONS We have various classifications of natural gas revenues, defined as follows: • Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms. • Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin.
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 16 - Common Stock to the Consolidated Financial Statements for more information regarding these dividend restrictions.
For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 18 - Common Stock to the Consolidated Financial Statements for more information regarding these dividend restrictions.
We have assumed an average interest rate of 5.71 percent on the outstanding balance through maturity of the credit facilities. (6) Represents significant firm purchase commitments for construction of planned capital projects. (7) The table above excludes potential tax payments related to unrecognized tax benefits as they are not practicable to estimate.
We have assumed an average interest rate of 5.07 percent on the outstanding balance through maturity of the credit facilities. (6) Represents significant firm purchase commitments for construction of planned capital projects. (7) The table above excludes potential tax payments related to unrecognized tax benefits as they are not practicable to estimate.
In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets. While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 4 - Regulatory Assets and Liabilities to the Consolidated Financial Statements for further discussion.
In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets. While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 6 - Regulatory Assets and Liabilities to the Consolidated Financial Statements for further discussion.
Our reported costs of providing pension and other postretirement benefits, as described in Note 14 - Employee Benefit Plans to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms.
Our reported costs of providing pension and other postretirement benefits, as described in Note 16 - Employee Benefit Plans to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms.
For further information on our long-term debt, see Note 11 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein. We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
For further information on our long-term debt, see Note 13 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein. We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
The amortization of these amounts are offset in retail revenue. • Transmission: Reflects transmission revenues regulated by the FERC. • Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense. Year Ended December 31, 2024 Compared with Year Ended December 31, 2023 Revenues Change MWHs Avg.
The amortization of these amounts are offset in retail revenue. • Transmission: Reflects transmission revenues regulated by the FERC. • Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense. Year Ended December 31, 2025 Compared with Year Ended December 31, 2024 Revenues Change MWHs Avg.
Contractual Obligations and Other Commitments We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2024.
Contractual Obligations and Other Commitments We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2025.
As costs are incurred under the AOC, the surety bonds will be reduced. 59 CRITICAL ACCOUNTING ESTIMATES Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP.
As costs are incurred under the AOC, the surety bonds will be reduced. 71 CRITICAL ACCOUNTING ESTIMATES Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP.
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, 2024, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $215.0 million, short-term borrowings of $100.0 million, and net issuances under our revolving lines of credit of $95.0 million, partly offset by payment of dividends of $158.6 million and repayment of $100.0 million of Montana First Mortgage Bonds.
The amortization of these amounts are offset in retail revenue. • Wholesale: Primarily represents transportation and storage for others. Year Ended December 31, 2024 Compared with Year Ended December 31, 2023 Revenues Change Dekatherms Avg.
The amortization of these amounts are offset in retail revenue. • Wholesale: Primarily represents transportation and storage for others. Year Ended December 31, 2025 Compared with Year Ended December 31, 2024 Revenues Change Dekatherms Avg.
Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $15.8 million and $15.7 million as of December 31, 2024 and 2023, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ.
Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $13.5 million and $15.8 million as of December 31, 2025 and 2024, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ.
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.
We are taking a proactive and pragmatic approach to replacing these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications. Approximately $2.3 billion, or 70 percent, of our capital forecast above is projected to be spent on our distribution and transmission system.
Long-term Debt and Equity We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $300.0 million of long-term debt maturing in 2025, which we intend to refinance.
Long-term Debt and Equity We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $105.0 million of long-term debt maturing in 2026, which we intend to refinance.
For further information regarding equity, see Note 16 - Common Stock to the Consolidated Financial Statements included herein.
For further information regarding equity, see Note 18 - Common Stock to the Consolidated Financial Statements included herein.
Based on this analysis as of December 31, 2024, our discount rate for both NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan is 5.50 percent and 5.60 percent, respectively. 60 In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions.
Based on this analysis as of December 31, 2025, our discount rate for both NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan is 5.20 percent and 5.65 percent, respectively. 72 In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions.
Additionally, the table above excludes reserves for environmental remediation (See Note 18 - Commitments and Contingencies ) and AROs (see Note 6 - Asset Retirement Obligations ) as the amount and timing of cash payments may be uncertain.
Additionally, the table above excludes reserves for environmental remediation (See Note 20 - Commitments and Contingencies ) and AROs (see Note 8 - Asset Retirement Obligations ) as the amount and timing of cash payments may be uncertain.
See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements.
See additional discussion in Note 20 - Commitments and Contingencies to the Consolidated Financial Statements.
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.
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) 61 percent for the same period of 2024.
See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin. 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.
See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin. Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in South Dakota, and lower industrial demand.
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.
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.
(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.
See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
As of February 7, 2025, our current ratings with these agencies are as follows: 57 Issuer Rating Senior Secured Rating Senior Unsecured Rating Outlook NorthWestern Energy Group Fitch (1) BBB - BBB Stable Moody’s - - - - S&P BBB - - Stable NW Corp Fitch (1) BBB A- BBB+ Stable Moody’s Baa2 A3 Baa2 Stable S&P BBB A- - Stable 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.
As of February 6, 2026, our current ratings with these agencies are as follows: 69 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.
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).
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).
(3) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $118 to $130 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $229.0 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $205.8 million.
(3) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $124 to $130 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $168.6 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $152.8 million.
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.
We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As of December 31, 2025, we have not recorded any unrecognized tax benefits.
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. 46 OVERALL CONSOLIDATED RESULTS Year Ended December 31, 2024 Compared with Year Ended December 31, 2023 Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023, an increase of $30.0 million.
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. 58 OVERALL CONSOLIDATED RESULTS Year Ended December 31, 2025 Compared with Year Ended December 31, 2024 Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024, a decrease of $43.0 million.
Our expected long-term rate of return on assets assumptions are 4.58% percent and 6.17% percent on the NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan, respectively, for 2025.
Our expected long-term rate of return on assets assumptions are 4.96% percent and 6.3% percent on the NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan, respectively, for 2026.
See Note 12 - Income Taxes to the Consolidated Financial Statements for further discussion. 61 NEW ACCOUNTING STANDARDS See Note 2 - Significant Accounting Policies , to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards. 62
See Note 14 - Income Taxes to the Consolidated Financial Statements for further discussion. 73 NEW ACCOUNTING STANDARDS See Note 2 - Significant Accounting Policies , to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards. 74
Cost Sensitivity The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands): Actuarial Assumption Change in Assumption Impact on Pension Cost Impact on Projected Benefit Obligation Discount rate increase 0.25 % $ 195 $ (11,443) Discount rate decrease (0.25) % 1,171 11,973 Rate of return on plan assets increase 0.25 % (982) N/A Rate of return on plan assets decrease (0.25) % 982 N/A Accounting Treatment We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets.
Cost Sensitivity The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands): Actuarial Assumption Change in Assumption Impact on Pension Cost Impact on Projected Benefit Obligation Discount rate increase 0.25 % $ 127 $ (6,446) Discount rate decrease (0.25) % 25 6,787 Rate of return on plan assets increase 0.25 % (798) N/A Rate of return on plan assets decrease (0.25) % 798 N/A Accounting Treatment We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets.
Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to be $531 million in 2025, $549 million in 2026, and $557 million in 2027.
Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to be $683 million in 2026, $643 million in 2027, and $667 million in 2028.
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.
See "Non-GAAP Financial Measure" above. Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in South Dakota, and lower industrial demand.
Primary components of the change include the following (in millions): Operating Expenses 2024 vs. 2023 Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income Depreciation expense due to plant additions and higher depreciation rates $ 17.1 Labor and benefits (1) 7.9 Insurance expense, primarily due to increased wildfire risk premiums 7.7 Property and other taxes not recoverable within trackers 4.4 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) Other (2.3) Change in Items Impacting Net Income 41.0 Operating Expenses Offset Within Net Income Property and other taxes recovered in trackers, offset in revenue 6.4 Pension and other postretirement benefits, offset in other income (1) 4.8 Operating and maintenance expenses recovered in trackers, offset in revenue 2.4 Deferred compensation, offset in other income 0.7 Change in Items Offset Within Net Income 14.3 Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 55.3 (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.
Primary components of the change include the following (in millions): Operating Expenses 2025 vs. 2024 Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income Non-cash regulatory disallowance of certain YCGS capital costs $ 30.9 Depreciation expense due to plant additions and higher depreciation rates 21.9 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) 7.6 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) Non-cash impairment of alternative energy storage investment (1.7) Other 3.0 Change in Items Impacting Net Income 101.9 Operating Expenses Offset Within Net Income Property and other taxes recovered in trackers, offset in revenue 16.3 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) (2.9) Change in Items Offset Within Net Income 16.3 Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 118.2 (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.
Cash provided by operating activities totaled $406.8 million for the year ended December 31, 2024 as compared with $489.2 million for the year ended December 31, 2023.
Cash provided by operating activities totaled $394.5 million for the year ended December 31, 2025 as compared with $406.8 million for the year ended December 31, 2024.
The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2024 (in millions): Amount outstanding at year end $ 413.0 Daily average amount outstanding $ 237.1 Maximum amount outstanding $ 413.0 Minimum amount outstanding $ 69.0 As of February 7, 2025, availability under our revolving credit facilities was approximately $233.0 million, and there were no letters of credit outstanding.
The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2025 (in millions): Amount outstanding at year end $ 404.0 Daily average amount outstanding $ 291.0 Maximum amount outstanding $ 415.0 Minimum amount outstanding $ 36.0 As of February 6, 2026, availability under our revolving credit facilities was approximately $229.0 million, and there were no letters of credit outstanding.
Cash Flows The following table summarizes our consolidated cash flows (in millions): Year Ended December 31, 2024 2023 Operating Activities Net income $ 224.1 $ 194.1 Non-cash adjustments to net income 213.5 210.1 Changes in working capital (18.9) 115.6 Other noncurrent assets and liabilities (11.9) (30.6) Cash Provided by Operating Activities 406.8 489.2 Investing Activities Property, plant and equipment additions (549.3) (566.9) Other investing activity (5.2) (3.9) Cash Used in Investing Activities (554.5) (570.8) Financing Activities Proceeds from issuance of common stock, net — 73.6 Issuance of long-term debt 215.0 300.0 Dividends on common stock (158.6) (154.1) Line of credit borrowings (repayments), net 95.0 (132.0) Financing costs (1.1) (4.3) Treasury stock activity 1.2 1.1 Cash Provided by Financing Activities 151.5 84.3 Net Increase in Cash, Cash Equivalents, and Restricted Cash $ 3.8 $ 2.7 Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 25.2 $ 22.5 Cash, Cash Equivalents, and Restricted Cash, end of period $ 29.0 $ 25.2 55 Operating Activities As of December 31, 2024, cash, cash equivalents, and restricted cash were $29.0 million as compared with $25.2 million as of December 31, 2023.
Cash Flows The following table summarizes our consolidated cash flows (in millions): Year Ended December 31, 2025 2024 Operating Activities Net income $ 181.1 $ 224.1 Non-cash adjustments to net income 289.0 213.5 Changes in working capital (61.4) (18.9) Other noncurrent assets and liabilities (14.2) (11.9) Cash Provided by Operating Activities 394.5 406.8 Investing Activities Property, plant and equipment additions (524.5) (549.3) Acquisition of Energy West Operations (35.9) — Other investing activity (10.3) (5.2) Cash Used in Investing Activities (570.7) (554.5) Financing Activities 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 (repayments) borrowings , net (9.0) 95.0 Financing costs (4.5) (1.1) Treasury stock activity 0.7 1.2 Cash Provided by Financing Activities 177.9 151.5 Net Increase in Cash, Cash Equivalents, and Restricted Cash $ 1.7 $ 3.8 Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 29.0 $ 25.2 Cash, Cash Equivalents, and Restricted Cash, end of period $ 30.7 $ 29.0 67 Operating Activities As of December 31, 2025, cash, cash equivalents, and restricted cash were $30.7 million as compared with $29.0 million as of December 31, 2024.
As of December 31, 2024, our total consolidated net liquidity was approximately $191.3 million, including $4.3 million of cash and $187.0 million of revolving credit facility availability with no letters of credit outstanding.
As of December 31, 2025, our total consolidated net liquidity was approximately $229.8 million, including $8.8 million of cash and $221.0 million of revolving credit facility availability with no letters of credit outstanding.
Consolidated utility margin in 2024 was $1,080.1 million as compared with $1,001.9 million in 2023, an increase of $78.2 million, or 7.8 percent. 47 Primary components of the change in utility margin include the following (in millions): Utility Margin 2024 vs. 2023 Utility Margin Items Impacting Net Income Base rates $ 62.4 Electric transmission revenue due to market conditions and rates 18.6 Montana interim rates (subject to refund) 4.8 Montana natural gas transportation 2.3 Montana property tax tracker collections 1.1 Non-recoverable Montana electric supply costs (7.9) QF liability adjustment (4.2) Natural gas retail volumes (4.0) Electric retail volumes (0.9) Other (3.0) Change in Utility Margin Impacting Net Income 69.2 Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 6.4 Operating expenses recovered in revenue, offset in operating and maintenance expense 2.4 Production tax credits, offset in income tax expense 0.2 Change in Items Offset Within Net Income 9.0 Increase in Consolidated Utility Margin (1) $ 78.2 (1) Non-GAAP financial measure.
Consolidated utility margin in 2025 was $1,200.8 million as compared with $1,080.1 million in 2024, an increase of $120.7 million, or 11.2 percent. 59 Primary components of the change in utility margin include the following (in millions): Utility Margin 2025 vs. 2024 Utility Margin Items Impacting Net Income Base Rates $ 93.3 Electric transmission revenue due to market conditions and rates 14.0 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 (7.3) Other 0.1 Change in Utility Margin Impacting Net Income 97.0 Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 16.3 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 Increase in Consolidated Utility Margin (1) $ 120.7 (1) Non-GAAP financial measure.
Heating Degree Days 2024 as compared with: 2024 2023 Historic Average 2023 Historic Average Montana (1) 7,265 7,478 7,791 3% warmer 7% warmer South Dakota 6,501 7,665 7,724 15% warmer 16% warmer Nebraska 5,241 5,893 6,085 11% warmer 14% warmer (1) Montana electric and natural gas heating degree days may differ due to differences in service territory. 53 The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2024 and 2023 (in millions): Utility Margin 2024 vs. 2023 Utility Margin Items Impacting Net Income Base rates 11.4 Montana natural gas transportation 2.3 Montana interim rates (subject to refund) 2.0 Retail volumes (4.0) Montana property tax tracker collections (0.1) Other (2.1) Change in Utility Margin Impacting Net Income 9.5 Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 3.0 Operating expenses recovered in revenue, offset in operating and maintenance expense 0.7 Change in Items Offset Within Net Income 3.7 Increase in Utility Margin (1) $ 13.2 (1) Non-GAAP financial measure.
Heating Degree Days 2025 as compared with: 2025 2024 Historic Average 2024 Historic Average Montana (1) 7,207 7,265 7,697 1% warmer 6% 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. 65 The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2025 and 2024 (in millions): Utility Margin 2025 vs. 2024 Utility Margin Items Impacting Net Income Base rates $ 21.5 Montana natural gas transportation 4.8 Retail volumes ($4.2 million due to acquisition of Energy West Operations) 2.0 Montana property tax tracker collections (3.4) Other 0.2 Change in Utility Margin Impacting Net Income 25.1 Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 3.6 Operating expenses recovered in revenue, offset in operating and maintenance expense (0.3) Change in Items Offset Within Net Income 3.3 Increase in Utility Margin (1) $ 28.4 (1) Non-GAAP financial measure.
Net under-collected supply costs (in millions) Beginning of year End of year Net cash inflows 2023 $ 115.4 $ 7.8 $ 107.6 2024 $ 7.8 $ 5.9 $ 1.9 Improvement in annual net cash inflows $ (105.7) Investing Activities Cash used in investing activities totaled $554.5 million during the year ended December 31, 2024, as compared with $570.8 million during 2023.
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) Increase in net cash outflows $ (40.8) Investing Activities Cash used in investing activities totaled $570.7 million during the year ended December 31, 2025, as compared with $554.5 million during 2024.
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 . 58 (5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate.
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 . 70 (5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate.
Plant additions during 2024 include capital maintenance additions of approximately $324.0 million and capacity related capital expenditures of approximately $225.3 million. Plant additions during 2023 included capital maintenance additions of approximately $321.9 million and capacity related capital expenditures of approximately $245.0 million.
Plant additions during 2025 include capital maintenance additions of approximately $372.7 million and capacity related capital expenditures of approximately $151.8 million. Plant additions during 2024 included capital maintenance additions of approximately $324.0 million and capacity related capital expenditures of approximately $225.3 million.
This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC. 49 Consolidated other income in 2024 was $23.0 million, as compared with $15.8 million in 2023.
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 lower capitalization of AFUDC. Consolidated other income in 2025 was $12.1 million, as compared with $23.0 million in 2024.
See "Non-GAAP Financial Measure" above. Year Ended December 31, 2024 2023 Change % Change (in millions) Utility Margin Electric $ 871.1 $ 806.1 $ 65.0 8.1 % Natural Gas 209.0 195.8 13.2 6.7 Total Utility Margin (1) $ 1,080.1 $ 1,001.9 $ 78.2 7.8 % (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
See "Non-GAAP Financial Measure" above. Year Ended December 31, 2025 2024 Change % Change (in millions) Utility Margin Electric $ 963.4 $ 871.1 $ 92.3 10.6 % Natural Gas 237.4 209.0 28.4 13.6 Total Utility Margin (1) $ 1,200.8 $ 1,080.1 $ 120.7 11.2 % (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Electric Natural Gas Total 2024 2023 2024 2023 2024 2023 (in millions) Reconciliation of gross margin to utility margin: Operating Revenues $ 1,200.7 $ 1,068.8 $ 313.2 $ 353.3 $ 1,513.9 $ 1,422.1 Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 329.6 262.7 104.2 157.5 433.8 420.2 Less: Operating and maintenance 171.7 166.0 56.1 54.5 227.8 220.5 Less: Property and other taxes 126.5 120.3 37.4 34.3 163.9 154.6 Less: Depreciation and depletion 190.0 174.1 37.6 36.4 227.6 210.5 Gross Margin 382.9 345.7 77.9 70.6 460.8 416.3 Operating and maintenance 171.7 166.0 56.1 54.5 227.8 220.5 Property and other taxes 126.5 120.3 37.4 34.3 163.9 154.6 Depreciation and depletion 190.0 174.1 37.6 36.4 227.6 210.5 Utility Margin (1) $ 871.1 $ 806.1 $ 209.0 $ 195.8 $ 1,080.1 $ 1,001.9 (1) Non-GAAP financial measure.
Electric Natural Gas Total 2025 2024 2025 2024 2025 2024 (in millions) Reconciliation of gross margin to utility margin: Operating Revenues $ 1,270.0 $ 1,200.7 $ 340.6 $ 313.2 $ 1,610.6 $ 1,513.9 Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 306.6 329.6 103.2 104.2 409.8 433.8 Less: Operating and maintenance 224.4 171.7 60.5 56.1 284.9 227.8 Less: Property and other taxes 140.9 126.5 41.2 37.4 182.1 163.9 Less: Depreciation and depletion 208.6 190.0 40.9 37.6 249.5 227.6 Gross Margin 389.5 382.9 94.8 77.9 484.3 460.8 Operating and maintenance 224.4 171.7 60.5 56.1 284.9 227.8 Property and other taxes 140.9 126.5 41.2 37.4 182.1 163.9 Depreciation and depletion 208.6 190.0 40.9 37.6 249.5 227.6 Utility Margin (1) $ 963.4 $ 871.1 $ 237.4 $ 209.0 $ 1,200.8 $ 1,080.1 (1) Non-GAAP financial measure.
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.
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.
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.
This change is offset within this table as it does not affect our operating expenses. Consolidated operating income in 2024 was $323.3 million as compared with $300.5 million in 2023. 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 change is offset within this table as it does not affect our operating expenses. Consolidated operating income in 2025 was $325.8 million as compared with $323.3 million in 2024. This increase was primarily due to new rates, electric transmission revenue, natural gas transportation revenues, and retail volumes.
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.
The actual amount of capital 68 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.
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.
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.
The 2023-2024 contract year was the last year of the contract that contains variable pricing terms. 48 Year Ended December 31, 2024 2023 Change % Change (in millions) Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Operating and maintenance $ 227.8 $ 220.5 $ 7.3 3.3 % Administrative and general 137.4 117.3 20.1 17.1 Property and other taxes 163.9 153.1 10.8 7.1 Depreciation and depletion 227.6 210.5 17.1 8.1 Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 756.7 $ 701.4 $ 55.3 7.9 % Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $756.7 million in 2024, as compared with $701.4 million in 2023.
Year Ended December 31, 2025 2024 Change % Change (in millions) Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Operating and maintenance $ 284.9 $ 227.8 $ 57.1 25.1 % Administrative and general 158.2 137.4 20.8 15.1 Property and other taxes 182.3 163.9 18.4 11.2 Depreciation and depletion 249.5 227.6 21.9 9.6 Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 874.9 $ 756.7 $ 118.2 15.6 % 60 Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $874.9 million in 2025, as compared with $756.7 million in 2024.
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 10 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein.
For further information on our credit facilities, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein.
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 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.
Cooling Degree Days 2024 as compared with: 2024 2023 Historic Average 2023 Historic Average Montana 485 441 448 10% warmer 8% warmer South Dakota 778 1,035 752 25% cooler 3% warmer Heating Degree Days 2024 as compared with: 2024 2023 Historic Average 2023 Historic Average Montana (1) 7,033 7,237 7,554 3% warmer 7% warmer South Dakota 6,501 7,665 7,724 15% warmer 16% warmer (1) Montana electric and natural gas heating degree days may differ due to differences in service territory. 51 The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2024 and 2023 (in millions): Utility Margin 2024 vs. 2023 Utility Margin Items Impacting Net Income Base rates $ 51.0 Electric transmission revenue due to market conditions and rates 18.6 Montana interim rates (subject to refund) 2.8 Montana property tax tracker collections 1.2 Non-recoverable Montana electric supply costs (7.9) QF liability adjustment (4.2) Retail volumes (0.9) Other (0.9) Change in Utility Margin Items Impacting Net Income 59.7 Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 3.4 Operating expenses recovered in revenue, offset in operating and maintenance expense 1.7 Production tax credits, offset in income tax expense 0.2 Change in Items Offset Within Net Income 5.3 Increase in Utility Margin (1) $ 65.0 (1) Non-GAAP financial measure.
The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2025 and 2024 (in millions): Utility Margin 2025 vs. 2024 Utility Margin Items Impacting Net Income Base rates $ 71.8 Electric transmission revenue due to market conditions and rates 14.0 Retail volumes 4.3 Montana property tax tracker collections (10.8) Non-recoverable Montana electric supply costs (7.3) Other (0.1) Change in Utility Margin Items Impacting Net Income 71.9 Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 12.7 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 Increase in Utility Margin (1) $ 92.3 (1) Non-GAAP financial measure.
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.
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.
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).
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.
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.
In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers. Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment.
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.
Based on the significant NOL income tax position we have, we anticipate paying minimal cash for income taxes into 2028.
We currently estimate our effective tax rate will range between 14.0 percent to 18.0 percent in 2026. Based on the significant NOL income tax position we have, we anticipate paying minimal cash for income taxes into 2029.
Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic 56 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 For further information on our short-term borrowings, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein.
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.
Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential customers.
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 13.0 percent to 17.0 percent in 2025.
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).
Customer Counts 2024 2023 $ % 2024 2023 2024 2023 (in thousands) Montana $ 110,215 $ 136,097 (25,882) (19.0) % 13,749 14,008 185,644 183,810 South Dakota 26,884 36,638 (9,754) (26.6) 2,709 3,179 42,577 42,053 Nebraska 21,205 35,539 (14,334) (40.3) 2,294 2,581 37,958 37,793 Residential 158,304 208,274 (49,970) (24.0) 18,752 19,768 266,179 263,656 Montana 59,925 73,721 (13,796) (18.7) 7,782 8,036 26,164 25,725 South Dakota 18,069 25,869 (7,800) (30.2) 2,791 3,169 7,383 7,232 Nebraska 11,432 22,114 (10,682) (48.3) 1,664 1,916 5,056 5,023 Commercial 89,426 121,704 (32,278) (26.5) 12,237 13,121 38,603 37,980 Industrial 1,041 1,392 (351) (25.2) 147 157 237 232 Other 1,352 1,681 (329) (19.6) 207 209 197 190 Total Retail Gas $ 250,123 $ 333,051 $ (82,928) (24.9) % 31,343 33,255 305,216 302,058 Regulatory amortization 19,017 (25,012) 44,029 (176.0) Wholesale and other 44,057 45,271 (1,214) (2.7) Total Revenues $ 313,197 $ 353,310 $ (40,113) (11.4) % Fuel, purchased supply and direct transmission expense (1) 104,238 157,507 (53,269) (33.8) Utility Margin (2) $ 208,959 $ 195,803 $ 13,156 6.7 % (1) Exclusive of depreciation and depletion.
Customer Counts 2025 2024 $ % 2025 2024 2025 2024 (in thousands) Montana $ 120,830 $ 110,215 10,615 9.6 % 14,339 13,749 201,728 185,644 South Dakota 28,948 26,884 2,064 7.7 3,032 2,709 42,952 42,577 Nebraska 25,733 21,205 4,528 21.4 2,414 2,294 37,970 37,958 Residential 175,511 158,304 17,207 10.9 19,785 18,752 282,650 266,179 Montana 68,722 59,925 8,797 14.7 8,691 7,782 28,380 26,164 South Dakota 21,574 18,069 3,505 19.4 3,303 2,791 7,586 7,383 Nebraska 13,784 11,432 2,352 20.6 1,738 1,664 5,114 5,056 Commercial 104,080 89,426 14,654 16.4 13,732 12,237 41,080 38,603 Industrial 2,439 1,041 1,398 134.3 2,140 147 241 237 Other 1,350 1,352 (2) (0.1) 197 207 218 197 Total Retail Gas $ 283,380 $ 250,123 $ 33,257 13.3 % 35,854 31,343 324,189 305,216 Regulatory amortization (305) 19,017 (19,322) (101.6) Transportation, wholesale and other 57,528 44,057 13,471 30.6 Total Revenues $ 340,603 $ 313,197 $ 27,406 8.8 % Fuel, purchased supply and direct transmission expense (1) 103,186 104,238 (1,052) (1.0) Utility Margin (2) $ 237,417 $ 208,959 $ 28,458 13.6 % (1) Exclusive of depreciation and depletion.
These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense. Consolidated gross margin in 2024 was $460.8 million as compared with $416.3 million in 2023, an increase of $44.5 million or 10.7 percent.
These were partly offset by higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. Consolidated gross margin in 2025 was $484.3 million as compared with $460.8 million in 2024, an increase of $23.5 million or 5.1 percent. This increase was primarily due to higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes.
Financing Activities Cash provided by financing activities totaled $151.5 million during the year ended December 31, 2024 as compared with $84.3 million during the year ended December 31, 2023.
As discussed above in the “Significant Infrastructure Investments and Initiatives” section, our capital expenditures are forecasted to be $683.0 million in 2026. Financing Activities Cash provided by financing activities totaled $177.9 million during the year ended December 31, 2025 as compared with $151.5 million during the year ended December 31, 2024.
Short-term Borrowings For further information on our short-term borrowings, see Note 10 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein. NorthWestern Energy Group has $100.0 million of short-term borrowings maturing in 2025, which we intend to refinance.
NorthWestern Energy Group has $150.0 million of short-term borrowings maturing in 2026, which we intend to refinance. Credit Facilities Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities.
Total 2025 2026 2027 2028 2029 Thereafter (in thousands) Long-term debt (1) $ 3,007,660 $ 300,000 $ 105,000 $ — $ 592,660 $ 33,000 $ 1,977,000 Finance leases 5,461 3,596 1,865 — — — — Short-term borrowings 100,000 100,000 — — — — — Estimated pension and other postretirement obligations (2) 50,310 11,310 9,750 9,750 9,750 9,750 N/A QF liability (3) 228,952 60,360 55,393 56,665 42,400 14,134 — Supply and capacity contracts (4) 4,228,637 345,821 365,202 350,381 349,347 350,201 2,467,685 Contractual interest payments on debt (5) 1,650,442 133,927 122,884 120,847 118,780 89,359 1,064,645 Commitments for significant capital projects (6) 66,837 57,975 8,862 — — — $ — Total Commitments (7) $ 9,338,299 $ 1,012,989 $ 668,956 $ 537,643 $ 1,112,937 $ 496,444 $ 5,509,330 (1) Represents cash payments for long-term debt and excludes $12.4 million of debt discounts and debt issuance costs, net.
Total 2026 2027 2028 2029 2030 Thereafter (in thousands) Long-term debt (1) $ 3,298,660 $ 105,000 $ — $ 583,660 $ 33,000 $ 650,000 $ 1,927,000 Finance leases 1,865 1,865 — — — — — Short-term borrowings 150,000 150,000 — — — — — Estimated pension and other postretirement obligations (2) 51,067 12,643 10,206 9,806 9,306 9,106 N/A QF liability (3) 168,592 55,393 56,665 42,400 14,134 — — Supply and capacity contracts (4) 3,883,865 424,471 343,663 340,135 341,470 316,667 2,117,459 Contractual interest payments on debt (5) 1,515,754 142,813 137,144 140,276 109,172 96,182 890,167 Commitments for significant capital projects (6) 51,111 51,111 — — — — $ — Total Commitments (7) $ 9,120,914 $ 943,296 $ 547,678 $ 1,116,277 $ 507,082 $ 1,071,955 $ 4,934,626 (1) Represents cash payments for long-term debt and excludes $12.7 million of debt discounts and debt issuance costs, net.
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.
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.
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses. 54 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.
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. 66 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.
Customer Counts 2024 2023 $ % 2024 2023 2024 2023 (in thousands) Montana $ 398,790 $ 408,341 $ (9,551) (2.3) % 2,804 2,795 328,420 322,489 South Dakota 70,012 67,888 2,124 3.1 557 603 51,467 51,261 Residential 468,802 476,229 (7,427) (1.6) 3,361 3,398 379,887 373,750 Montana 408,977 431,357 (22,380) (5.2) 3,197 3,238 75,878 74,438 South Dakota 111,813 103,194 8,619 8.4 1,093 1,101 13,084 12,973 Commercial 520,790 534,551 (13,761) (2.6) 4,290 4,339 88,962 87,411 Industrial 46,637 45,958 679 1.5 2,924 2,660 80 79 Other 32,811 32,756 55 0.2 146 134 6,544 6,443 Total Retail Electric $ 1,069,040 $ 1,089,494 $ (20,454) (1.9) % 10,721 10,531 475,473 467,683 Regulatory amortization 24,908 (105,608) 130,516 (123.6) Transmission 97,052 78,436 18,616 23.7 Wholesale and Other 9,701 6,511 3,190 49.0 Total Revenues $ 1,200,701 $ 1,068,833 $ 131,868 12.3 % Fuel, purchased supply and direct transmission expense (1) 329,578 262,755 66,823 25.4 Utility Margin (2) $ 871,123 $ 806,078 $ 65,045 8.1 % (1) Exclusive of depreciation and depletion.
Customer Counts 2025 2024 $ % 2025 2024 2025 2024 (in thousands) Montana $ 406,643 $ 398,790 $ 7,853 2.0 % 2,834 2,804 334,011 328,420 South Dakota 77,894 70,012 7,882 11.3 583 557 51,787 51,467 Residential 484,537 468,802 15,735 3.4 3,417 3,361 385,798 379,887 Montana 408,530 408,977 (447) (0.1) 3,216 3,197 77,305 75,878 South Dakota 120,108 111,813 8,295 7.4 1,061 1,093 13,190 13,084 Commercial 528,638 520,790 7,848 1.5 4,277 4,290 90,495 88,962 Industrial 43,128 46,637 (3,509) (7.5) 2,789 2,924 80 80 Other (1) 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 Regulatory amortization 58,265 24,908 33,357 133.9 Transmission 111,024 97,052 13,972 14.4 Wholesale and Other 9,854 9,701 153 1.6 Total Revenues $ 1,269,956 $ 1,200,701 $ 69,255 5.8 % Fuel, purchased supply and direct transmission expense (2) 306,569 329,578 (23,009) (7.0) Utility Margin (3) $ 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.
Removed
Beginning in 2021, we began installing automated metering infrastructure in Montana.
Added
In 2025, we completed the installation, which began in 2021, of automated metering infrastructure in Montana. 57 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.
Removed
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. 45 RESULTS OF OPERATIONS Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

35 edited+149 added−12 removed122 unchanged
Biggest changeRegulatory, contractual and legal limitations, as well as subsidiary capital requirements, affect the ability of a subsidiary to pay dividends up to the parent entity and thereby could restrict or influence our ability or decision to pay dividends on our common stock, which could adversely affect our stock price. 36
Biggest changeRegulatory, contractual and legal limitations, as well as subsidiary capital requirements, affect the ability of a subsidiary to pay dividends up to the parent entity and thereby could restrict or influence our ability or decision to pay dividends on our common stock, which could adversely affect our stock price. 37 Risks Related to the Merger Because the exchange ratio is fixed and because the market prices of NorthWestern Common Stock and Black Hills Common Stock will fluctuate, NorthWestern shareholders cannot be certain of the market value of the Merger consideration they will receive in the Merger or the difference between the market value of the Merger consideration they will receive in the Merger and the market value of NorthWestern Common Stock immediately prior to the Merger.
In order to operate the Colstrip facility through its currently identified depreciable life of 2042, it will be necessary to identify and contract for coal supply subsequent to expiration of our current contract. Moreover, the suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us.
In order to operate the Colstrip facility through its currently identified depreciable life of 2042, it will be necessary to identify and contract for coal supply subsequent to expiration of our current contract in 2033. Moreover, the suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us.
Environmental advocacy groups, certain investors and other third parties oppose the operation of fossil-fuel generation, expressing concerns about the environmental and climate-related impacts from fossil fuels. This opposition may increase in scope and frequency depending on a number of variables, including the course of Federal and State laws and environmental regulations and the financial resources devoted to opposition efforts.
Environmental advocacy groups, certain investors and other third parties oppose the operation of fossil-fuel generation, expressing concerns about the environmental-related impacts from fossil fuels. This opposition may increase in scope and frequency depending on a number of variables, including the course of Federal and State laws and environmental regulations and the financial resources devoted to opposition efforts.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. In addition, we may not recover all costs related to mitigating these physical and financial risks. Our results of operations may be impacted by disruptions to fuel supply or the electric grid that are beyond our control.
To the extent the frequency of extreme weather 31 events increases, this could increase our cost of providing service. In addition, we may not recover all costs related to mitigating these physical and financial risks. Our results of operations may be impacted by disruptions to fuel supply or the electric grid that are beyond our control.
Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in our credit ratings may lead to additional collateral posting requirements. We are a participant in the energy markets, including the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation.
Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in our credit ratings may lead to additional collateral posting requirements. 36 We are a participant in the energy markets, including the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation.
Extreme weather conditions, especially those of prolonged duration, create high energy demand on our own and/or other systems and increase the risk we may be unable to reliably serve customers, causing brownouts and/or blackouts of our electric 30 systems, and loss of gas supply.
Extreme weather conditions, especially those of prolonged duration, create high energy demand on our own and/or other systems and increase the risk we may be unable to reliably serve customers, causing brownouts and/or blackouts of our electric systems, and loss of gas supply.
As we expand our energy generation asset mix, the ability to integrate renewable technologies into our operations and maintain reliability and affordability is a risk. The intermittency of renewables remains a critical challenge particularly as cost-efficient energy storage is still in development.
As we expand our energy generation asset mix, the ability to integrate renewable technologies into our operations and maintain reliability and affordability is a risk. The intermittency of renewables remains a critical challenge particularly as cost- 35 efficient energy storage is still in development.
Should these economic conditions and issues continue, we could have difficulty completing the operational activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations. 32 Failure to attract and retain an appropriately qualified workforce could affect our operations.
Should these economic conditions and issues continue, we could have difficulty completing the operational activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations. 33 Failure to attract and retain an appropriately qualified workforce could affect our operations.
Finally, the requirement to procure power from these QF sources may impact our transmission system and require additional transmission facilities to be developed in order to integrate these resources, which also can impact overall customer bills. 28 Operational Risks Our electric and natural gas operations involve numerous activities that may result in accidents, fires, system outages and other operating risks and costs that are unique to our industry.
Finally, the requirement to procure power from these QF sources may impact our transmission system and require additional transmission facilities to be developed in order to integrate these resources, which also can impact overall customer bills. 29 Operational Risks Our electric and natural gas operations involve numerous activities that may result in accidents, fires, system outages and other operating risks and costs that are unique to our industry.
The advancement of artificial intelligence and large language models has given rise to additional vulnerabilities and potential entry points for cyber crime. Our assets and the information technology systems on which they depend could be direct targets of, or indirectly affected by, cyber attacks and other disruptive activities, including those that impact third party facilities that are interconnected to us.
The advancement of artificial intelligence and large language models has given rise to additional vulnerabilities and potential entry points for cyber crime. Our assets and the information technology systems on which they depend are direct targets of, or are indirectly affected by, cyber attacks and other disruptive activities, including those that impact third party facilities that are interconnected to us.
A significant number of base-load generation facilities, which may also serve to meet peak requirements, in the state and region have been retired or are scheduled to be retired in the next five to ten years. 29 This includes Colstrip Units 1 and 2, representing 614 MWs of generation on a capacity basis, which ceased operations in January 2020.
A significant number of base-load generation facilities, which may also serve to meet peak requirements, in the state and region have been retired or are scheduled to be retired in the next five to ten years. 30 This includes Colstrip Units 1 and 2, representing 614 MWs of generation on a capacity basis, which ceased operations in January 2020.
If these promulgated GHG and 26 MATS Rules are implemented and enforced as currently written, they may affect our ability to reliably serve our customers and we could be subject to significant additional compliance costs that would affect our future financial position, results of operations, and cash flows if such costs are not recovered through regulated rates.
If these promulgated GHG and MATS Rules are implemented and enforced as currently written, they may affect our ability to reliably serve our customers and we could be subject to significant additional compliance costs that would affect our future financial position, results of operations, and cash flows if such costs are 27 not recovered through regulated rates.
Our operations are subject to laws and regulations imposed by federal, state and local government authorities regarding energy policy, permitting/siting for energy projects, climate change, the environment, air and water quality, GHG emissions, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations.
Our operations are subject to laws and regulations imposed by federal, state and local government authorities regarding energy policy, permitting/siting for energy projects, the environment, air and water quality, GHG emissions, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations.
Future negotiation of these collective bargaining agreements could lead to work stoppages or other disruptions to our operations, which could adversely affect our financial condition and results of operations. 33 Liquidity and Financial Risks We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.
Future negotiation of these collective bargaining agreements could lead to work stoppages or other disruptions to our operations, which could adversely affect our financial condition and results of operations. 34 Liquidity and Financial Risks We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.
These events could adversely affect our results of operations, financial position and cash flows. 31 Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations.
These events could adversely affect our results of operations, financial position and cash flows. 32 Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations.
As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, potential tariffs, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases.
As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, potential tariffs on imported products, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases.
Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates and therefore may impact our results of operations, cash flows and financial position. 35 We are subject to counterparty credit risk.
Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates and therefore may impact our results of operations, cash flows and financial position.
To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs or collect them in a timely manner, which could adversely impact our results of operations and liquidity.
We are subject to potential unfavorable litigation, and state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs or collect them in a timely manner, which could adversely impact our results of operations and liquidity.
We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time-to-time. For example, we have $300 million of secured long-term debt and $100 million of short-term borrowings maturing in 2025.
We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time-to-time. For example, we have $105 million of secured long-term debt and $150 million of short-term borrowings maturing in 2026.
Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our ability to manage our operational requirements to serve our customers, and ultimately adversely affect our results of operations and liquidity.
Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events, could adversely affect our ability to manage our operational requirements to serve our customers, and ultimately adversely affect our results of operations and liquidity.
Differing schedules and regulatory practices between our state commissions and FERC expose us to the risk that we may not fully recover our costs due to timing of filings, specific calculations and issues such as cost allocation methodologies. Thus, the rates we are allowed to charge may or may not match our costs at any given time.
Differing schedules and regulatory practices between our state commissions and FERC expose us to the risk that we may not fully recover our costs due to timing of filings, specific calculations and issues such as cost allocation methodologies.
We enter into transactions to buy and sell power, natural gas, and transmission service. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. Certain of these contracts may result in the receipt of, or posting of, collateral with counterparties.
We are subject to counterparty credit risk. We enter into transactions to buy and sell power, natural gas, and transmission service. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform.
Such technologies could also result in further declines in commodity prices or demand for delivered energy. Decreasing use per customer (driven, for example, by appliance and lighting efficiency) and the availability of cost-effective distributed generation, put downward pressure on load growth.
Such technologies could also result in further declines in commodity prices or demand for delivered energy. Decreasing use per customer (driven, for example, by appliance and lighting efficiency) and the availability of cost-effective distributed generation, put downward pressure on load growth. There can be no assurance that load growth from large-load customers, such as data centers, will be realized.
There can be no assurance that laws, regulations and policies will not be changed in ways that have a material adverse effect on our operations, financial condition, results of operations, and cash flows.
There can be no assurance that laws, regulations and policies will not be changed in ways that have a material adverse effect on our operations, financial condition, results of operations, and cash flows. We are subject to extensive and changing energy, and environmental laws and regulations with which compliance may be difficult and costly.
In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered.
In 2025, the MPSC disallowed $30.9 million of capital costs that they deemed were not prudently incurred related to the construction of YCGS. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered.
The natural gas system has capacity constraints that expose us to risks to be able to deliver natural gas during periods of peak demand. Fluctuations in actual weather conditions, generation availability, transmission constraints, and generation reserve margins may all have an impact on market prices for energy and capacity and the electricity consumption of our customers on a given day.
Fluctuations in actual weather conditions, generation availability, transmission constraints, and generation reserve margins may all have an impact on market prices for energy and capacity and the electricity consumption of our customers on a given day.
In particular, as described more fully below in Note 18 - Commitments and Contingencies , we are a co-owner of Colstrip Unit 4. The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042.
In particular, as described more fully below in Note 20 - Commitments and Contingencies to the Consolidated Financial Statements included herein, we are a co-owner of the coal-fired Colstrip Units 3 & 4 generating facility. The remaining depreciable life of our investments in Colstrip Units 3 & 4 is through 2042.
During recent periods, we have had a significant under-collection of these costs impacting our results of operations and cash flows. In addition, our natural gas system serves both retail customers and the needs of natural gas fired electric generation.
During recent periods, we have had a significant under-collection of these costs impacting our results of operations and cash flows.
We must comply with established reliability standards and requirements including Critical Infrastructure Protection Reliability Standards, which apply to NERC functions. NERC reliability standards protect the nations’ bulk power system against potential disruptions from cyber and physical security breaches. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards.
Increased risks of regulatory penalties could negatively impact our business. We must comply with established reliability standards and requirements including Critical Infrastructure Protection Reliability Standards, which apply to NERC functions. NERC reliability standards protect the nations’ bulk power system against potential disruptions from cyber and physical security breaches.
Our equipment has been alleged to be involved in igniting wildfires although none have had a material adverse effect on our financial condition or results of operations.
Fires alleged to have been caused by our equipment potentially expose us to significant penalties and/or damage awards based on claims of strict liability, negligence, gross negligence, inverse condemnation, nuisance, trespass and others. Our equipment has been alleged to be involved in igniting wildfires although none have had a material adverse effect on our financial condition or results of operations.
We are generally obligated under federal law to purchase power from certain QF projects, regardless of current load demand, availability of lower cost generation resources, transmission availability or market prices.
Federally mandated purchases of power from QFs, and integration of power generated from those projects in our system, may increase costs to our customers and decrease system reliability, limit our ability to make generation investments and adversely affect our business. 28 We are generally obligated under federal law to purchase power from certain QF projects, regardless of current load demand, availability of lower cost generation resources, transmission availability or market prices.
Any damage caused as a result of fires could negatively impact our financial condition, results of operations or cash flows. The physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events.
Any damage caused as a result of fires could negatively impact our financial condition, results of operations or cash flows.
Penalties for the most severe violations can reach nearly $1.2 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.
If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results. Additionally, the Pipeline and Hazardous Materials Safety Administration, Occupational Safety and Health Administration and other federal or state agencies have penalty authority.
Additionally, the Pipeline and Hazardous Materials Safety Administration, Occupational Safety and Health Administration and other federal or state agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties.
In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
In forested areas, this issue has been heightened by mountain pine beetle and other infestations weakening and killing trees in our service territory. Worsening conditions as a result of climate change may increase the likelihood and magnitude of damages that may be caused by fires.
In forested areas, this issue has been heightened by mountain pine beetle and other infestations weakening and killing trees in our service territory. Residential and commercial development into the wildland-urban interface has also led to an increasing trend in the degree of destruction from wildfires.
Removed
Regulatory, Legislative and Legal Risks Our profitability depends on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We are subject to potential unfavorable litigation, and state and federal regulatory outcomes.
Added
Summary Risk Factors The following is a summary of some of the risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flows in the future. You should read this summary together with the more detailed description of each risk factor contained below.
Removed
We are subject to extensive and changing energy, and environmental laws and regulations, including legislative, judicial, and regulatory responses to climate change, with which compliance may be difficult and costly.
Added
Regulatory, Legislative and Legal Risks • Our ability to recover prudently incurred costs and earn authorized returns depends on regulatory outcomes; • Changes in laws, energy policies, or regulatory frameworks may increase costs or limit growth; • Environmental compliance requirements may require significant investments, which may or may not be recoverable, or early retirements of certain generating facilities; • Exposure to litigation may delay projects or restrict operations; • Reliability and safety compliance failures could result in substantial penalties; and • Mandated QF purchases may increase costs and limit investment flexibility.
Removed
Recently promulgated federal rules under the Biden Administration will potentially impose requirements on fossil fuel assets, but the Trump Administration is evaluating energy-related regulations impacting reliability and affordability. It is currently unclear whether the promulgated GHG or MATS Rules will be enforced, revised, or repealed.
Added
Operational Risks • Utility operations involve hazards that may cause outages, injuries, or environmental harm; • Increasing fire risk may lead to significant claims or penalties; • System constraints may limit reliable service or access to lower-cost supply; • Reliance on market purchases exposes us to price volatility and counterparty risks; • Weather variability impacts loads, supply, hydrology, and financial performance; • Fuel supply disruptions may increase costs or reduce generation availability; • Decreasing customer usage may reduce revenues and increase system costs; • Cyber and physical security threats may disrupt operations or compromise data; • Supply-chain delays, inflation, and labor shortages may impair operations; and • Workforce challenges may affect safety, operations, and project execution.
Removed
See discussion related to YCGS below in “Management’s Discussion and Analysis – Significant Trends and Regulation.” Adverse litigation outcomes could cause us to delay or terminate projects, increase costs and impact our ability to service our customers.
Added
Liquidity and Financial Risks • Insurance coverage may be insufficient for certain risks; • Capital projects and acquisitions carry permitting, cost, and recovery risks; • Access to capital markets may be constrained by interest rates or volatility; • Energy transition policies and technologies present financial and operational risks; • Credit rating downgrades would increase borrowing costs and collateral needs; • QF minimum energy obligations may expose us to higher replacement power costs; • Changes in tax laws may affect earnings and cash flows; • Counterparty defaults may impact liquidity; • Pension and benefit plan performance may increase costs; and • We rely on subsidiary dividends subject to regulatory constraints.
Removed
On January 16, 2023 we entered into an agreement with Avista Corporation pursuant to which it will transfer to us its 15% project share in Units 3 and 4 on December 31, 2025.
Added
Risks Related to the Merger • The fixed exchange ratio creates variability in merger consideration value; • Required approvals may delay, condition, or prevent merger completion; • Deal protections and termination fees may discourage alternatives; • Merger uncertainty may impact stock price, ratings, and operations; and • Merger-related litigation may cause delays or additional costs.
Removed
On July 30, 2024, we entered into an agreement with Puget Sound Energy pursuant to which it will transfer to us its 25% project share in Units 3 and 4 on December 31, 2025. Increased risks of regulatory penalties could negatively impact our business.
Added
Risks Relating to the Combined Company Following Completion of the Merger • Integration challenges may delay or reduce anticipated synergies; • NorthWestern shareholders will have reduced ownership and voting influence; • Significant indebtedness may increase refinancing and interest-rate risks; 26 • Goodwill created in the merger may be subject to impairment; • Tax attribute limitations may reduce expected NOL benefits; • Future dividends are not assured; and • Issuance of new Black Hills Common Stock could negatively impact the Black Hills Common Stock price Regulatory, Legislative and Legal Risks Our profitability depends on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.
Removed
If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. 27 Federally mandated purchases of power from QFs, and integration of power generated from those projects in our system, may increase costs to our customers and decrease system reliability, limit our ability to make generation investments and adversely affect our business.
Added
We are required to have FERC approved cost based rates or FERC approved contract rates in order to sell electricity in the wholesale market. Absent these rates, we may be subject to refund of some or all of the revenue collected. Thus, the rates we are allowed to charge may or may not match our costs at any given time.
Removed
Residential and commercial development into the wildland-urban interface has also led to an increasing trend in the degree of destruction from wildfires. Fires alleged to have been caused by our equipment potentially expose us to significant penalties and/or damage awards based on claims of strict liability, negligence, gross negligence, inverse condemnation, nuisance, trespass and others.
Added
In 2024, the EPA released final rules that will potentially impose requirements on fossil fuel assets, however, in 2025, the EPA issued multiple Notices of Proposed Rulemaking that would remove these additional requirements on fossil fuel assets. There is no mandated timeline for final action on these rules.
Removed
Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate.
Added
In 2023, due to lawsuits filed by the Montana Environmental Information Center and Sierra Club alleging that the environmental analysis conducted by the MDEQ prior to the issuance of the YCGS air quality construction permit was inadequate, the Montana District Court issued an order vacating our YCGS air quality permit pending the MDEQ addressing the identified deficiencies.
Removed
For example, during the Biden Administration, the EPA indicated that it was "evaluating additional opportunities" to reduce GHG emissions from existing power plants.
Added
While we eventually were successful in staying this order, and the air quality permit was subsequently reinstated, due to this litigation we paused construction for approximately three months, causing us to incur substantial additional costs. Adverse litigation outcomes, such as this, could cause us to delay or terminate projects, increase costs and impact our ability to service our customers.
Removed
Although the Trump Administration has directed federal executive agencies to 34 review all energy related regulations implicating reliability and affordability, it is not yet clear what the impact will be on existing regulations or future legislation or regulations affecting GHG.
Added
The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Penalties for the most severe violations can reach nearly $1.2 million per violation, per day.
Removed
To the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory costs, CO 2 taxes or imposed costs, we may be adversely impacted.
Added
As described more fully below in Note 5 - Regulatory Matters to the Consolidated Financial Statements included herein, while the MPSC has suspended the sharing component of the Montana PCCAM beginning on February 1, 2026, pending further review, there can be no assurances that a final order will be issued eliminating this sharing component.
Added
In addition, our natural gas system serves both retail customers and the needs of natural gas fired electric generation. The natural gas system has capacity constraints that expose us to risks to be able to deliver natural gas during periods of peak demand.
Added
Certain of these contracts may result in the receipt of, or posting of, collateral with counterparties.
Added
The exchange ratio in the Merger is fixed and will not be adjusted in the event of any change in the stock prices of NorthWestern or Black Hills prior to the Merger.
Added
There may be a significant amount of time between the dates when the shareholders of NorthWestern or Black Hills vote on the Merger Agreement at the special meeting of each company and the date when the Merger is completed.
Added
The absolute and relative prices of shares of NorthWestern Common Stock and Black Hills Common Stock may vary significantly between the date the Merger Agreement, the date hereof, the date of the meetings and the date of the completion of the Merger.
Added
These variations may be caused by, among other things, changes in the businesses, operations, results or prospects of NorthWestern or Black Hills, market expectations of the likelihood that the Merger will be completed and the timing of completion, the prospects of post-merger operations, general market and economic conditions and other factors.
Added
In addition, it is impossible to predict accurately the market price of the Black Hills Common Stock to be received by NorthWestern shareholders after the completion of the Merger.
Added
Accordingly, the prices of NorthWestern Common Stock and Black Hills Common Stock on the date hereof and on the date of the meetings may not be indicative of their prices immediately prior to completion of the Merger and the price of the combined company common stock after the Merger is completed.
Added
The ability of NorthWestern and Black Hills to complete the Merger is subject to various closing conditions, including the receipt of approval of NorthWestern and Black Hills stockholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect NorthWestern or Black Hills or cause the Merger to be abandoned.
Added
Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of NorthWestern common stock or other securities and the future business and financial results of NorthWestern. To complete the Merger, NorthWestern and Black Hills stockholders must vote to approve a number of proposals related to the Merger and the Merger Agreement.
Added
Further, the Merger is subject to the satisfaction or waiver of certain closing conditions, including, (1) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (the HSR Act), and approval from the FERC and certain state regulatory commissions, in each case on such terms and conditions that would not result in a material adverse effect on the combined company; (2) the absence of any court order or regulatory injunction prohibiting completion of the Merger; (3) the authorization for listing of shares of Black Hills Common Stock to be issued in connection with the Merger on the New York Stock Exchange (NYSE) or other mutually-agreed stock exchange; (4) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (5) compliance by each party in all material respects with its covenants under the Merger Agreement; (6) the absence of a material adverse effect on each party; and (7) receipt by each party of an opinion relating to the anticipated tax-free treatment of the Merger.
Added
If the foregoing conditions are not satisfied or waived, one or both of NorthWestern or Black Hills would not be required to complete the Merger. NorthWestern and Black Hills have not yet obtained stockholder approval or all of the regulatory consents and approvals required to complete the Merger.
Added
Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger.
Added
NorthWestern and Black Hills will be unable to complete the Merger until the waiting period under the HSR Act has expired or been terminated and the required governmental approvals have been received. Regulatory authorities may impose certain requirements or obligations as conditions for their approval.
Added
The Merger Agreement may require NorthWestern and/or Black Hills to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither NorthWestern nor Black Hills will be obligated to complete the Merger.
Added
There can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.
Added
Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest.
Added
In addition, in some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed.
Added
NorthWestern or Black Hills may not prevail and may incur significant costs in defending or settling any action under the antitrust laws. 38 The special meetings at which the NorthWestern stockholders and the Black Hills stockholders will vote on the transactions contemplated by the Merger Agreement may take place before all regulatory approvals have been obtained and, in cases where they have not been obtained, before the terms of any conditions to obtain such regulatory approvals that may be imposed are known.
Added
As a result, if stockholder approval of the transactions contemplated by the Merger Agreement is obtained at such meetings, NorthWestern may make decisions after the meetings to waive a condition or approve certain actions required to obtain the necessary approvals without seeking further stockholder approval. Such actions could have an adverse effect on the combined company.
Added
If NorthWestern and Black Hills are unable to complete the Merger, or there is a significant delay in completing the Merger, NorthWestern would be subject to a number of risks, including the following: • NorthWestern would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies and future cost savings; • the attention of management of NorthWestern may have been diverted to the Merger rather than to its own operations and the pursuit of other opportunities that could have been beneficial to NorthWestern; • the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with the combined company; • NorthWestern will have been subject to certain restrictions on the conduct of its business, which may prevent NorthWestern from making certain acquisitions or dispositions or pursuing certain business opportunities while the Merger is pending; • the trading price of NorthWestern Common Stock or other securities may decline to the extent that the current market prices reflect a market assumption that the Merger will be completed; and • the parties may be liable for damages to one another, or have to pay a termination fee, under the Merger Agreement.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeThrough the year ending on December 31, 2024, there have been no cybersecurity incidents that have had a material impact, or any impact, on our business strategy, operations, or financial condition. Risk Management and Strategy We utilize a comprehensive, defense in depth approach to cybersecurity risk, which helps us to continually assess, identify and manage enterprise-wide material cybersecurity risks.
Biggest changeThrough the year ending on December 31, 2025, there have been no cybersecurity incidents that have had a material impact, or any impact, on our business strategy, operations, or financial condition. Risk Management and Strategy We utilize a comprehensive, defense in depth approach to cybersecurity risk, which helps us to continually assess, identify and manage enterprise-wide material cybersecurity risks.
Collectively, our cyber security team holds numerous industry certifications related to cybersecurity and have experience in desktop support, networking, application administration and programming. 37
Collectively, our cyber security team holds numerous industry certifications related to cybersecurity and have experience in desktop support, networking, application administration and programming. 48

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeSubstantially all of our South Dakota and Nebraska electric and natural gas assets are subject to the lien of our South Dakota Mortgage Bond indenture.
Biggest changeSubstantially all of our NW Corp Montana electric and natural gas assets are subject to the lien of NW Corp's Montana First Mortgage Bond indenture. Substantially all of our South Dakota and Nebraska electric and natural gas assets are subject to the lien of NWE Public Service's South Dakota Mortgage Bond indenture.
ITEM 2. PROPERTIES Our material properties include electric generating facilities, electric transmission and distribution lines, and natural gas production, transmission and distribution lines, which are described in Item 1 under Electric Operations and Natural Gas Operations. Substantially all of our Montana electric and natural gas assets are subject to the lien of our Montana First Mortgage Bond indenture.
ITEM 2. PROPERTIES Our material properties include electric generating facilities, electric transmission and distribution lines, and natural gas production, transmission and distribution lines, which are described in Item 1 under Electric Operations and Natural Gas Operations.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. LEGAL PROCEEDINGS We discuss details of our legal proceedings in Note 18 - Commitments and Contingencies , to the Consolidated Financial Statements. Some of this information is about costs or potential costs that may be material to our financial results.
Biggest changeITEM 3. LEGAL PROCEEDINGS We discuss details of our legal proceedings in Note 20 - Commitments and Contingencies , to the Consolidated Financial Statements. Some of this information is about costs or potential costs that may be material to our financial results.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock, which is traded under the ticker symbol NWE, is listed on the Nasdaq Stock Market. As of February 7, 2025, there were approximately 1,201 common stockholders of record.
Biggest changeITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock, which is traded under the ticker symbol NWE, is listed on the Nasdaq Stock Market. As of February 6, 2026, there were approximately 1,268 common stockholders of record.
Added
The following table contains monthly information about our repurchase of equity securities for the three months ended December 31, 2025: Period Total Number of Shares Purchased (1) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs October 1, 2025 - October 31, 2025 — $ — — — November 1, 2025 - November 30, 2025 — — — — December 1, 2025 - December 31, 2025 3,129 67.87 — — Total 3,129 $ 67.87 — — (1) Shares were acquired under the share withholding provisions of the Amended and Restated Equity Compensation Plan for payment of taxes associated with the vesting of equity compensation awards.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

18 edited+33 added−28 removed11 unchanged
Biggest changeWe are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system. 41 HOW WE PERFORMED IN 2024 COMPARED TO OUR 2023 RESULTS Year Ended December 31, 2024 vs. 2023 Income Before Income Taxes Income Tax Benefit (Expense) Net Income (in millions) December 31, 2023 $ 201.6 $ (7.5) $ 194.1 Variance in revenue and fuel, purchased supply, and direct transmission expense (1) items impacting net income: Base rates 62.4 (15.8) 46.6 Electric transmission revenue 18.6 (4.7) 13.9 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) 0.2 (0.2) — Non-recoverable Montana electric supply costs (7.9) 2.0 (5.9) QF liability adjustment (4.2) 1.1 (3.1) Natural gas retail volumes (4.0) 1.0 (3.0) Electric retail volumes (0.9) 0.2 (0.7) Other (3.2) 0.8 (2.4) Variance in expense items (2) impacting net income: Operating, maintenance, and administrative (19.4) 4.9 (14.5) Depreciation (17.1) 4.3 (12.8) Interest expense (17.1) 4.3 (12.8) Property and other taxes not recoverable within trackers (4.4) 1.1 (3.3) Release of unrecognized tax benefits (inclusive of related interest previously accrued) — 17.8 17.8 Gas repairs safe harbor method change — 7.0 7.0 Other 1.9 (4.8) (2.9) December 31, 2024 $ 214.7 $ 9.4 $ 224.1 Change in Net Income $ 30.0 (1) Exclusive of depreciation and depletion shown separately below.
Biggest changeWe are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system. 52 HOW WE PERFORMED IN 2025 COMPARED TO OUR 2024 RESULTS Year Ended December 31, 2025 vs. 2024 Income Before Income Taxes Income Tax Benefit (Expense) Net Income (in millions) December 31, 2024 $ 214.7 $ 9.4 $ 224.1 Variance in revenue and fuel, purchased supply, and direct transmission expense (1) items impacting net income: Base Rates 93.3 (23.6) 69.7 Electric transmission revenue 14.0 (3.5) 10.5 Production tax credits, offset within income tax benefit (expense) 6.6 (6.6) — Montana natural gas transportation 4.8 (1.2) 3.6 Electric retail volumes 4.3 (1.1) 3.2 Natural gas retail volumes 2.0 (0.5) 1.5 Montana property tax tracker collections (14.2) 3.6 (10.6) Non-recoverable Montana electric supply costs (7.3) 1.8 (5.5) Other 0.1 0.0 0.1 Variance in expense items (2) impacting net income: Operating, maintenance, and administrative (37.7) 9.5 (28.2) Non-cash regulatory disallowance of certain YCGS capital costs (30.9) 7.8 (23.1) Depreciation (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 - current year — 7.4 7.4 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) December 31, 2025 $ 187.6 $ (6.5) $ 181.1 Change in Net Income $ (43.0) (1) Exclusive of depreciation and depletion shown separately below.
Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2024, 2023 and 2022.
Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2025, 2024 and 2023.
This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 20 - Segment and Related Information , to the Consolidated Financial Statements.
This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 22 - Segment and Related Information , to the Consolidated Financial Statements.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023, on both a consolidated basis and on a segment basis.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2025 compared to the year ended December 31, 2024, on both a consolidated basis and on a segment basis.
For a discussion of our financial results and cash flows for the year ended December 31, 2023 compared with the year ended December 31, 2022, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023 .
For a discussion of our financial results and cash flows for the year ended December 31, 2024 compared with the year ended December 31, 2023, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 .
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 787,000 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park.
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.
In 2024, approximately 58 percent of our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 41 percent for the total U.S. electric power industry. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment.
In 2025, approximately 52 percent of our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 41 percent for the total U.S. electric power industry. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment.
(2) Excluding fuel, purchased supply, and direct transmission expense. Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023.
(2) Excluding fuel, purchased supply, and direct transmission expense. Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024.
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.
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.
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.
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.
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.
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.
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.
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.
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.
For us, wind generation is a close second and continues to grow. While utility-scale solar energy has not been a significant portion of our energy mix to date, we expect solar to further evolve along with advances in energy storage.
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. 40 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.
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.
Following is a discussion of our strategy and significant trends. 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.
See Note 3 - Pending Merger with Black Hills Corporation to the Consolidated Financial Statements included herein for additional information regarding this pending Merger. 51 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.
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. 44 SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions): Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments.
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. 56 SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions): Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments.
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.
Resources and regulatory mechanisms to be utilized for serving these requests are pending further evaluation and regulatory considerations. 54 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.
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.
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.
Removed
We expect solar to further evolve along with advances in energy storage.
Added
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.
Removed
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.
Added
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.
Removed
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. 42 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.
Added
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.
Removed
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.
Added
Under the provisions of ASC Topic 805, which requires the identification of an acquirer in a business combination, Black Hills is the accounting acquirer.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
Based on the procedural schedule developed by the MPSC, a hearing on our rate review request is scheduled to commence on April 22, 2025.
Added
These were partly offset by higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. 53 SIGNIFICANT TRENDS AND REGULATION Montana Rate Review In July 2024, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates.
Removed
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.
Added
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.
Removed
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 $95.6 million.
Added
The details of this final order are set forth below: Returns, Capital Structure & Revenue Increase Resulting From Final Order ($ in millions) Electric Natural Gas Return on Equity (ROE) 9.65 % 9.60 % Equity Capital Structure 47.84 % 47.84 % Base Rates $ 105.5 $ 18.0 PCCAM (1)(2) (94.5) n/a Property Tax (tracker base adjustment) (1) (1.8) 0.1 Total Revenue Increase Through Final Order $ 9.2 $ 18.1 (1) These items are flow-through costs.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
See Note 1 8 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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. 43 EPA Rules In April 2024, the EPA released GHG Rules for existing coal-fired facilities and new coal and natural gas-fired facilities as well as MATS Rules.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
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. 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.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Removed
We collaborated with Grid United, the Montana Department of Commerce, and other regional utilities on the successful GRIP grant application.
Added
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.
Removed
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.
Added
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.
Removed
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.
Added
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.
Added
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.
Added
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.
Added
Montana Wildfire Risk Mitigation The Montana Legislature approved House Bill 490 in April 2025.
Added
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, 55 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.
Added
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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeWe are also exposed to counterparty credit risk related to providing transmission service to our customers under our OATT and under gas transportation agreements. We have risk management policies in place to limit our transactions to high quality counterparties. We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk.
Biggest changeWe are also exposed to counterparty credit risk related to providing transmission service to our customers under our OATT, under gas transportation agreements, and contracts for electricity sales in wholesale energy markets. We have risk management policies in place to limit our transactions to high quality counterparties.
As a regulated utility, our exposure to market risk caused by changes in commodity prices is mitigated because these commodity costs are included in our Montana, South Dakota and Nebraska cost tracking mechanisms and are recoverable from customers subject to a regulatory review for prudency and, in Montana, a sharing mechanism.
As a regulated utility, our exposure to market risk caused by changes in commodity prices is mitigated because these commodity costs are included in our Montana, South Dakota and Nebraska cost tracking mechanisms and are recoverable from customers subject to a regulatory review for prudency.
As of December 31, 2024, we had $413.0 million in borrowings under our revolving credit facilities. A 1.0 percent increase in interest rates would increase our annual interest expense by approximately $4.1 million.
As of December 31, 2025, we had $404.0 million in borrowings under our revolving credit facilities. A 1.0 percent increase in interest rates would increase our annual interest expense by approximately $4.0 million.
This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.
We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

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