# NorthWestern Energy Group, Inc.: Form 10-Q for the period ended Sep 30, 2024

- Company: [NorthWestern Energy Group, Inc.](/companies/nwe.md) (CIK 1993004)
- Form: 10-Q
- Filed: 2024-10-29
- Accepted by EDGAR: Oct 28, 2024, 19:02 ET
- Period: 2024-09-30
- Accession: 0001993004-24-000102
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1993004/000199300424000102/nwe-20240930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1993004/000199300424000102/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-07-01 to 2024-09-30 | $345.2m | us-gaap:Revenues |
| Revenue | 9 months, 2024-01-01 to 2024-09-30 | $1.14bn | us-gaap:Revenues |
| Operating income | 3 months, 2024-07-01 to 2024-09-30 | $67.9m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2024-01-01 to 2024-09-30 | $231.6m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2024-07-01 to 2024-09-30 | −$3.2m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2024-01-01 to 2024-09-30 | $11.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-07-01 to 2024-09-30 | $46.8m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2024-01-01 to 2024-09-30 | $143.6m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.76 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2024-01-01 to 2024-09-30 | $2.34 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.76 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2024-01-01 to 2024-09-30 | $2.34 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-07-01 to 2024-09-30 | 61,396,975 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2024-01-01 to 2024-09-30 | 61,354,706 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2024-01-01 to 2024-09-30 | $343.9m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 9 months, 2024-01-01 to 2024-09-30 | $400.5m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 9 months, 2024-01-01 to 2024-09-30 | $118.9m | us-gaap:PaymentsOfDividendsCommonStock |
| Cash and equivalents | at 2024-09-30 | $2.5m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-09-30 | $368.4m | us-gaap:AssetsCurrent |
| Total assets | at 2024-09-30 | $7.85bn | us-gaap:Assets |
| Current liabilities | at 2024-09-30 | $813.3m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-09-30 | $5.04bn | us-gaap:Liabilities |
| Long-term debt | at 2024-09-30 | $2.57bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2024-09-30 | $299.9m | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2024-09-30 | $100.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2024-09-30 | $2.82bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 75,959 characters.

### Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.

We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.

### OVERVIEW

NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 775,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:

- Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
- Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
- Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.

We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.

We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050.

As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three and nine months ended September 30, 2024 and 2023.

### HOW WE PERFORMED AGAINST OUR THIRD QUARTER 2023 RESULTS

*(in millions)*

|  | Three Months Ended September 30, 2024 vs. 2023 Income Before Income Taxes | Income Tax (Expense) Benefit(3) | Net Income |
| --- | ---: | ---: | ---: |
| **Third Quarter, 2023** | **$31.0** | **$(1.7)** | **$29.3** |
| Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income: |  |  |  |
| Base rates | 17.2 | (4.4) | 12.8 |
| Electric transmission revenue | 5.9 | (1.5) | 4.4 |
| Electric retail volumes | 3.6 | (0.9) | 2.7 |
| Montana property tax tracker collections | 1.5 | (0.4) | 1.1 |
| Montana natural gas transportation | 0.9 | (0.2) | 0.7 |
| Non-recoverable Montana electric supply costs | 0.6 | (0.2) | 0.4 |
| Natural gas retail volumes | (0.3) | 0.1 | (0.2) |
| Production tax credits, offset within income tax benefit | (0.2) | 0.2 | — |
| Other | (1.2) | 0.3 | (0.9) |
| Variance in expense items(2) impacting net income: |  |  |  |
| Operating, maintenance, and administrative | (5.5) | 1.4 | (4.1) |
| Depreciation | (4.8) | 1.2 | (3.6) |
| Interest expense | (4.7) | 1.2 | (3.5) |
| Property and other taxes not recoverable within trackers | (1.9) | 0.5 | (1.4) |
| Gas repairs safe harbor method change | — | 7.0 | 7.0 |
| Other | 1.5 | 0.6 | 2.1 |
| **Third Quarter, 2024** | **$43.6** | **$3.2** | **$46.8** |
| **Change in Net Income** |  |  | **$17.5** |

(1) Exclusive of depreciation and depletion shown separately below

(2) Excluding fuel, purchased supply, and direct transmission expense

(3) Income tax expense calculation on reconciling items assumes a blended federal plus state effective tax rate of 25.3 percent.

Consolidated net income for the three months ended September 30, 2024 was $46.8 million as compared with $29.3 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, lower non-recoverable Montana electric supply costs, and an income tax benefit from a change to the gas repairs safe harbor method. These were offset in part by natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

### SIGNIFICANT TRENDS AND REGULATION

Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2023 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows:

### Yellowstone County 175 MW plant

Construction of the new generation facility was substantially completed and the plant placed in service in October 2024. 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 have increased costs. As of September 30, 2024, total costs of approximately $305.6 million have been incurred, with expected total costs of approximately

$310.0 million to $320.0 million. See Note 10 - Commitments and Contingencies to the Condensed Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.

### Regulatory Update

Rate reviews are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We regularly review the need for electric and natural gas rate relief in each state in which we provide service. Our ongoing rate review activity includes the following:

*Montana Rate Review -* In July 2024, we filed a Montana electric and natural gas rate review with the MPSC. The filing requests a base rate annual revenue increase of $156.5 million ($69.4 million net with Property Tax and PCCAM tracker adjustments) for electric and $28.6 million for natural gas. Our request is based on a return on equity of 10.80 percent with a capital structure including 46.81 percent equity, and forecasted 2024 electric and natural gas rate base of $3.45 billion and $731.9 million, respectively. The electric rate base investment includes the 175-megawatt natural gas-fired Yellowstone County Generating Station, which was placed in service in October 2024.

Our filing included a request for interim base rates to be effective October 1, 2024. Implementation of interim base rates, if any, has been delayed beyond our requested effective date as the MPSC has not yet made a decision on the interim rate request.

The MPSC has developed its procedural schedule for our rate review request including a hearing scheduled to commence on April 22, 2025. If a final order is not received by May 23, 2025, which is 270 days from acceptance of our filing, we intend to implement, as permitted by the MPSC regulations, our requested rates, which will be subject to refund, until a final order is received.

*South Dakota Natural Gas Rate Review -* In June 2024, we filed a natural gas rate review with the South Dakota Public Utilities Commission. The filing requests a base rate annual revenue increase of $6.0 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 $95.6 million. If a final order is not received by December 21, 2024, interim base rates may go into effect.

*Nebraska Natural Gas Rate Review -* In June 2024, we filed a natural gas rate review with the NPSC. The filing requests a base rate annual revenue increase of $3.6 million. Our request is based on a return on equity of 10.70 percent, a capital structure including 53.13 percent equity, and rate base of $47.4 million. Interim rates, which increased base natural gas rates $2.3 million, were implemented on October 1, 2024. Interim rates will remain in effect on a refundable basis until the NPSC issues a final order.

### EPA Rules

On April 25, 2024, the EPA released GHG Rules for existing coal-fired facilities and new coal and natural gas-fired facilities as well as MATS Rules. Compliance with the rules will require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively. See Note 10 - Commitments and Contingencies to the Condensed Consolidated Financial Statements included herein for additional information regarding these rules.

### Acquisition of Energy West Montana Assets

On July 29, 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 in cash, subject to certain working capital and other agreed upon closing adjustments. The transaction is subject to a number of customary closing conditions, including MPSC approval, and we expect the acquisition to be completed by the end of the first quarter of 2025.

### Colstrip - Puget Sound Energy Transaction

On July 30, 2024, we entered into a definitive agreement (the Agreement) with Puget Sound Energy (Puget) to acquire Puget's 25 percent interest in each of Units 3 and 4 (collectively representing 370 megawatts) at the Colstrip Generating Station for $0. The acquisition would be effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the Agreement. Under the terms of the Agreement, we will be responsible for operating costs starting on January 1, 2026; while Puget will retain responsibility for its 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 Puget's interest. The Agreement is subject to customary conditions and approvals. The ultimate amount of Puget's ownership interest we acquire is contingent on a right-of-first-refusal held by other Colstrip owners which, if exercised prior to expiration in fourth quarter 2024, would reduce our acquired interest proportionately.

Acquisition of Puget’s entire ownership interest, in addition to the previously disclosed acquisition of Avista’s 15 percent interest in each of Colstrip Units 3 and 4 (collectively representing 222 megawatts), would result in our ownership of 55 percent of the facility with the ability to guide operating and maintenance investments. This provides 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.

### 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 North Plains Connector (NPC) Consortium project. The 415-mile, high-voltage direct-current transmission line is intended to connect Montana's Colstrip substation, of which we are the operator and a joint owner, to central North Dakota, bridging the eastern and western U.S. energy grids. The NPC Consortium includes potential upgrades to our jointly owned Colstrip Transmission System and $70.0 million of the award is earmarked for the Colstrip Transmission System Upgrade. The NPC project, estimated to be a $3.6 billion investment, aims to enhance grid reliability, support renewable energy integration, and provide additional capacity across multiple states. We collaborated with Grid United, the Montana Department of Commerce, and other regional utilities on the successful GRIP grant application. 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. In addition to the Colstrip Transmission System Upgrade, we are considering an investment in NPC and are engaged in regional transmission development activities.

### RESULTS OF OPERATIONS

Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.

### Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.

Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.

### OVERALL CONSOLIDATED RESULTS

### Three Months Ended September 30, 2024 Compared with the Three Months Ended September 30, 2023

Consolidated net income for the three months ended September 30, 2024 was $46.8 million as compared with $29.3 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, lower non-recoverable Montana electric supply costs, and a income tax benefit from a change to the gas repairs safe harbor method. These were offset in part by natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

Consolidated gross margin for the three months ended September 30, 2024 was $102.8 million as compared with $83.5 million in 2023, an increase of $19.3 million, or 23.1 percent. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs. These were offset in part by natural gas retail volumes, depreciation, and operating and maintenance costs.

*(in millions)*

| Reconciliation of gross margin to utility margin: | Electric 2024 | 2023 | Natural Gas 2024 | 2023 | Total 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating Revenues | $306.5 | $280.0 | $38.7 | $41.1 | $345.2 | $321.1 |
| Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 80.8 | 78.0 | 7.1 | 10.9 | 87.9 | 88.9 |
| Less: Operating and maintenance | 42.5 | 40.0 | 13.4 | 13.2 | 55.9 | 53.2 |
| Less: Property and other taxes | 32.3 | 33.7 | 9.3 | 9.6 | 41.6 | 43.3 |
| Less: Depreciation and depletion | 47.6 | 43.3 | 9.4 | 8.9 | 57.0 | 52.2 |
| **Gross Margin** | **103.3** | **85.0** | **(0.5)** | **(1.5)** | **102.8** | **83.5** |
| Operating and maintenance | 42.5 | 40.0 | 13.4 | 13.2 | 55.9 | 53.2 |
| Property and other taxes | 32.3 | 33.7 | 9.3 | 9.6 | 41.6 | 43.3 |
| Depreciation and depletion | 47.6 | 43.3 | 9.4 | 8.9 | 57.0 | 52.2 |
| **Utility Margin(1)** | **$225.7** | **$202.0** | **$31.6** | **$30.2** | **$257.3** | **$232.2** |

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

*(dollars in millions)*

| Utility Margin | Three Months Ended September 30, 2024 | 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Electric | $225.7 | $202.0 | $23.7 | 11.7% |
| Natural Gas | 31.6 | 30.2 | 1.4 | 4.6 |
| **Total Utility Margin(1)** | **$257.3** | **$232.2** | **$25.1** | **10.8%** |

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Consolidated utility margin for the three months ended September 30, 2024 was $257.3 million as compared with $232.2 million for the same period in 2023, an increase of $25.1 million, or 10.8 percent. Primary components of the change in utility margin include the following (in millions):

| Utility Margin Items Impacting Net Income | Utility Margin 2024 vs. 2023 |
| --- | ---: |
| Base rates | $17.2 |
| Transmission revenue due to market conditions and rates | 5.9 |
| Electric retail volumes | 3.6 |
| Montana property tax tracker collections | 1.5 |
| Montana natural gas transportation | 0.9 |
| Non-recoverable Montana electric supply costs | 0.6 |
| Natural gas retail volumes | (0.3) |
| Other | (1.2) |
| **Change in Utility Margin Items Impacting Net Income** | **28.2** |
| **Utility Margin Items Offset Within Net Income** |  |
| Property and other taxes recovered in revenue, offset in property and other taxes | (2.0) |
| Operating expenses recovered in revenue, offset in operating and maintenance expense | (0.9) |
| Production tax credits, offset in income tax expense | (0.2) |
| **Change in Utility Margin Items Offset Within Net Income** | **(3.1)** |
| **Increase in Consolidated Utility Margin(1)** | **$25.1** |

29

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Higher electric retail volumes were driven by favorable weather in Montana impacting residential demand, higher commercial and industrial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in South Dakota impacting residential demand. Lower natural gas retail volumes were driven by unfavorable weather in Montana partly offset by customer growth in all jurisdictions.

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. For the three months ended September 30, 2024, we over-collected supply costs of $5.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance). For the three months ended September 30, 2023, we over-collected supply costs of $1.0 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.1 million.

*(dollars in millions)*

| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | Three Months Ended September 30, 2024 | 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Operating and maintenance | $55.9 | $53.2 | $2.7 | 5.1% |
| Administrative and general | 34.9 | 29.4 | 5.5 | 18.7 |
| Property and other taxes | 41.6 | 41.8 | (0.2) | (0.5) |
| Depreciation and depletion | 57.0 | 52.2 | 4.8 | 9.2 |
| **Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)** | **$189.4** | **$176.6** | **$12.8** | **7.2%** |

30

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $189.4 million for the three months ended September 30, 2024, as compared with $176.6 million for the three months ended September 30, 2023. Primary components of the change include the following (in millions):

| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income | Operating Expenses 2024 vs. 2023 |
| --- | ---: |
| Depreciation expense due to plant additions and higher depreciation rates | $4.8 |
| Insurance expense, primarily due to increased wildfire risk premiums | 3.4 |
| Labor and benefits(1) | 3.0 |
| Electric generation maintenance | 1.9 |
| Property and other taxes not recoverable within trackers | 1.9 |
| Technology implementation and maintenance expenses | (0.1) |
| Partial recovery from previously impaired alternative energy storage investment | (0.5) |
| Uncollectible accounts | (1.1) |
| Other | (1.1) |
| **Change in Items Impacting Net Income** | **12.2** |
| **Operating Expenses Offset Within Net Income** |  |
| Property and other taxes recovered in trackers, offset in revenue | (2.0) |
| Operating and maintenance expenses recovered in trackers, offset in revenue | (0.9) |
| Deferred compensation, offset in other income | 2.8 |
| Pension and other postretirement benefits, offset in other income(1) | 0.7 |
| **Change in Items Offset Within Net Income** | **0.6** |
| **Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)** | **$12.8** |

(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, 2024 was $67.9 million as compared with $55.6 million in the same period of 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs. These were offset in part by natural gas retail volumes, depreciation, operating, and administrative and general expenses.

Consolidated interest expense was $33.4 million for the three months ended September 30, 2024 as compared with $28.7 million for the same period of 2023. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of Allowance for Funds Used During Construction (AFUDC).

Consolidated other income was $9.1 million for the three months ended September 30, 2024 as compared with $4.1 million for the same period of 2023. This increase was primarily due to higher capitalization of AFUDC, a decrease in the non-service component of pension expense, and an increase in the value of deferred shares held in trust for deferred compensation.

Consolidated income tax benefit was $3.2 million for the three months ended September 30, 2024 as compared to income tax expense of $1.7 million for the same period of 2023. Our effective tax rate for the three months ended September 30, 2024 was (7.3)% as compared with 5.5% for the same period in 2023. As further discussed in Note 3 - Income Taxes, during the third quarter of 2024 we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission and distribution property. This resulted in an income tax benefit of $7.0 million during the three months ended September 30, 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

|  | Three Months Ended September 30, 2024 |  | 2023 |  |
| --- | ---: | ---: | ---: | ---: |
| Income Before Income Taxes | $43.7 |  | $31.0 |  |
| Income tax calculated at federal statutory rate | 9.2 | 21.0% | 6.5 | 21.0% |
| Permanent or flow-through adjustments: |  |  |  |  |
| State income tax, net of federal provisions | 0.1 | 0.1 | 0.1 | 0.4 |
| Gas repairs safe harbor method change | (7.0) | (16.0) | — | — |
| Flow-through repairs deductions | (4.6) | (10.5) | (4.2) | (13.5) |
| Production tax credits | (2.4) | (5.6) | (1.3) | (4.1) |
| Amortization of excess deferred income tax | (0.2) | (0.5) | (0.3) | (1.0) |
| Income tax return to accrual adjustment | — | — | 0.4 | 1.3 |
| Plant and depreciation flow-through items | 1.8 | 4.2 | 0.4 | 1.2 |
| Other, net | (0.1) | — | 0.1 | 0.2 |
|  | (12.4) | (28.3) | (4.8) | (15.5) |
| **Income tax (benefit) expense** | $(3.2) | (7.3)% | $1.7 | 5.5% |

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.

### Nine Months Ended September 30, 2024 Compared with the Nine Months Ended September 30, 2023

Consolidated net income for the nine months ended September 30, 2024 was $143.6 million as compared with $111.0 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, electric retail volumes, and an income tax benefit from a change to the gas repairs safe harbor method. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

Consolidated gross margin for the nine months ended September 30, 2024 was $338.3 million as compared with $289.8 million in 2023, an increase of $48.5 million, or 16.7 percent. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, and electric retail volumes. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, natural gas retail volumes, depreciation, and operating and maintenance costs.

*(in millions)*

| Reconciliation of gross margin to utility margin: | Electric 2024 | 2023 | Natural Gas 2024 | 2023 | Total 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating Revenues | $909.8 | $804.6 | $230.6 | $261.5 | $1,140.4 | $1,066.1 |
| Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 257.0 | 198.5 | 82.1 | 123.5 | 339.1 | 322.0 |
| Less: Operating and maintenance | 126.3 | 123.8 | 41.1 | 40.1 | 167.4 | 163.9 |
| Less: Property and other taxes | 96.6 | 103.0 | 28.4 | 29.6 | 125.0 | 132.6 |
| Less: Depreciation and depletion | 142.4 | 130.5 | 28.2 | 27.3 | 170.6 | 157.8 |
| **Gross Margin** | **287.5** | **248.8** | **50.8** | **41.0** | **338.3** | **289.8** |
| Operating and maintenance | 126.3 | 123.8 | 41.1 | 40.1 | 167.4 | 163.9 |
| Property and other taxes | 96.6 | 103.0 | 28.4 | 29.6 | 125.0 | 132.6 |
| Depreciation and depletion | 142.4 | 130.5 | 28.2 | 27.3 | 170.6 | 157.8 |
| **Utility Margin(1)** | **$652.8** | **$606.1** | **$148.5** | **$138.0** | **$801.3** | **$744.1** |

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

*(dollars in millions)*

| Utility Margin | Nine Months Ended September 30, 2024 | 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Electric | $652.8 | $606.1 | $46.7 | 7.7% |
| Natural Gas | 148.5 | 138.0 | 10.5 | 7.6 |
| **Total Utility Margin(1)** | **$801.3** | **$744.1** | **$57.2** | **7.7%** |

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Consolidated utility margin for the nine months ended September 30, 2024 was $801.3 million as compared with $744.1 million for the same period in 2023, an increase of $57.2 million, or 7.7 percent. Primary components of the change in utility margin include the following (in millions):

| Utility Margin Items Impacting Net Income | Utility Margin 2024 vs. 2023 |
| --- | ---: |
| Base rates | $53.4 |
| Transmission revenue due to market conditions and rates | 13.5 |
| Montana property tax tracker collections(1) | 4.9 |
| Montana natural gas transportation | 1.9 |
| Electric retail volumes | 1.0 |
| QF liability adjustment | (4.2) |
| Non-recoverable Montana electric supply costs | (3.8) |
| Natural gas retail volumes | (2.7) |
| Other | 2.4 |
| **Change in Utility Margin Items Impacting Net Income** | **66.4** |
| **Utility Margin Items Offset Within Net Income** |  |
| Property and other taxes recovered in revenue, offset in property and other taxes | (8.2) |
| Production tax credits, offset in income tax expense | (1.5) |
| Operating expenses recovered in revenue, offset in operating and maintenance expense | 0.5 |
| **Change in Utility Margin Items Offset Within Net Income** | **(9.2)** |
| **Increase in Consolidated Utility Margin(2)** | **$57.2** |

(1) In the fourth quarter of 2023, upon receiving the final valuation reports from the Montana Department of Revenue, we recorded a significant reduction in property tax expense. Accordingly, we do not anticipate this year-to-date favorable change to Utility Margin to continue on a full year basis.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Under the PCCAM, net supply costs higher or lower than the PCCAM Base (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the nine months ended September 30, 2024, we under-collected supply costs of $10.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance). For the nine months ended September 30, 2023, we over-collected supply costs of $23.5 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.6 million.

Electric retail volume impact was favorable due to higher residential usage in Montana due to favorable weather, higher industrial volumes, and customer growth, partly offset by lower residential usage due to unfavorable weather in South Dakota, and lower commercial demand. Lower natural gas retail volumes were driven by unfavorable weather in all jurisdictions partly offset by customer growth.

The adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, as further explained above in the consolidated results of operations for the three months ended June 30, 2024.

*(dollars in millions)*

| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | Nine Months Ended September 30, 2024 | 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Operating and maintenance | $167.4 | $163.9 | $3.5 | 2.1% |
| Administrative and general | 106.7 | 94.1 | 12.6 | 13.4 |
| Property and other taxes | 125.0 | 131.0 | (6.0) | (4.6) |
| Depreciation and depletion | 170.6 | 157.8 | 12.8 | 8.1 |
| **Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)** | **$569.7** | **$546.8** | **$22.9** | **4.2%** |

34

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $569.7 million for the nine months ended September 30, 2024, as compared with $546.8 million for the nine months ended September 30, 2023. Primary components of the change include the following (in millions):

| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income | Operating Expenses 2024 vs. 2023 |
| --- | ---: |
| Depreciation expense due to plant additions and higher depreciation rates | $12.8 |
| Labor and benefits(1) | 6.4 |
| Insurance expense, primarily due to increased wildfire risk premiums | 4.4 |
| Litigation outcome (Pacific Northwest Solar) | 2.4 |
| Property and other taxes not recoverable within trackers | 2.2 |
| Non-cash impairment of alternative energy storage investment | 1.7 |
| Electric generation maintenance | 1.3 |
| Technology implementation and maintenance expenses | 0.5 |
| Uncollectible accounts | (2.1) |
| Other | (2.4) |
| **Change in Items Impacting Net Income** | **27.2** |
| **Operating Expenses Offset Within Net Income** |  |
| Property and other taxes recovered in trackers, offset in revenue | (8.2) |
| Deferred compensation, offset in other income | 2.9 |
| Pension and other postretirement benefits, offset in other income(1) | 0.5 |
| Operating and maintenance expenses recovered in trackers, offset in revenue | 0.5 |
| **Change in Items Offset Within Net Income** | **(4.3)** |
| **Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)** | **$22.9** |

(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.

Consolidated operating income for the nine months ended September 30, 2024 was $231.6 million as compared with $197.3 million in the same period of 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, and electric retail volumes. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, natural gas retail volumes, depreciation, operating, and administrative and general costs.

Consolidated interest expense was $96.3 million for the nine months ended September 30, 2024 as compared with $85.1 million for the same period of 2023. This increase was due to higher borrowings and interest rates partly offset by higher capitalization of AFUDC.

Consolidated other income was $19.6 million for the nine months ended September 30, 2024 as compared to $12.9 million during the same period of 2023. This increase was primarily due 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 component of pension expense, and an increase in the value of deferred shares held in trust for deferred compensation, partly offset by a $2.5 million non-cash impairment of an alternative energy storage equity investment.

Consolidated income tax expense for the nine months ended September 30, 2024 was $11.4 million as compared to $14.1 million in the same period of 2023. Our effective tax rate for the nine months ended September 30, 2024 was 7.4% as compared with 11.3% for the same period in 2023. As further discussed in Note 3 - Income Taxes, during the third quarter of 2024 we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission and distribution property. This resulted in an income tax benefit of $7.0 million during the nine months ended September 30, 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years. Income tax expense for the nine months ended September 30, 2023 includes a one-time $3.2 million charge for the reduction of previously claimed alternative minimum tax credits.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

|  | Nine Months Ended September 30, 2024 |  | 2023 |  |
| --- | ---: | ---: | ---: | ---: |
| Income Before Income Taxes | $155.0 |  | $125.1 |  |
| Income tax calculated at federal statutory rate | 32.5 | 21.0% | 26.3 | 21.0% |
| Permanent or flow-through adjustments: |  |  |  |  |
| State income tax, net of federal provisions | 0.7 | 0.5 | 1.4 | 1.1 |
| Flow-through repairs deductions | (13.8) | (8.9) | (11.7) | (9.4) |
| Production tax credits | (7.4) | (4.8) | (5.6) | (4.5) |
| Gas repairs safe harbor method change | (7.0) | (4.5) | — | — |
| Amortization of excess deferred income tax | (0.8) | (0.5) | (1.4) | (1.1) |
| Reduction to previously claimed alternative minimum tax credit | — | — | 3.2 | 2.5 |
| Income tax return to accrual adjustment | — | — | 0.4 | 0.3 |
| Plant and depreciation flow-through items | 6.0 | 3.8 | 1.2 | 1.0 |
| Share-based compensation | 0.3 | 0.2 | 0.4 | 0.3 |
| Other, net | 0.9 | 0.6 | (0.1) | 0.1 |
|  | (21.1) | (13.6) | (12.2) | (9.7) |
| **Income tax expense** | $11.4 | 7.4% | $14.1 | 11.3% |

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.

### ELECTRIC SEGMENT

We have various classifications of electric revenues, defined as follows:

- Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory

mechanisms.

- Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
- Transmission: Reflects transmission revenues regulated by the FERC.
- Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.

### Three Months Ended September 30, 2024 Compared with the Three Months Ended September 30, 2023

*(in thousands)*

|  | Revenues 2024 | 2023 | Change $% |  | Megawatt Hours (MWH) 2024 | 2023 | Avg. Customer Counts 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Montana | $100,737 | $96,812 | $3,925 | 4.1% | 685 | 664 | 328,962 | 322,832 |
| South Dakota | 19,062 | 17,951 | 1,111 | 6.2 | 145 | 151 | 51,393 | 51,236 |
| **Residential** | **119,799** | **114,763** | **5,036** | **4.4** | **830** | **815** | **380,355** | **374,068** |
| Montana | 109,655 | 110,100 | (445) | (0.4) | 830 | 825 | 75,857 | 74,385 |
| South Dakota | 30,053 | 27,474 | 2,579 | 9.4 | 288 | 289 | 13,115 | 12,989 |
| **Commercial** | **139,708** | **137,574** | **2,134** | **1.6** | **1,118** | **1,114** | **88,972** | **87,374** |
| Industrial | 11,852 | 11,423 | 429 | 3.8 | 726 | 691 | 80 | 79 |
| Other | 14,071 | 13,243 | 828 | 6.3 | 82 | 71 | 8,274 | 8,204 |
| **Total Retail Electric** | **$285,430** | **$277,003** | **$8,427** | **3.0%** | **2,756** | **2,691** | **477,681** | **469,725** |
| Regulatory amortization | (6,805) | (18,534) | 11,729 | (63.3) |  |  |  |  |
| Transmission | 25,750 | 19,847 | 5,903 | 29.7 |  |  |  |  |
| Wholesale and Other | 2,103 | 1,714 | 389 | 22.7 |  |  |  |  |
| **Total Revenues** | **$306,478** | **$280,030** | **$26,448** | **9.4%** |  |  |  |  |
| **Fuel, purchased supply and direct transmission expense(1)** | **80,761** | **77,995** | **2,766** | **3.5** |  |  |  |  |
| **Utility Margin(2)** | **$225,717** | **$202,035** | **$23,682** | **11.7%** |  |  |  |  |

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

|  | Cooling Degree Days 2024 2023 Historic Average | 2024 as compared with: 2023 Historic Average |
| --- | ---: | --- |
| Montana | 441 396 385 | 11% warmer 15% warmer |
| South Dakota | 628 744 635 | 16% cooler 1% cooler |
|  | **Heating Degree Days** | **2024 as compared with:** |
|  | **2024** **2023** **Historic Average** | **2023** **Historic Average** |
| Montana(1) | 169 190 280 | 11% warmer 40% warmer |
| South Dakota | 39 25 76 | 56% colder 49% warmer |

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

The following summarizes the components of the changes in electric utility margin for the three months ended September 30, 2024 and 2023 (in millions):

| Utility Margin Items Impacting Net Income | Utility Margin 2024 vs. 2023 |
| --- | ---: |
| Base rates | $15.2 |
| Transmission revenue due to market conditions and rates | 5.9 |
| Retail volumes | 3.6 |
| Montana property tax tracker collections | 1.2 |
| Non-recoverable Montana electric supply costs | 0.6 |
| Other | 0.2 |
| **Change in Utility Margin Items Impacting Net Income** | 26.7 |
| **Utility Margin Items Offset Within Net Income** |  |
| Property and other taxes recovered in revenue, offset in property and other taxes | (1.9) |
| Operating expenses recovered in revenue, offset in operating and maintenance expense | (0.9) |
| Production tax credits, offset in income tax expense | (0.2) |
| **Change in Utility Margin Items Offset Within Net Income** | (3.0) |
| **Increase in Utility Margin(1)** | **$23.7** |

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Higher electric retail volumes were driven by favorable weather in Montana impacting residential demand, higher commercial and industrial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in South Dakota impacting residential 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. For the three months ended September 30, 2024, we over-collected supply costs of $5.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance). For the three months ended September 30, 2023, we over-collected supply costs of $1.0 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.1 million.

The change in regulatory amortization revenue is primarily due to timing differences between when we incur electric supply costs and property taxes and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

### Nine Months Ended September 30, 2024 Compared with the Nine Months Ended September 30, 2023

*(in thousands)*

|  | Revenues 2024 | 2023 | Change $% |  | Megawatt Hours (MWH) 2024 | 2023 | Avg. Customer Counts 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Montana | $304,128 | $306,114 | $(1,986) | (0.6)% | 2,114 | 2,103 | 327,644 | 321,797 |
| South Dakota | 53,764 | 53,408 | 356 | 0.7 | 435 | 481 | 51,395 | 51,224 |
| **Residential** | **357,892** | **359,522** | **(1,630)** | **(0.5)** | **2,549** | **2,584** | **379,039** | **373,021** |
| Montana | 310,813 | 324,632 | (13,819) | (4.3) | 2,410 | 2,435 | 75,712 | 74,294 |
| South Dakota | 84,182 | 77,736 | 6,446 | 8.3 | 834 | 834 | 13,070 | 12,972 |
| **Commercial** | **394,995** | **402,368** | **(7,373)** | **(1.8)** | **3,244** | **3,269** | **88,782** | **87,266** |
| Industrial | 34,803 | 33,986 | 817 | 2.4 | 2,190 | 1,961 | 80 | 79 |
| Other | 27,437 | 27,229 | 208 | 0.8 | 131 | 119 | 6,552 | 6,483 |
| **Total Retail Electric** | **$815,127** | **$823,105** | **$(7,978)** | **(1.0)%** | **8,114** | **7,933** | **474,453** | **466,849** |
| Regulatory amortization | 18,637 | (80,085) | 98,722 | (123.3) |  |  |  |  |
| Transmission | 70,573 | 57,092 | 13,481 | 23.6 |  |  |  |  |
| Wholesale and Other | 5,461 | 4,492 | 969 | 21.6 |  |  |  |  |
| **Total Revenues** | **$909,798** | **$804,604** | **$105,194** | **13.1%** |  |  |  |  |
| **Fuel, purchased supply and direct transmission expense(1)** | **256,989** | **198,492** | **58,497** | **29.5** |  |  |  |  |
| **Utility Margin(2)** | **$652,809** | **$606,112** | **$46,697** | **7.7%** |  |  |  |  |

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

|  | Cooling Degree Days 2024 | 2023 | Historic Average | 2024 as compared with: 2023 | Historic Average |
| --- | ---: | ---: | ---: | --- | --- |
| Montana(1) | 484 | 440 | 447 | 10% warmer | 8% warmer |
| South Dakota | 682 | 945 | 707 | 28% cooler | 4% cooler |

|  | Heating Degree Days 2024 | 2023 | Historic Average | 2024 as compared with: 2023 | Historic Average |
| --- | ---: | ---: | ---: | --- | --- |
| Montana(1) | 4,661 | 4,746 | 4,755 | 2% warmer | 2% warmer |
| South Dakota | 4,847 | 5,982 | 5,730 | 19% warmer | 15% warmer |

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

The following summarizes the components of the changes in electric utility margin for the nine months ended September 30, 2024 and 2023 (in millions):

| Utility Margin Items Impacting Net Income | Utility Margin 2024 vs. 2023 |
| --- | ---: |
| Base rates | $43.2 |
| Transmission revenue due to market conditions and rates | 13.5 |
| Montana property tax tracker collections | 3.9 |
| Retail volumes | 1.0 |
| QF liability adjustment | (4.2) |
| Non-recoverable Montana electric supply costs | (3.8) |
| Other | 1.6 |
| **Change in Utility Margin Items Impacting Net Income** | 55.2 |
| **Utility Margin Items Offset Within Net Income** |  |
| Property and other taxes recovered in revenue, offset in property and other taxes | (7.5) |
| Production tax credits, offset in income tax expense | (1.5) |
| Operating expenses recovered in revenue, offset in operating and maintenance expense | 0.5 |
| **Change in Utility Margin Items Offset Within Net Income** | (8.5) |
| **Increase in Utility Margin(1)** | **$46.7** |

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Electric retail volume impact was favorable due to higher residential usage in Montana due to favorable weather, higher industrial volumes, and customer growth, partly offset by lower residential usage in South Dakota due to unfavorable weather, and lower commercial demand.

Under the PCCAM, net supply costs higher or lower than the PCCAM Base (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the nine months ended September 30, 2024, we under-collected supply costs of $10.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance). For the nine months ended September 30, 2023, we over-collected supply costs of $23.5 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.6 million.

The adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, as further explained above in the consolidated results of operations for the nine months ended September 30, 2024.

The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

### NATURAL GAS SEGMENT

We have various classifications of natural gas revenues, defined as follows:

- Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
- Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
- Wholesale: Primarily represents transportation and storage for others.

### Three Months Ended September 30, 2024 Compared with the Three Months Ended September 30, 2023

*(in thousands)*

|  | Revenues 2024 | 2023 | Change $% |  | Dekatherms (Dkt) 2024 | 2023 | Avg. Customer Counts 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Montana | $8,422 | $9,603 | $(1,181) | (12.3)% | 739 | 825 | 185,578 | 183,586 |
| South Dakota | 1,745 | 1,987 | (242) | (12.2) | 108 | 102 | 42,389 | 41,821 |
| Nebraska | 1,791 | 2,251 | (460) | (20.4) | 143 | 138 | 37,834 | 37,580 |
| **Residential** | **11,958** | **13,841** | **(1,883)** | **(13.6)** | **990** | **1,065** | **265,801** | **262,987** |
| Montana | 6,190 | 6,136 | 54 | 0.9 | 609 | 622 | 26,094 | 25,657 |
| South Dakota | 1,262 | 1,498 | (236) | (15.8) | 225 | 208 | 7,336 | 7,184 |
| Nebraska | 795 | 1,291 | (496) | (38.4) | 134 | 142 | 5,009 | 4,970 |
| **Commercial** | **8,247** | **8,925** | **(678)** | **(7.6)** | **968** | **972** | **38,439** | **37,811** |
| Industrial | 115 | 106 | 9 | 8.5 | 15 | 13 | 238 | 231 |
| Other | 169 | 160 | 9 | 5.6 | 23 | 19 | 196 | 191 |
| **Total Retail Gas** | **$20,489** | **$23,032** | **$(2,543)** | **(11.0)%** | **1,996** | **2,069** | **304,674** | **301,220** |
| Regulatory amortization | 8,025 | 7,458 | 567 | (7.6) |  |  |  |  |
| Wholesale and other | 10,169 | 10,570 | (401) | (3.8) |  |  |  |  |
| **Total Revenues** | **$38,683** | **$41,060** | **$(2,377)** | **(5.8)%** |  |  |  |  |
| **Fuel, purchased supply and direct transmission expense(1)** | **7,127** | **10,948** | **(3,821)** | **(34.9)** |  |  |  |  |
| **Utility Margin(2)** | **$31,556** | **$30,112** | **$1,444** | **4.8%** |  |  |  |  |

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

|  | Heating Degree Days 2024 | 2023 | Historic Average | 2024 as compared with: 2023 | Historic Average |
| --- | ---: | ---: | ---: | --- | --- |
| Montana(1) | 203 | 226 | 319 | 10% warmer | 36% warmer |
| South Dakota | 39 | 25 | 76 | 56% colder | 49% warmer |
| Nebraska | 7 | 15 | 33 | 53% warmer | 79% warmer |

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

The following summarizes the components of the changes in natural gas utility margin for the three months ended September 30, 2024 and 2023:

*(in millions)*

| Utility Margin Items Impacting Net Income | Utility Margin 2024 vs. 2023 |
| --- | ---: |
| Base rates | $2.0 |
| Montana natural gas transportation | 0.9 |
| Montana property tax tracker collections | 0.3 |
| Retail volumes | (0.3) |
| Other | (1.4) |
| **Change in Utility Margin Items Impacting Net Income** | 1.5 |
| **Utility Margin Items Offset Within Net Income** |  |
| Property and other taxes recovered in revenue, offset in property and other taxes | (0.1) |
| **Change in Utility Margin Items Offset Within Net Income** | (0.1) |
| **Increase in Utility Margin(1)** | **$1.4** |

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

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

### Nine Months Ended September 30, 2024 Compared with the Nine Months Ended September 30, 2023

*(in thousands)*

|  | Revenues 2024 | 2023 | Change $% |  | Dekatherms (Dkt) 2024 | 2023 | Avg. Customer Counts 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Montana | $75,933 | $94,074 | $(18,141) | (19.3)% | 9,220 | 9,206 | 185,412 | 183,584 |
| South Dakota | 21,244 | 30,297 | (9,053) | (29.9) | 2,113 | 2,557 | 42,477 | 41,962 |
| Nebraska | 16,106 | 30,221 | (14,115) | (46.7) | 1,812 | 2,053 | 37,924 | 37,752 |
| **Residential** | **113,283** | **154,592** | **(41,309)** | **(26.7)** | **13,145** | **13,816** | **265,813** | **263,298** |
| Montana | 42,016 | 52,393 | (10,377) | (19.8) | 5,307 | 5,456 | 26,112 | 25,679 |
| South Dakota | 14,283 | 21,289 | (7,006) | (32.9) | 2,139 | 2,385 | 7,353 | 7,218 |
| Nebraska | 8,982 | 19,119 | (10,137) | (53.0) | 1,328 | 1,528 | 5,045 | 5,017 |
| **Commercial** | **65,281** | **92,801** | **(27,520)** | **(29.7)** | **8,774** | **9,369** | **38,510** | **37,914** |
| Industrial | 703 | 995 | (292) | (29.3) | 98 | 107 | 237 | 231 |
| Other | 1,036 | 1,282 | (246) | (19.2) | 156 | 155 | 196 | 189 |
| **Total Retail Gas** | **$180,303** | **$249,670** | **$(69,367)** | **(27.8)%** | **22,173** | **23,447** | **304,756** | **301,632** |
| Regulatory amortization | 18,686 | (21,312) | 39,998 | (187.7) |  |  |  |  |
| Wholesale and other | 31,645 | 33,172 | (1,527) | (4.6) |  |  |  |  |
| **Total Revenues** | **$230,634** | **$261,530** | **$(30,896)** | **(11.8)%** |  |  |  |  |
| **Fuel, purchased supply and direct transmission expense(1)** | **82,100** | **123,521** | **(41,421)** | **(33.5)** |  |  |  |  |
| **Utility Margin(2)** | **$148,534** | **$138,009** | **$10,525** | **7.6%** |  |  |  |  |

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

|  | Heating Degree Days 2024 | 2023 | Historic Average | 2024 as compared with: 2023 | Historic Average |
| --- | ---: | ---: | ---: | --- | --- |
| Montana(1) | 4,792 | 4,855 | 4,854 | 1% warmer | 1% warmer |
| South Dakota | 4,847 | 5,982 | 5,730 | 19% warmer | 15% warmer |
| Nebraska | 3,985 | 4,521 | 4,501 | 12% warmer | 11% warmer |

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

The following summarizes the components of the changes in natural gas utility margin for the nine months ended September 30, 2024 and 2023:

*(in millions)*

| Utility Margin Items Impacting Net Income | Utility Margin 2024 vs. 2023 |
| --- | ---: |
| Base rates | $10.2 |
| Montana natural gas transportation | 1.9 |
| Montana property tax tracker collections | 1.0 |
| Retail volumes | (2.7) |
| Other | 0.8 |
| **Change in Utility Margin Items Impacting Net Income** | 11.2 |
| **Utility Margin Items Offset Within Net Income** |  |
| Property and other taxes recovered in revenue, offset in property tax expense | (0.7) |
| **Change in Utility Margin Items Offset Within Net Income** | (0.7) |
| **Increase in Utility Margin(1)** | **$10.5** |

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

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

### LIQUIDITY AND CAPITAL RESOURCES

### Liquidity

We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 16 - Common Stock in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 for further information regarding these dividend restrictions. As of September 30, 2024, we are in compliance with these provisions.

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

As of September 30, 2024, our total net liquidity was approximately $316.5 million, including $2.5 million of cash and $314.0 million of revolving credit facility availability with no letters of credit outstanding.

### Cash Flows

The following table summarizes our consolidated cash flows (in millions):

| Operating Activities | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: |
| Net income | $143.6 | $111.0 |
| Non-cash adjustments to net income | 175.3 | 141.1 |
| Changes in working capital | 35.9 | 194.5 |
| Other noncurrent assets and liabilities | (10.9) | (19.6) |
| **Cash Provided by Operating Activities** | **343.9** | **427.0** |
| **Investing Activities** |  |  |
| Property, plant and equipment additions | (400.5) | (407.2) |
| Investment in equity securities | (4.6) | (3.8) |
| **Cash Used in Investing Activities** | **(405.1)** | **(411.0)** |
| **Financing Activities** |  |  |
| Proceeds from issuance of common stock, net | — | 73.6 |
| Issuance of long-term debt | 215.0 | 300.0 |
| Issuances of short-term borrowings | 100.0 | — |
| Line of credit repayments, net | (32.0) | (273.0) |
| Repayments on long-term debt | (100.0) | — |
| Dividends on common stock | (118.9) | (115.0) |
| Other financing activities, net | (0.2) | (2.4) |
| **Cash Provided by (Used in) Financing Activities** | **63.9** | **(16.8)** |
| **Increase (decrease) in Cash, Cash Equivalents, and Restricted Cash** | **2.7** | **(0.8)** |
| Cash, Cash Equivalents, and Restricted Cash, beginning of period | 25.2 | 22.5 |
| **Cash, Cash Equivalents, and Restricted Cash, end of period** | **$27.9** | **$21.7** |

### Operating Activities

As of September 30, 2024, cash, cash equivalents, and restricted cash were $27.9 million as compared with $25.2 million as of December 31, 2023 and $21.7 million as of September 30, 2023. Cash provided by operating activities totaled $343.9 million for the nine months ended September 30, 2024 as compared with $427.0 million during the nine months ended September 30, 2023. As shown in the table below, this decrease in operating cash flows is primarily due to significant net cash inflows in the prior period from the recovery of previously under-collected energy supply costs, compared to minimal net cash inflows for energy supply costs in the current period due to the timely recovery of energy supply costs.

| Uncollected energy supply costs (in millions) Beginning of period End of period | Net cash inflows (outflows) |
| --- | ---: |
| **2023** $115.4 $16.6 | $98.8 |
| **2024** $7.8 $1.8 | $6.0 |
| **Decrease in net cash inflows** | $(92.8) |

### Investing Activities

Cash used in investing activities totaled $405.1 million during the nine months ended September 30, 2024, as compared with $411.0 million during the nine months ended September 30, 2023. Plant additions during the first nine months of 2024 include maintenance additions of approximately $216.5 million and capacity related capital expenditures of $184.0 million. Plant additions during the first nine months of 2023 included maintenance additions of approximately $235.0 million and capacity related capital expenditures of approximately $172.2 million.

### Financing Activities

Cash provided by financing activities totaled $63.9 million during the nine months ended September 30, 2024, as compared with cash used in financing activities of $16.8 million during the nine months ended September 30, 2023. During the nine months ended September 30, 2024, cash provided by financing activities reflects proceeds from the issuance of debt of $215.0 million and short-term borrowings of $100.0 million, partly offset by payment of dividends of $118.9 million, repayment of 1.00 percent, $100.0 million of Montana First Mortgage Bonds, and net repayments under our revolving lines of credit of $32.0 million. During the nine months ended September 30, 2023, cash used in financing activities reflects net repayments under our revolving lines of credit of $273.0 million and payment of dividends of $115.0 million, partly offset by proceeds from the issuance of debt of $300.0 million and proceeds received from the issuance of common stock of $73.6 million.

### Cash Requirements and Capital Resources

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.

Our material cash requirements are also related to investment in our business through our capital expenditure program. Our estimated capital expenditures are discussed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As of September 30, 2024, there have been no material changes in our estimated capital expenditures. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.

### Credit Facilities

Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.

For further information on our credit facilities, see Note 10 - Unsecured Credit Facilities in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

As of September 30, 2024 and 2023 the outstanding balances of our credit facilities were $286.0 million and $177.0 million, respectively. As of October 25, 2024, the availability under our credit facilities was approximately $335.0 million, and there were no letters of credit outstanding.

### Long-term Debt and Equity

We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities.

For further information on our recent long-term debt activity, see Note 5 - Financing Activities to the Condensed Consolidated Financial Statements included herein.

We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.

### Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of October 25, 2024, our current ratings with these agencies are as follows:

| NorthWestern Energy Group | Issuer Rating | Senior Secured Rating | Senior Unsecured Rating | Outlook |
| --- | --- | --- | ---: | --- |
| Fitch(1)(2) | BBB | - | BBB | Stable |
| Moody’s | - | - | - | - |
| S&P(2) | BBB | - | - | Stable |
| **NW Corp** |  |  |  |  |
| Fitch(1)(2) | BBB | A- | BBB+ | Stable |
| Moody’s(2) | Baa2 | A3 | Baa2 | Stable |
| S&P(2) | BBB | A- | - | Stable |
| **NWE Public Service** |  |  |  |  |
| Fitch(1)(2) | BBB | A- | BBB+ | Stable |
| Moody’s(2) | Baa2 | A3 | - | Stable |
| S&P(2) | BBB | A- | - | Stable |

(1) This Fitch Issuer Rating represents the Issuer Default Rating.

(2) As part of completing the holding company reorganization, NorthWestern Energy Group and NWE Public Service received their credit ratings from these agencies in December 2023. These agencies also affirmed their ratings for NW Corp.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

### Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 30, 2024.

*(in thousands)*

|  | Total | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Long-term debt(1) | $2,880,660 | $— | $300,000 | $105,000 | $— | $465,660 | $2,010,000 |
| Finance leases | 6,327 | 866 | 3,596 | 1,865 | — | — | — |
| Short-term borrowings | 100,000 | — | 100,000 | — | — | — | — |
| Estimated pension and other postretirement obligations(2) | 47,785 | 2,937 | 11,437 | 11,137 | 11,137 | 11,137 | N/A |
| Qualifying facilities liability(3) | 247,480 | 18,528 | 60,360 | 55,393 | 56,665 | 42,400 | 14,134 |
| Supply and capacity contracts(4) | 3,279,236 | 92,481 | 331,100 | 294,228 | 275,410 | 257,802 | 2,028,215 |
| Contractual interest payments on debt(5) | 1,578,806 | 35,493 | 125,836 | 116,651 | 114,992 | 112,135 | 1,073,699 |
| Commitments for significant capital projects(6) | 34,800 | 26,817 | 7,983 | — | — | — | — |
| **Total Commitments(7)** | $8,175,094 | $177,122 | $940,312 | $584,274 | $458,204 | $889,134 | $5,126,048 |

(1) Represents cash payments for long-term debt and excludes $12.8 million of debt discounts and debt issuance costs, net.

(2) We estimate cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(3) 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 $247.5 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $221.0 million.

(4) We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC.

(5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 6.19 percent on the outstanding balance through maturity of the facilities.

(6) Represents significant firm purchase commitments for construction of planned capital projects.

(7) The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 10 - Commitments and Contingencies) and asset retirement obligations as the amount and timing of cash payments may be uncertain.

### CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. This includes the accounting for the following: regulatory assets and liabilities, pension and postretirement benefit plans and income taxes. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023. As of September 30, 2024, there have been no material changes in these policies.

## Market risk

As filed, 418 characters.

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and counterparty credit exposure. We have established comprehensive risk management policies and procedures to manage these market risks. There have been no material changes in our market risks as disclosed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

## Controls and procedures

As filed, 1,321 characters.

### Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective.

### Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 504 characters.

Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2023 for disclosure of the risk factors that could have a significant impact on our business, financial condition, results of operations or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not changed materially since such disclosure.

Filed Oct 29, 2024.
Source: SEC EDGAR, the filing index for accession 0001993004-24-000102. Last ingested by Listed: Nov 6, 2026, 17:53 ET. No prices; not investment advice.