Open the filing on EDGARNorthWestern Energy Group, Inc.d/b/a NorthWestern Energy3010 W. 69 StreetSioux Falls, SD 57108www.northwesternenergy.com
NorthWestern Energy Reports Third Quarter 2026 Financial Results
- Third Quarter 2026 Diluted GAAP EPS of $0.50, compared to $0.62 in 2025.
- Third Quarter 2026 Adjusted Diluted Non-GAAP EPS of $0.58, compared to $0.79 in 2025.
- Affirms 2026 earnings guidance range of $3.68 to $3.83 per diluted share.
- Affirms record $683 million capital plan for 2026 and 4% to 6% long-term EPS and rate base growth rate.
- Announces $0.67 per share quarterly dividend - payable December 1, 2026.
BUTTE, MT /
SIOUX FALLS, SD - November 4, 2026 - NorthWestern Energy Group, Inc. d/b/a NorthWestern Energy (Nasdaq: NWE) reported financial results for the Third Quarter of 2026. Net income for the period was $30.7 million, or $0.50 per diluted share, as compared with net income of $38.2 million, or $0.62 per diluted share, for the same period in 2025. This decrease was primarily due to $6.1 million of net loss associated with our additional ownership interests in Colstrip Units 3 and 4, depreciation expense, and interest expense. These were offset in part by lower non-recoverable Montana electric supply costs, retail volumes, transmission revenue, and lower merger-related costs.
NorthWestern’s Third Quarter 2026 non-GAAP net income and diluted earnings per share were $35.6 million and $0.58, respectively, compared to $48.4 million and $0.79 in 2025. See “Adjusted Non-GAAP Earnings” and “Non-GAAP Financial Measures” sections below for more information on these measures.
"The third quarter was a busy and productive one for NorthWestern,” said President and CEO Brian Bird. “We continued to execute on our core business and remain focused on delivering long-term value for our customers, communities, and shareholders. Although the costs associated with our incremental ownership in Colstrip have created a temporary earnings headwind, this strategic decision helps ensure reliable energy for our customers and support economic development in Montana. Looking ahead, we are excited about the prospect of completing our merger with Black Hills and beginning the next chapter for our combined company, subject to final, satisfactory approval from the Montana Public Service Commission which is expected to consider the merger prior to November 12, 2026.”
TRANSACTION UPDATE
On August 18, 2025, we entered into a Merger Agreement with Black Hills Corporation (Black Hills) and a wholly owned subsidiary of Black Hills. The Merger Agreement provides for an all-stock merger of equals between NorthWestern and Black Hills upon the terms and subject to the conditions set forth therein. The new corporate name selected for the resulting parent company of the combined corporate group is Bright Horizon Energy Corporation (Bright Horizon).
In April 2026, shareholders of each company voted to approve the Merger and the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act expired, permitting consummation of the transaction.
In May 2026, the Federal Energy Regulatory Commission (FERC) and the Nebraska Public Service Commission (NPSC) each approved the Merger. In June 2026, the South Dakota Public Utilities Commission (SDPUC) approved the merger.
We filed an application with the Montana Public Service Commission (MPSC) for approval of the Merger, and in April 2026, we reached a settlement agreement with certain key intervenors in Montana, which is subject to the approval by the MPSC. In May 2026, a hearing with the MPSC was held and we await their final order.
We anticipate the transaction closing by year-end 2026, subject to the satisfaction or waiver of certain closing conditions.
During the three and nine months ended September 30, 2026, we have incurred $3.2 million and $9.9 million, respectively, of merger-related costs, which are included in our Administrative and general expenses.
FINANCIAL OUTLOOK
Affirming 2026 Guidance and Long-Term Growth Rates
As noted above, we anticipate completing the merger with Black Hills by year-end 2026. The financial guidance and long-term outlook presented below reflect NorthWestern Energy on a standalone basis. Upon completion of the merger, NorthWestern’s standalone guidance and outlook will no longer apply or be indicative of the combined company’s expected results.
We are affirming our 2026 non-GAAP earnings guidance of $3.68 - $3.83 per diluted share. This guidance is based upon, but not limited to, the following major assumptions:
- Normal weather in our service territories;
- Excludes costs related to the pending merger with Black Hills;
- Approval of the Power Cost and Credit Adjustment Mechanism (PCCAM) waiver and power prices sufficient to recover operating expense from incremental Avista and Puget Colstrip interests;
- An effective income tax rate of approximately 14 percent to 18 percent; and
- Diluted average shares outstanding of approximately 61.8 million.
We are affirming our long-term diluted earnings per share growth guidance of 4% to 6%, based on our 2024 adjusted diluted non-GAAP EPS baseline of $3.40.
Additionally, we are affirming our $3.2 billion capital investment plan for 2026-2030, which is expected to support rate base growth of 4% to 6% from our 2024 base year of approximately $5.4 billion.
We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt issuances, and future rate increases. In order to fund South Dakota generation investment, equity issuances are expected beginning in 2027.
Dividend Declared
NorthWestern Energy Group’s Board of Directors has declared a quarterly common stock dividend of $0.67 per share, payable on December 1, 2026, to shareholders of record as of November 17, 2026. As previously disclosed in NorthWestern’s 2025 Annual Report issued in March 2026, this dividend was expected to be payable on December 31, 2026, to shareholders of record on December 15, 2026. The Board revised the record and payment dates in connection with the pending merger transaction and the dividend coordination provisions of the merger agreement.
If the merger receives final, satisfactory regulatory approval and is completed before the November 17, 2026 record date, each share of NorthWestern common stock will be converted into 0.98 shares of Black Hills common stock, with cash paid in lieu of any fractional shares, pursuant to the merger agreement, and Black Hills will be renamed Bright Horizon Energy Corporation. In that event, former NorthWestern shareholders who become shareholders of Bright Horizon as a result of the merger and are shareholders of Bright Horizon on Bright Horizon's November 17, 2026 record date will be eligible to receive the dividend of $0.703 per Bright Horizon share from Bright Horizon that was declared by Black Hills on October 28, 2026. If the merger is completed after the November 17, 2026 record date, NorthWestern shareholders of record on that date will receive the NorthWestern dividend of $0.67 per share payable on December 1, 2026.
NorthWestern remains committed to its targeted dividend payout ratio of 60% to 70% over the long term. This target only reflects NorthWestern on a standalone basis through completion of the pending merger with Black Hills.
Additional information regarding this release can be found in the earnings presentation at https://www.northwesternenergy.com/investors/earnings.
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COMPANY UPDATES
Montana Rate Review
In December 2025, the MPSC issued a final order approving our partial electric settlement agreement. The final order also suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. The ultimate resolution regarding the suspension of the PCCAM cost sharing mechanism will be addressed in a separate PCCAM docket and we anticipate resolution in the first half of 2027. Within this final order, the MPSC disallowed a portion of the capital costs related to the construction of Yellowstone County Generating Station (YCGS). As a result, in the fourth quarter of 2025 we recorded a $30.9 million non-cash charge for the regulatory disallowance.
In January 2026, we filed a Motion for Reconsideration (Motion) as it relates to this final order. Among other things, our Motion requests that the MPSC reconsider their prudence conclusions regarding the capital costs associated with the construction of YCGS and clarification as to the effective date of the PCCAM sharing mechanism suspension, for which we have requested an effective date of July 1, 2025, to align with the PCCAM tracker year. Any subsequent modifications by the MPSC to their final order are expected to be reflected in our results.
Montana Large New Load Tariff Rule
In March 2026, we filed an application with the MPSC requesting approval of a Large New Load tariff rule (LNL Rule) to establish requirements and contract terms for providing electric service to bundled customers with new or expanded loads of five megawatts or greater, including data centers and other energy-intensive operations. This filing establishes a framework governing agreements between us and large new load customers and is intended to address the costs and operational considerations associated with serving those loads while protecting existing customers from cost shifting and other adverse impacts. Under this proposed framework, for the largest commitments, 50 megawatts or greater, we would file the executed Electric Service Agreement with the MPSC for review and approval before service begins. For customers with loads between 5 and 49 megawatts, the tariff's standardized process and mandatory protections apply, but individual agreements do not require case-specific MPSC approval filings. This application initiates a public regulatory proceeding that will include opportunities for review and public comment consistent with MPSC procedures. Discovery has started in this proceeding, however, the MPSC has not set settlement or hearing dates.
Data Center Development
As previously disclosed, we have signed development agreements with Atlas Power Holdings LLC (Atlas) and Quantica Infrastructure (Quantica) to provide electric supply services for data centers being developed in Montana. The development agreements require us to evaluate the transmission infrastructure and generation resources needed to support their proposed need. Our previously disclosed development agreement with Sabey Data Centers has been terminated. The combined energy service requirement associated with our remaining development agreements is currently expected to be 75 megawatts beginning in late 2027, with growth of up to approximately 1,250 megawatts or more by 2030. We are working with Atlas and Quantica to execute electric service agreements.
Resources and regulatory mechanisms, such as the LNL Rule discussed above, to be utilized for serving these requests are pending further evaluation and regulatory considerations.
Colstrip Acquisitions and Requests for Cost Recovery
As previously disclosed, we entered into definitive agreements with Avista and Puget to acquire their respective interests in Colstrip Units 3 and 4 for $0 and completed these acquisitions on January 1, 2026. Accordingly, we are responsible for the associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates until requested in a future Montana rate review. Puget and Avista will remain responsible for their respective pre-closing share of environmental, asset retirement obligations, and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests.
Avista Interests - The 222 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Avista (Avista Interests) on January 1, 2026, was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan. Noting the costs associated with operating this resource are not currently reflected in utility customer rates, in August 2025, we filed a temporary PCCAM tariff waiver request with the MPSC that could provide a near-term cost-recovery mechanism to offset a portion of the approximately $18.0 million in annual incremental operating and maintenance costs associated with the Avista Interests. This waiver requested that the MPSC allow us to keep 100 percent of the net revenue associated with certain designated power sales contracts up to the amount of the operating and maintenance expenses we incur associated with our Avista Interests. Furthermore, the waiver request indicated that any net revenues from the designated contracts exceeding the operating and maintenance expenses associated with our Avista Interests would continue to flow back to retail customers. In January 2026, the MPSC approved our PCCAM tariff waiver request on an interim basis with final approval or denial subject to the ongoing PCCAM docket process.
During the three and nine months ended September 30, 2026, power prices in the Pacific Northwest associated with these designated power sales contracts included within our PCCAM tariff waiver were insufficient to contribute to the recovery of the operating and maintenance expenses associated with the Avista Interests.
Puget Interests - The 370 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Puget (Puget Interests) on January 1, 2026, increases our ownership share of the facility to 55 percent and provides an increase in voting share in determining strategic direction and investment decisions at the facility. Unlike the Avista Interests, we do not currently need this capacity to serve existing customers in Montana. As such, the Puget Interests are held by our FERC regulated subsidiary to isolate the costs associated with this acquired interest from our Montana retail customers. While we expect our future opportunity to serve growing customer demand, including large-load customers, may be supported by this resource, in October 2025, we signed a contract to sell the dispatchable capacity and associated energy from the Puget Interests beginning January 1, 2026, through late 2027. Revenues from this agreement are expected to largely offset the estimated $30.0 million of annual incremental operating and maintenance costs associated with the Puget Interests. In addition, in October 2025, we submitted a request to the FERC for approval of cost-based rates for our subsidiary that will own the Puget Interests. In February 2026, the FERC approved both the cost-based rates and the contract rates retroactive to January 1, 2026. In March 2026, two MPSC commissioners, in their individual capacity, filed a motion with the FERC requesting a rehearing that largely reiterated arguments previously rejected by the FERC. The FERC denied this motion by operation of law. In June 2026, the two MPSC commissioners appealed the decision to the Ninth Circuit. The Court granted our intervention. The Court further granted FERC's motion to hold the case in abeyance until December 11, 2026.
Generation Capacity in South Dakota
The Southwest Power Pool (SPP) has recently updated its resource accreditation and planning reserve margin (PRM) requirements in response to growing reliability concerns. As a result, SPP is requiring additional accredited capacity by 2030 to meet the updated PRM targets. In October 2025, we submitted a project with the SPP under their Expedited Resource Adequacy Study program for the construction of a 131 MW natural gas generating facility located in Aberdeen, South Dakota, which has been named the Hub City Energy Park generation project, to meet regional capacity needs by 2030. Anticipated costs for this project are approximately $470.0 million. As of September 30, 2026, we have recorded $42.6 million within Other noncurrent assets on the Condensed Consolidated Balance Sheets for non-refundable milestone payments to secure the turbines that will be used at this facility.
South Dakota Phase In Rate Plan Rider
In June 2026, we filed our annual Phase In Rate Plan Rider (PIRP) update with the SDPUC requesting recovery of costs associated with Aberdeen Generating Station, a 33 megawatt (MW) natural gas fired electric generating facility located in Aberdeen, South Dakota, certain nuclear study costs, and the proposed Hub City Energy Park generation project, a 131 MW natural gas generating facility located in Aberdeen, South Dakota. The filing requests collection of approximately $11.8 million of revenue for the July 2026 through June 2027 period with a requested effective date of September 1, 2026. This represents a $7.4 million increase from the previously approved PIRP revenue amount for the July 2025 through June 2026 period. The filing remains pending before the SDPUC.
Regional Transmission Development Activities
In December 2024, we signed a nonbinding memorandum of understanding (MOU) with North Plains Connector LLC, a wholly owned subsidiary of Grid United, to own 10 percent (300 megawatts) of the NPC Consortium project. The project is entering the permitting phase. Currently, construction is planned to commence in 2028, subject to receipt of regulatory approvals, with the project expected to be operational by 2032. Under the terms of the MOU, Grid United will continue to fund the development of the NPC and we will make our investment decision when the regulatory approvals and permits are in place. The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region.
We have also entered into a nonbinding letter of intent with Grid United to continue transmission development to further enhance the grid through the southwest corridor of Montana. Development to expand the southwest corridor of Montana through grid build out would represent a significant step in enhancing connectivity between Montana and the broader Western energy market - bolstering grid reliability, allowing for critical import capability, and enabling customers to access and benefit from emerging energy markets in the West.
South Dakota Wildfire Risk Mitigation
The South Dakota Legislature approved Senate Bill 36, and the Governor signed this bill into law in March 2026. It precludes common law strict liability claims for utility operations alleged to have caused wildfire-related damages; establishes a statutory standard of care, supplanting common law causes of action and other theories of recovery; and creates a rebuttable presumption that a valid and current wildfire mitigation plan is reasonable preparation for, and mitigation of, wildfire risk. The legislation also defines the availability of damages by allowing noneconomic personal injury damages only when there is bodily injury and punitive damages only when an injured party proves by clear and convincing evidence that a qualified utility acted with willful and wanton misconduct and the qualified utility's willful and wanton misconduct was the actual and proximate cause of damages to the plaintiff. In July 2026, we filed our wildfire mitigation plan with the SDPUC. It was duly published completing our compliance obligation.
Financing Update
On August 20, 2026, NW Corp exercised the accordion feature under its existing $425.0 million revolving credit facility to increase the capacity to $500.0 million. On this same day, NorthWestern Energy Group and NWE Public Service exercised the accordion feature under its existing $200.0 million revolving credit facility to increase the capacity to $250.0 million. This increased the base sublimit for NWE Public Service from $150.0 million to $200.0 million. These actions did not affect the maturity date or borrowing rates.
On September 30, 2026, NWE Public Service repaid at maturity $45.0 million of 2.66 percent South Dakota First Mortgage Bonds due on September 30, 2026.
CONSOLIDATED STATEMENT OF INCOME
| Three Months Ended September 30, | Nine Months Ended September 30, |
|---|
| ($ in millions, except per share amounts) | | 2026 | | 2025 | | 2026 | | 2025 |
| Revenues | | | | |
| Electric | $373.6 | | $339.8 | | $1,059.9 | | $954.7 | |
| Gas | 50.1 | | 47.2 | | 254.0 | | 241.6 | |
| Total Revenues | 423.8 | | 387.0 | | 1,313.9 | | 1,196.3 | |
| Operating expenses | | | | |
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 107.3 | | 86.9 | | 342.7 | | 300.4 | |
| Operating and maintenance | 84.9 | | 64.1 | | 238.5 | | 183.2 | |
| Administrative and general | 39.5 | | 46.7 | | 128.0 | | 121.8 | |
| Property and other taxes | 50.5 | | 46.1 | | 151.0 | | 137.5 | |
| Depreciation and depletion | 67.0 | | 62.8 | | 200.9 | | 187.6 | |
| Total Operating Expenses | 349.1 | | 306.7 | | 1,061.0 | | 930.5 | |
| Operating income | 74.6 | | 80.3 | | 253.0 | | 265.8 | |
| Interest expense, net | (42.2) | | (38.4) | | (122.4) | | (111.1) | |
| Other income, net | 3.0 | | 5.1 | | 10.6 | | 9.1 | |
| Income before income taxes | 35.4 | | 47.0 | | 141.1 | | 163.8 | |
| Income tax expense | (4.7) | | (8.8) | | (21.9) | | (27.4) | |
| Net Income | $30.7 | | $38.2 | | $119.2 | | $136.4 | |
| Average Common Shares Outstanding | 61,518 | | 61,395 | | 61,496 | | 61,372 | |
| Basic Earnings per Average Common Share | $0.50 | | $0.62 | | $1.94 | | $2.22 | |
| Diluted Earnings per Average Common Share | $0.50 | | $0.62 | | $1.93 | | $2.22 | |
| Dividends Declared per Common Share | $0.67 | | $0.66 | | $2.01 | | $1.98 | |
| Note: Subtotal variances may exist due to rounding. | | |
RECONCILIATION OF PRIMARY CHANGES DURING THE QUARTER
| Three Months Ended September 30, 2026 vs. 2025 |
|---|
| ($ in millions, except per share amounts) | Pre-tax Income | Income Tax (Expense) Benefit | Net Income | Diluted Earnings Per Share |
| Third Quarter, 2025 | $47.0 | $(8.8) | $38.2 | $0.62 | |
| Variance in revenue and fuel, purchased supply, and direct transmission expense items impacting net income: | | | | |
| Electric margin from the acquisition of the Colstrip Puget Interests | 5.3 | (1.3) | 4.0 | 0.06 | |
| Non-recoverable Montana electric supply costs | 2.3 | (0.6) | 1.7 | 0.03 | |
| Electric retail volumes | 1.5 | (0.4) | 1.1 | 0.02 | |
| Electric transmission revenue | 1.3 | (0.3) | 1.0 | 0.02 | |
| Natural gas retail volumes | 1.0 | (0.3) | 0.7 | 0.01 | |
| Rates | (1.2) | 0.3 | (0.9) | (0.01) | |
| Montana property tax tracker collections | (0.6) | 0.2 | (0.4) | (0.01) | |
| Production tax credits, offset within income tax expense | (0.5) | 0.5 | - | - | |
| Natural gas production step down | (0.1) | 0.0 | (0.1) | | 0.00 |
| Other | 0.1 | 0.0 | 0.1 | | 0.00 |
| Variance in expense items impacting net income: | | | | |
| Operating, maintenance, and administrative, excluding merger-related costs | (15.3) | 3.9 | (11.4) | (0.18) | |
| Depreciation | (4.2) | 1.1 | (3.1) | (0.05) | |
| Interest expense | (3.8) | 1.0 | (2.8) | (0.05) | |
| Property and other taxes not recoverable within trackers | (2.0) | 0.5 | (1.5) | (0.02) | |
| Merger-related costs | 4.4 | 0.7 | 5.1 | 0.08 | |
| Other | 0.2 | (1.2) | (1.0) | (0.02) | |
| Dilution from higher share count | | | | - | |
| Third Quarter, 2026 | $35.4 | $(4.7) | $30.7 | $0.50 | |
| Change in Net Income | | | $(7.5) | $(0.12) | |
| (1) Exclusive of depreciation and depletion shown separately below(2) Excluding fuel, purchased supply, and direct transmission expense(3) Income Tax (Expense) Benefit calculation on reconciling items assumes blended federal plus state effective tax rate of 25.3 percent. |
EXPLANATION OF CONSOLIDATED RESULTS
Three Months Ended September 30, 2026 Compared with the Three Months Ended September 30, 2025
Consolidated gross margin for the three months ended September 30, 2026 was $114.1 million as compared with $127.0 million in 2025, a decrease of $12.9 million, or 10.2 percent. This decrease was primarily due to negative margin associated with our additional ownership interests in Colstrip Units 3 and 4 and depreciation expense. These were offset in part by lower non-recoverable Montana electric supply costs, retail volumes, and transmission revenue.
| ($ in millions) | Three Months Ended September 30, |
| Reconciliation of gross margin to utility margin: | | 2026 | | 2025 |
| Operating Revenues | $423.8 | | $387.0 | |
| Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 107.3 | | 87.0 | |
| Less: Operating and maintenance | 84.9 | | 64.1 | |
| Less: Property and other taxes | 50.5 | | 46.1 | |
| Less: Depreciation and depletion | 67.0 | | 62.8 | |
| Gross Margin | 114.1 | | 127.0 | |
| Add back: Operating and maintenance | 84.9 | | 64.1 | |
| Add back: Property and other taxes | 50.5 | | 46.1 | |
| Add back: Depreciation and depletion | 67.0 | | 62.8 | |
| Utility Margin | $316.5 | | $300.0 | |
| (1) Non-GAAP financial measure. See “Non-GAAP Financial Measures” below. |
| Three Months Ended September 30, |
|---|
| ($ in millions) | | 2026 | | 2025 | Change | % Change |
| Utility Margin | | | | |
| Electric | $277.4 | | $262.6 | | $14.8 | 5.6% |
| Natural Gas | 39.1 | | 37.4 | | 1.7 | 4.5 |
| Total Utility Margin | $316.5 | | $300.0 | | $16.5 | 5.5% |
| (1) Non-GAAP financial measure. See “Non-GAAP Financial Measures” below. | | |
Consolidated utility margin for the three months ended September 30, 2026 was $316.5 million as compared with $300.0 million for the same period in 2025, an increase of $16.5 million, or 5.5 percent.
Primary components of the change in utility margin include the following:
| ($ in millions) | Utility Margin 2026 vs. 2025 |
| Utility Margin Items Impacting Net Income | |
| Electric margin from the acquisition of the Puget Interests | $5.3 |
| Non-recoverable Montana electric supply costs | 2.3 |
| Electric retail volumes | 1.5 |
| Electric transmission revenue | 1.3 |
| Natural gas retail volumes | 1.0 |
| Base rates | (1.2) |
| Montana property tax tracker collections | (0.6) |
| Natural gas production step down | (0.1) |
| Other | 0.1 |
| Change in Utility Margin Items Impacting Net Income | 9.6 |
| Utility Margin Items Offset Within Net Income | |
| Operating expenses recovered in revenue, offset in operating and maintenance expense | 5.0 |
| Property and other taxes recovered in revenue, offset in property and other taxes | 2.4 |
| Production tax credits, offset in income tax expense | (0.5) |
| Change in Utility Margin Items Offset Within Net Income | 6.9 |
| Increase in Consolidated Utility Margin | $16.5 |
| (1) Non-GAAP financial measure. See “Non-GAAP Financial Measures” below. | |
Electric retail volumes were impacted by favorable weather and customer growth in all jurisdictions. Natural gas retail volumes were impacted by favorable weather in Montana and customer growth, partly offset by unfavorable weather in South Dakota and Nebraska.
Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility costs) were allocated 90 percent to Montana customers and 10 percent to shareholders. Effective February 1, 2026 the cost sharing mechanism of the PCCAM was suspended on an interim basis pending further review by the MPSC. For the three months ended September 30, 2025, we recorded a decrease in pre-tax earnings of $2.3 million (10 percent of the PCCAM Base cost variance).
| Three Months Ended September 30, |
|---|
| ($ in millions) | | 2026 | | 2025 | Change | % Change |
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | | | | |
| Operating and maintenance | $84.9 | | $64.1 | | $20.8 | 32.4% |
| Administrative and general | 39.5 | | 46.7 | | (7.2) | (15.4) |
| Property and other taxes | 50.5 | | 46.1 | | 4.4 | 9.5 |
| Depreciation and depletion | 67.0 | | 62.8 | | 4.2 | 6.7 |
| Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $241.9 | | $219.7 | | $22.2 | 10.1% |
Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $241.9 million for the three months ended September 30, 2026, as compared with $219.7 million for the three months ended September 30, 2025. Primary components of the change include the following:
| Operating Expenses |
|---|
| ($ in millions) | 2026 vs. 2025 |
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income | |
| Electric generation maintenance (including $7.2 million and $4.3 million due to the acquisition of the Colstrip Puget Interests and Avista Interests, respectively) | $10.5 |
| Depreciation expense due to plant additions and higher depreciation rates | 4.2 |
| Labor and benefits | 2.8 |
| Property and other taxes not recoverable within trackers (including $1.6 million and $0.3 million due to the acquisition of the Colstrip Puget Interests and Avista Interests, respectively) | 2.0 |
| Technology implementation and maintenance expenses | 1.2 |
| Wildfire mitigation expense, partly offset by higher base revenues | 0.5 |
| Uncollectible accounts | 0.2 |
| Merger-related costs, including consulting and legal fees | (4.4) |
| Insurance expense | (0.4) |
| Other | 0.5 |
| Change in Items Impacting Net Income | 17.1 |
| Operating Expenses Offset Within Net Income | |
| Operating and maintenance expenses recovered in trackers, offset in revenue | 5.0 |
| Property and other taxes recovered in trackers, offset in revenue | 2.4 |
| Pension and other postretirement benefits, offset in other income | 0.2 |
| Deferred compensation, offset in other income | (2.5) |
| Change in Items Offset Within Net Income | 5.1 |
| Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $22.2 |
(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. This change is offset within this table as it does not affect our operating expenses.
We estimate property taxes throughout each year, and update those estimates based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases and decreases in the actual level of state and local taxes and fees and adjust our rates to recover the increase or decrease between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
Consolidated operating income for the three months ended September 30, 2026 was $74.6 million as compared with $80.3 million in the same period of 2025. This decrease was primarily due to operating losses associated with our additional ownership interests in Colstrip Units 3 and 4 and depreciation expense. These were offset in part by lower non-recoverable Montana electric supply costs, retail volumes, transmission revenue, and lower merger-related costs.
Consolidated interest expense was $42.2 million for the three months ended September 30, 2026 as compared with $38.4 million for the same period of 2025. This increase was due to higher borrowings and interest rates offset in part by higher capitalization of Allowance for Funds Used During Construction (AFUDC).
Consolidated other income was $3.0 million for the three months ended September 30, 2026 as compared with $5.1 million for the same period of 2025. This decrease was primarily due to a decrease in the value of deferred shares held in trust for deferred compensation offset in part by higher capitalization of AFUDC.
Consolidated income tax expense was $4.7 million for the three months ended September 30, 2026 as compared to $8.8 million for the same period of 2025. Our effective tax rate for the three months ended September 30, 2026 was 13.2% as compared with 18.7% for the same period in 2025.
The following table summarizes the differences between our effective tax rate and the federal statutory rate:
| Three Months Ended September 30, |
|---|
| ($ in millions) | | | | 2026 | | | | 2025 |
| (in dollars) | (in percent) | (in dollars) | (in percent) |
| Income before income taxes | $35.4 | | | $47.0 | | |
| Income tax calculated at federal statutory rate | | 7.4 | 21.0% | | | 9.9 | 21.0% | |
| State income tax, net of federal provision | | 0.5 | 1.4 | | | 0.1 | 0.2 | |
| Tax Credits | | | | |
| Production tax credits | (0.9) | | (2.5) | | (1.3) | | (2.8) | |
| Other | - | | - | | 0.2 | | 0.4 | |
| Impact of utility ratemaking on income taxes | | | | |
| Flow-through repairs deductions | (5.6) | | (15.8) | | (5.2) | | (11.1) | |
| Amortization of excess deferred income taxes | (0.8) | | (2.3) | | (0.4) | | (0.8) | |
| AFUDC, net | (0.3) | | (0.8) | | (0.3) | | (0.6) | |
| Plant and depreciation of flow through items | 3.9 | | 11.0 | | 3.3 | | 7.0 | |
| Changes in Unrecognized Tax Benefits | | | | |
| Interest and penalties | - | | - | | 0.3 | | 0.6 | |
| Nontaxable and nondeductible items | | | | |
| Merger transaction costs | 0.1 | | 0.3 | | 1.9 | | 4.1 | |
| Other | 0.4 | | 0.9 | | 0.2 | | 0.4 | |
| Other | - | | - | | 0.1 | | 0.3 | |
| (2.7) | | (7.8) | | (1.1) | | (2.3) | |
| Income Tax Expense and Effective Tax Rate | $4.7 | | 13.2% | | $8.8 | | 18.7% | |
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.
LIQUIDITY AND OTHER CONSIDERATIONS
Liquidity and Capital Resources
As of September 30, 2026, our total net liquidity was approximately $349.5 million, including $6.5 million of cash and cash equivalents and $343.0 million of revolving credit facility availability with no letters of credit outstanding. This compares to total net liquidity one year ago at September 30, 2025 of $262.2 million.
Earnings Per Share
Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows:
| Three Months Ended |
|---|
| September 30, 2026 | September 30, 2025 |
|---|
| Basic computation | 61,518,300 | 61,395,002 |
| Dilutive effect of: | | |
| Performance and restricted share awards | 285,233 | 158,323 |
| Diluted computation | 61,803,533 | 61,553,325 |
| Nine Months Ended |
|---|
| September 30, 2026 | September 30, 2025 |
|---|
| Basic computation | 61,496,216 | 61,371,962 |
| Dilutive effect of: | | |
| Performance and restricted share awards | 240,704 | 116,597 |
| Diluted computation | 61,736,920 | 61,488,559 |
| (1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. |
As of September 30, 2026, there were no shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations, compared to 20,406 shares as of September 30, 2025.
Adjusted Non-GAAP Earnings
We reported GAAP earnings of $0.50 per diluted share for the three months ended September 30, 2026 and $0.62 per diluted share for the same period in 2025. Adjusted Non-GAAP earnings per diluted share for the same periods are $0.58 and $0.79, respectively. A reconciliation of items factored into our Adjusted Non-GAAP diluted earnings are summarized below. The amount below represents a non-GAAP measure that may provide users of this data with additional meaningful information regarding the impact of certain items on our expected earnings. More information on this measure can be found in the "Non-GAAP Financial Measures" section below.
| Pre-tax Income | Net Income | Diluted EPS |
|---|
| ($ in millions, except EPS) | |
| Three Months Ended September 30, 2026 |
| 2026 Reported GAAP | | $35.4 | | $30.7 | | $0.50 |
| Non-GAAP Adjustments: |
| Favorable Weather (Deduct) | (1.1) | | (0.8) | | (0.01) | |
| Merger-Related Costs | 3.2 | | 2.5 | | 0.04 | |
| Colstrip Avista Interests | 4.3 | | 3.2 | | 0.05 | |
| 2026 Adj. Non-GAAP | | $41.8 | | $35.6 | | $0.58 |
| Three Months Ended September 30, 2025 |
| Pre-tax Income | Net Income | Diluted EPS |
| 2025 Reported GAAP | | $47.0 | | $38.2 | | $0.62 |
| Non-GAAP Adjustments: |
| Unfavorable Weather (Addback) | 3.5 | | 2.6 | | 0.05 | |
| Merger-Related Costs | 7.6 | | 7.6 | | 0.12 | |
| 2025 Adj. Non-GAAP | | $58.1 | | $48.4 | | $0.79 |
| (1) Income tax rate on reconciling items assumes blended federal plus state effective tax rate of 25.3%. (2) Certain merger-related costs are not tax-deductible. (3) Power prices in the Pacific Northwest associated with the designated power sales contracts included within our temporary PCCAM tariff waiver were insufficient to recover the operating expenses associated with the Avista Interests. |
Company Hosting Earnings Webinar
NorthWestern will host an investor earnings webinar on Thursday, November 5, 2026, at 11:00 a.m. Eastern time to review its financial results for the three months ended September 30, 2026. To register for the webinar, please visit www.northwesternenergy.com/earnings-registration. Please go to the site at least 15 minutes in advance of the webinar to register. An archived webinar will be available shortly after the event and remain active for one year.
NorthWestern Energy - Delivering a Bright Future
NorthWestern Energy Group, doing business as NorthWestern Energy, provides essential energy infrastructure and valuable services that enrich lives and empower communities while serving as long-term partners to our customers and communities. We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We provide electricity and / or natural gas to approximately 850,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Upon the completion of the holding company reorganization in 2023, NW Corp became a subsidiary of NorthWestern Energy Group. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. We have provided service in South Dakota and Nebraska since 1923 and in Montana since 2002.
Non-GAAP Financial Measures
This press release includes financial information prepared in accordance with GAAP, as well as other financial measures, such as Utility Margin, Adjusted Non-GAAP pretax income, Adjusted Non-GAAP net income and Adjusted Non-GAAP Diluted EPS that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.
We define Utility Margin as Operating Revenues less fuel, purchased supply, and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. A reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure, is included in the press release above.
Management believes that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic, or other conditions), rates, and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
Management also believes the presentation of Adjusted Non-GAAP pre-tax income, Adjusted Non-GAAP net income, and Adjusted Non-GAAP Diluted EPS is more representative of normal earnings than GAAP pre-tax income, net income, and EPS due to the exclusion (or inclusion) of certain impacts that are not reflective of ongoing earnings. The presentation of these non-GAAP measures is intended to supplement investors' understanding of our financial performance and not to replace other GAAP measures as an indicator of actual operating performance. Our measures may not be comparable to other companies' similarly titled measures.
Special Note Regarding Forward-Looking Statements
This press release contains forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, including, without limitation, the information under "Adjusted Non-GAAP Earnings." Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records, and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:
- risks relating to the pending merger transaction pursuant to that certain Agreement and Plan of Merger dated August 18, 2025 (Merger Agreement) between NorthWestern and Black Hills Corporation (Black Hills), including, among others, (1) the risk of delays in consummating the pending merger transaction, including as a result of required regulatory approvals, which may not be obtained on the expected timeline, or at all, (2) the risk of any event, change or other circumstance that could give rise to the termination of the Merger Agreement, (3) the risk that required regulatory approvals are subject to conditions not anticipated by NorthWestern and Black Hills, (4) the possibility that the anticipated benefits and projected value creation of the pending merger transaction will not be realized or will not be realized within the expected time period, (5) disruption to the parties’ businesses as a result of the announcement and pendency of the merger transaction, including potential distraction of management from current plans and operations of NorthWestern or Black Hills and the ability of NorthWestern or Black Hills to retain and hire key personnel, (6) reputational risk and the reaction of each company’s customers, suppliers, employees or other business partners to the pending merger transaction, (7) the possibility that the pending merger transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events, (8) the outcome of any legal or regulatory proceedings that may be instituted against NorthWestern or Black Hills related to the Merger Agreement or the pending merger transaction, (9) the risks associated with third party contracts containing consent and/or other provisions that may be triggered by the pending merger transaction, (10) legislative, regulatory, political, market, economic and other conditions, developments and uncertainties affecting NorthWestern's or Black Hills' businesses; (11) the evolving legal, regulatory and tax regimes under which NorthWestern and Black Hills operate; (12) restrictions during the pendency of the merger transaction that may impact NorthWestern's or Black Hills' ability to pursue certain business opportunities or strategic transactions; and (13) unpredictability and severity of catastrophic events, including, but not limited to, extreme weather, natural disasters, acts of terrorism or outbreak of war or hostilities, as well as NorthWestern's and Black Hills' response to any of the aforementioned factors;
- adverse determinations by regulators, such as adverse outcomes from the denial of interim rates, final rates not consistent with a reasonable ability to earn our allowed returns, failure to timely approve our requests associated with recovering the operating costs for the additional interests in Colstrip Units 3 and 4, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, and wildfire damages in excess of liability insurance coverage, could have a material effect on our liquidity, results of operations and financial condition;
- our ability to attract and serve large new load customers, including data centers and other energy-intensive operations, depends on regulatory and legislative actions supportive of a framework for review and approval of these large new load customer contracts;
- our ability to enter agreements to sell excess capacity and associated energy from additional interests in Colstrip Units 3 and 4 on favorable commercial and economic terms;
- the impact of extraordinary external events and natural disasters, such as a wide-spread or global pandemic, geopolitical events, earthquake, flood, drought, lightning, weather, wind, and fire, could have a material effect on our liquidity, results of operations and financial condition;
- acts of terrorism, cybersecurity attacks, data security breaches, or other malicious acts that cause damage to our generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;
- supply chain constraints, tariffs on certain imported products, recent high levels of inflation for products, services and labor costs, and their impact on capital expenditures, operating activities, and/or our ability to safely and reliably serve our customers;
- changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;
- unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase operating costs or may require additional capital expenditures or other increased operating costs; and
- adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.
Additional factors which could affect future results of NorthWestern and Black Hills can be found in NorthWestern Energy’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, and Black Hills’ Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, in each case filed with the SEC and available on the SEC’s website at http://www.sec.gov. NorthWestern and Black Hills disclaim any obligation and do not intend to update or revise any forward-looking statements contained in this communication, which speak only as of the date hereof, whether as a result of new information, future events or otherwise, except as required by federal securities laws.
Investor Relations Contact: Media Contact:
Travis Meyer (605) 978-2967 Jo Dee Black (866) 622-8081 travis.meyer@northwestern.com jodee.black@northwestern.com