What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-02-13 compared with 2024-02-15 · 185 added, 166 removed, 459 unchanged (43% of the section changed)

27 unchanged sentences

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.

In 2023, approximately 55 percent of our retail needs from our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 40 percent for the total U.S.

In 2024, approximately 58 percent of our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 41 percent for the total U.S.

electric power industry.

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(in millions)

Year ended December 31, 2022 $ 182.4 $ 0.6 $ 183.0

December 31, 2023 $ 201.6 $ (7.5) $ 194.1

Variance in revenue and fuel, purchased supply, and direct transmission expense (1) items impacting net income:

Montana rate review - new base rates

Base rates 62.4 (15.8) 46.6

Electric transmission revenue

18.6 (4.7) 13.9

Lower non-recoverable Montana electric supply costs 14.2 (3.6) 10.6

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

Montana natural gas transportation 2.3 (0.6) 1.7

Montana property tax tracker collections 1.1 (0.3) 0.8

Higher Montana natural gas transportation 2.2 (0.6) 1.6

Higher electric transmission revenue 0.6 (0.2) 0.4

Lower natural gas retail volumes (7.0) 1.8 (5.2)

Lower electric retail volumes (1.8) 0.5 (1.3)

Higher revenue from lower production tax credits, offset within income tax benefit (expense) 3.8 (3.8) —

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

Non-recoverable Montana electric supply costs

(7.9) 2.0 (5.9)

QF liability adjustment

(4.2) 1.1 (3.1)

Natural gas retail volumes

(4.0) 1.0 (3.0)

Electric retail volumes

(0.9) 0.2 (0.7)

Other (3.2) 0.8 (2.4)

Variance in expense items (2) impacting net income:

Higher depreciation expense (15.5) 3.9 (11.6)

Higher interest expense (14.5) 3.7 (10.8)

Higher operating, maintenance, and administrative expenses (14.4) 3.6 (10.8)

Lower property and other taxes not recoverable within trackers 3.0 (0.8) 2.2

Operating, maintenance, and administrative

(19.4) 4.9 (14.5)

(17.1) 4.3 (12.8)

Interest expense

(17.1) 4.3 (12.8)

Property and other taxes not recoverable within trackers

(4.4) 1.1 (3.3)

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

Gas repairs safe harbor method change

Other 1.9 (4.8) (2.9)

Year ended December 31, 2023 $ 201.6 $ (7.5) $ 194.1

December 31, 2024 $ 214.7 $ 9.4 $ 224.1

Change in Net Income $ 30.0

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Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023.

This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, higher interest expense, higher operating, maintenance, and administrative expenses, and higher income tax expense.

This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenue, and income tax benefits from a change to the gas repairs safe harbor method and a reduction to our unrecognized tax benefits.

These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

SIGNIFICANT TRENDS AND REGULATION

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We regularly review the need for electric and natural gas rate relief in each state in which we provide service.

Montana Rate Review Filing – On October 27, 2023, the MPSC issued a final order approving the settlement agreement filed April 3, 2023.

Final rates, adjusting from interim to settled rates, were effective November 1, 2023.

For additional information related to our Montana Rate Review Filing, see Note 3 - Regulatory Matters to the Consolidated Financial Statements.

South Dakota Electric Rate Review Filing – In June 2023, we filed a South Dakota electric rate review filing (2022 test year) for an annual increase to electric rates totaling approximately $30.9 million.

Our request was based on a rate of return of 7.54 percent, a capital structure including 50.5 percent equity, and rate base of $787.3 million.

In January 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $21.5 million and an authorized rate of return of 6.81 percent.

The approved settlement is based on a capital structure of 50.5 percent equity and a rate base of $791.8 million.

Final rates were effective January 10, 2024.

In addition, the SDPUC approved a phase in rate plan rider that allows for the recovery of capital investments not yet included in base rates.

Holding Company Reorganization – On October 2, 2023, NW Corp and NorthWestern Energy Group completed a merger transaction pursuant to which NorthWestern Energy Group became the holding company parent of NW Corp.

In this reorganization, shareholders of NW Corp (the predecessor publicly held parent company) became shareholders of NorthWestern Energy Group, maintaining the same number of shares and ownership percentage as held in NW Corp immediately prior to the reorganization.

NW Corp became a wholly-owned subsidiary of NorthWestern Energy Group.

The transaction was effected pursuant to a merger pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the shareholders of the constituent corporation.

Immediately after consummation of the reorganization, NorthWestern Energy Group had, on a consolidated basis, the same assets, businesses and operations as NW Corp had immediately prior to the consummation of the reorganization.

As a result of the reorganization, NorthWestern Energy Group became the successor issuer to NW Corp pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, and as a result, NorthWestern Energy Group's common stock was deemed registered under Section 12(b) of the Securities Exchange Act of 1934.

On January 1, 2024, we completed the second and final phase of the holding company reorganization.

NW Corp contributed the assets and liabilities of its South Dakota and Nebraska regulated utilities to NWE Public Service, and then distributed its equity interest in NWE Public Service and certain other subsidiaries to NorthWestern Energy Group, resulting in NW Corp owning and operating the Montana regulated utility and NWE Public Service owning and operating the Nebraska and South Dakota utilities, each as a direct subsidiary of NorthWestern Energy Group.

Power Costs and Credits Adjustment Mechanism - The MPSC's September 2022 decision approving interim rates related to our Montana rate review included a $61.1 million increase to the PCCAM Base, from $138.7 million to $199.8 million, effective October 1, 2022.

The MPSC's October 2023 decision approving the Montana rate review settlement agreement increased the PCCAM Base to $208.4 million, with retroactive application to July 1, 2022.

We have under-collected our total Montana electric supply costs for the July 2022 through June 2023 PCCAM year by approximately $14.5 million, which includes a $2.9 million increase to our under-collection for this tracker period to reflect the retroactive application of the higher PCCAM Base rates effective July 1, 2022.

As of December 31, 2023, we have over-collected our total Montana electric supply costs for the July 2023 through June 2024 PCCAM year by approximately $4.7 million.

Under the PCCAM, net costs higher or lower than the PCCAM Base (excluding QF costs) are allocated 90 percent to Montana customers and 10 percent to shareholders.

For the twelve months ended December 31, 2023, we over collected supply costs of $32.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $7.0 million (10 percent of the PCCAM Base cost variance), which is inclusive of a $3.2 million increase in pre-tax earnings related to the retroactive application of higher PCCAM Base rates to July 1, 2022.

For the twelve months ended December 31, 2022, we under collected costs of $64.8 million resulting in an increase to the under collection of costs, and recorded a reduction in pre-tax earnings of $7.2 million.

As discussed above, the approved Montana rate review settlement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery.

The updated $208.4 million PCCAM Base is retroactive to an effective date of July 1, 2022.

Our electric supply from owned and long-term contracted resources is not adequate to meet our peak-demand needs.

Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows.

See the Electric Resource Planning - Montana section below for how we are working to address this market exposure.

Our ongoing rate review activity includes the following:

Montana Rate Review - In July 2024, we filed a Montana electric and natural gas rate review (2023 test year) with the MPSC.

The filing requests a base rate annual revenue increase of $156.5 million ($69.4 million net with Property Tax and PCCAM tracker adjustments) for electric and $28.6 million for natural gas.

Our request is based on a return on equity of 10.80 percent with a capital structure including 46.81 percent equity, and forecasted 2024 electric and natural gas rate base of $3.45 billion and $731.9 million, respectively.

The electric rate base investment includes the 175-megawatt natural gas-fired Yellowstone County Generating Station, which was placed in service in October 2024.

In November 2024, the MPSC partially approved our requested interim rates, which are subject to refund, increasing electric and natural gas base rates by $18.4 million and $17.4 million, respectively, and decreasing our PCCAM base costs by $88.0 million, effective December 1, 2024.

In January 2025, intervenor testimony was filed and we anticipate filing our rebuttal testimony in March 2025.

Based on the procedural schedule developed by the MPSC, a hearing on our rate review request is scheduled to commence on April 22, 2025.

If a final order is not received by May 23, 2025, which is 270 days from acceptance of our filing, we intend to implement our requested rates as permitted by the MPSC regulations, which will be subject to refund until a final order is received.

South Dakota Natural Gas Rate Review - In June 2024, we filed a natural gas rate review (2023 test year) with the SDPUC for an annual increase to natural gas rates totaling approximately $6.0 million.

Our request was based on a rate of return of 7.75 percent and rate base of $95.6 million.

In December 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $4.6 million and an authorized rate of return of 6.91 percent.

The approved settlement is based on a rate base of $96.2 million.

Final rates were effective December 19, 2024.

Nebraska Natural Gas Rate Review - In June 2024, we filed a natural gas rate review (2023 test year) with the NPSC.

The filing requests a base rate annual revenue increase of $3.6 million.

Our request is based on a return on equity of 10.70 percent, a capital structure including 53.13 percent equity, and rate base of $47.4 million.

Interim rates, which increased base natural gas rates $2.3 million, were implemented on October 1, 2024.

Interim rates will remain in effect on a refundable basis until the NPSC issues a final order.

Electric Resource Planning - Montana

Yellowstone County 175 MW plant - Construction of the new generation facility continues to progress and we expect the plant to be operational no later than the end of the third quarter 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 December 31, 2023, total costs of approximately $240.0 million have been incurred, with expected total costs of approximately $310.0 million to $320.0 million.

Yellowstone County 175 MW plant - Construction of the generation facility was substantially completed and the plant placed in service in October 2024.

As of December 31, 2024, we have incurred $305.5 million of generation plant costs and $12.1 million of non-generation plant costs related to YCGS.

On January 3, 2025, the Montana Supreme Court ordered that the YCGS air quality permit be reinstated.

See Note 1 8 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.

Acquisition of Colstrip Interest - On January 16, 2023, we entered into a definitive agreement (the Avista Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana.

The Avista Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the Avista Agreement.

Under the terms of this Avista Agreement, we will be responsible for operating costs starting on January 1, 2026;

while Avista 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 Avista's interest.

The Avista Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Avista Agreement is subject to customary conditions and approvals, including approval from the FERC.

Closing also is conditioned on our ability to enter into a new coal supply agreement for Colstrip by December 31, 2024.

Such coal supply agreement must provide a sufficient amount of coal to Colstrip to permit the generation of electric power by the maximum permitted capacity of the interest in Colstrip then held by us during the period from January 1, 2026 through, December 31, 2030.

Either party may terminate the Avista Agreement if any requested regulatory approval is denied or if the closing has not occurred by December 31, 2025 or if any law or order would delay or impair closing.

The acquisition of an additional interest under this Avista Agreement in 2026 will provide capacity to help us meet our obligation to provide reliable and cost effective power to our customers in Montana, while allowing opportunity for us to identify and plan for newer technologies to provide reliable, affordable and carbon free power through our IRP process.

Future Integrated Resource Planning - Resource adequacy in the Western third of the U.S.

has been declining with the retirement of thermal power plants.

Our owned and long-term contracted resources are inadequate to supply the necessary capacity we require to meet our peak-demand loads, which exposes us to large quantities of market purchases at typically high and volatile energy prices.

To comply with regulatory resource planning requirements, we submitted an IRP to the MPSC on April 28, 2023.

We remain concerned regarding an overall lack of capacity in the West and our owned and long-term contracted capacity deficit to meet peak-demand loads.

The construction of the Yellowstone County Generating Station and acquisition of Avista's Colstrip Units 3 and 4 interests are expected to reduce our exposure to market purchases.

Proposed EPA Rules

In May 2023, the EPA proposed new GHG emissions standards for coal and natural gas-fired plants.

In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired);

(ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units);

and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired).

In addition, in April 2023, EPA proposed to amend the MATS.

Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units.

We are in compliance with existing MATS requirements.

The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic.

Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted.

As MATS and GHG regulations are implemented, it could result in additional material compliance costs.

We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region.

Electric Resource Supply - South Dakota

Our electric supply resource plans for South Dakota continue to identify portfolio requirements including potential investments resulting from a completed competitive solicitation process.

We anticipate filing the next resource plan in the summer of 2024.

Acquisition of Colstrip Interests - As previously disclosed, in January 2023 and in July 2024, we entered into definitive agreements, the first with Avista Corporation (Avista) and the second with Puget Sound Energy (Puget), to acquire their respective interests in Colstrip Units 3 & 4 for $0.

In particular, we agreed to acquire a 15% (222 megawatts) interest from Avista and a 25% (370 megawatts) interest from Puget.

These agreements are substantially similar and are both scheduled to close December 31, 2025, subject to the satisfaction of customary closing conditions and approvals contained within the agreements.

Under the terms of the agreements, we will be responsible for operating costs starting on January 1, 2026;

while Puget and Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommission and demolition costs associated with the existing facilities that comprise their interests.

Acquisition of Avista and Puget's interests would result in our ownership of 55 percent of the facility with the ability to guide operating and maintenance investments.

This would provide capacity to help us meet our obligation to provide reliable and cost effective power to our customers in Montana, while allowing opportunity for us to identify and plan for newer lower or no-carbon technologies in the future.

In April 2024, the EPA released GHG Rules for existing coal-fired facilities and new coal and natural gas-fired facilities as well as MATS Rules.

Compliance with the rules will require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities.

The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively.

However, the Trump Administration is evaluating energy related regulations impacting reliability and affordability.

See Note 1 8 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding these rules.

Acquisition of Energy West Montana Assets

In July 2024, we entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas utility distribution system and operations serving approximately 33,000 customers located near Great Falls, Cut Bank, and West Yellowstone, Montana for approximately $39.0 million, subject to certain working capital and other agreed upon closing adjustments.

The transaction is subject to a number of customary closing conditions, including MPSC approval, and we expect the acquisition to be completed in the first half of 2025.

Regional Transmission Development Activities

In August 2024, the U.S.

Department of Energy awarded a $700.0 million grant through the Grid Resilience and Innovation Partnership (GRIP) program to advance the NPC Consortium project.

The 415-mile, high-voltage direct-current transmission line is intended to connect Montana's Colstrip substation, of which we are the operator and a joint owner, to central North Dakota, bridging the eastern and western U.S.

energy grids.

The NPC Consortium includes potential upgrades to our jointly owned Colstrip Transmission System and $70.0 million of the award is earmarked for the Colstrip Transmission System Upgrade.

The NPC project, estimated to be a $3.6 billion investment, aims to enhance grid reliability, support renewable energy integration, and provide additional capacity across multiple states.

We collaborated with Grid United, the Montana Department of Commerce, and other regional utilities on the successful GRIP grant application.

In addition to the Colstrip Transmission System Upgrade, in December 2024, we signed a nonbinding memorandum of understanding (MOU) with North Plains Connector LLC, a wholly owned subsidiary of Grid United, to own 10 percent (300 megawatts) of the NPC Consortium project.

The project is entering the permitting phase and initiating regulatory filings with approvals targeted in 2026.

Construction is expected to commence in 2028, with the project expected to be operational by 2032.

Under the terms of the MOU, Grid United will continue to fund the development of the NPC and we will invest when the regulatory approvals and permits are in place.

The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region.

President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources.

This Executive Order has delayed, for up to 90 days, the disbursement of the funds granted by the U.S.

Department of Energy for the NPC Consortium project.

We have also entered into a nonbinding letter of intent with Grid United to continue transmission development to further enhance the grid through the southwest corridor of Montana.

Development to expand the southwest corridor of Montana through grid build out would represent a significant step in enhancing connectivity between Montana and the broader Western energy market - bolstering grid reliability, allowing for critical import capability, and enabling customers to access and benefit from emerging energy markets in the West.

Montana Data Centers

In December 2024, we announced two separate nonbinding letters of intent to provide electric supply services for data centers being developed in Montana.

The combined energy service requirement is expected to be 75 megawatts beginning in early 2026 with growth of up to 400 megawatts or more by 2030.

Our strategic acquisition of additional interest in Colstrip Units 3 & 4 beginning in 2026, the construction of the YCGS, and our balanced energy portfolio have enabled us to serve new large energy supply customers while continuing to provide our current customers with affordable and reliable energy.

SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES

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

Beginning in 2021, and continuing through 2025, we expect to install automated metering infrastructure in Montana at a total cost of approximately $134.0 million, of which $41.7 million remains and is reflected in the five year capital forecast above.

Beginning in 2021, we began installing automated metering infrastructure in Montana.

We expect this project to be substantially complete in 2025, with a total cost of approximately $105.0 million, of which approximately $10.0 million remains and is reflected in the five year capital forecast above.

RESULTS OF OPERATIONS

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Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment.

Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers.

Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential customers.

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

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Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023, an increase of $30.0 million.

As described in more detail below, this increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, higher interest expense, higher operating, maintenance, and administrative expenses, and higher income tax expense.

This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenue, and income tax benefits related to the gas repairs safe harbor method and a reduction in our unrecognized tax benefits.

Consolidated gross margin in 2024 was $460.8 million as compared with $416.3 million in 2023, an increase of $44.5 million or 10.7 percent.

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

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

Electric Natural Gas Total

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Utility Margin Items Impacting Net Income

Montana rate review - new base rates

Lower non-recoverable Montana electric supply costs 14.2

Base rates $ 62.4

Electric transmission revenue due to market conditions and rates 18.6

Montana interim rates (subject to refund) 4.8

Montana natural gas transportation 2.3

Montana property tax tracker collections 1.1

Higher Montana natural gas transportation 2.2

Higher electric transmission revenue due to market conditions 0.6

Lower natural gas retail volumes (7.0)

Lower electric retail volumes (1.8)

Non-recoverable Montana electric supply costs

QF liability adjustment

Natural gas retail volumes (4.0)

Electric retail volumes (0.9)

Change in Utility Margin Impacting Net Income 69.2

Utility Margin Items Offset Within Net Income

Lower property taxes recovered in revenue, offset in property tax expense (35.8)

Lower operating expenses recovered in revenue, offset in operating and maintenance expense (3.1)

Lower gas production taxes recovered in revenue, offset in property and other taxes (0.7)

Higher revenue from lower production tax credits, offset in income tax expense 3.8

Property and other taxes recovered in revenue, offset in property and other taxes 6.4

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

Production tax credits, offset in income tax expense 0.2

Change in Items Offset Within Net Income 9.0

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See "Non-GAAP Financial Measure" above.

Lower non-recoverable Montana electric supply costs were driven by higher electric supply revenues, lower electric supply costs, and $3.2 million for the retroactive application of higher PCCAM base rates approved in the Montana rate review.

Lower electric retail volumes were driven by unfavorable weather in Montana impacting residential demand and lower commercial demand as compared to the prior year, partly offset by customer growth.

Lower natural gas retail volumes were driven by unfavorable weather in Montana, partly offset by favorable weather in Nebraska and customer growth.

Lower electric residential and commercial retail volumes were driven by unfavorable weather in South Dakota impacting residential demand and lower commercial demand in all jurisdictions as compared to the prior year, partly offset by higher industrial demand and customer growth.

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

Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders.

For the twelve months ended December 31, 2024, we under-collected supply costs of $8.0 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.9 million (10 percent of the PCCAM Base cost variance).

For the twelve months ended December 31, 2023, we over collected supply costs of $32.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $7.0 million, which was inclusive of a $3.2 million increase in pre-tax earnings related to the retroactive application of higher PCCAM Base rates to July 1, 2022.

The less favorable adjustment to our electric QF liability (unrecoverable costs associated with contracts covered by the Public Utility Regulatory Policies Act of 1978 (PURPA) as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, due to a favorable adjustment in the prior year, decreasing the QF liability by $4.2 million, reflecting annual actual contract price escalation for the 2023-2024 contract year, which was less than previously estimated.

The 2023-2024 contract year was the last year of the contract that contains variable pricing terms.

Year Ended December 31,

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

Higher depreciation expense due to plant additions $ 15.5

Higher labor and benefits expense, partly offset by higher capitalization of labor and benefits costs (1)

Higher insurance expense 2.1

Increase in uncollectible accounts 1.1

Higher expenses at our electric generation facilities 1.0

Higher cost of materials 0.8

Lower property and other taxes not recoverable within trackers (3.0)

Depreciation expense due to plant additions and higher depreciation rates $ 17.1

Labor and benefits (1)

Insurance expense, primarily due to increased wildfire risk premiums 7.7

Property and other taxes not recoverable within trackers 4.4

Litigation outcome (Pacific Northwest Solar) 2.4

Electric generation maintenance 2.0

Non-cash impairment of alternative energy storage investment 1.7

Technology implementation and maintenance 1.5

Uncollectible accounts (1.4)

Change in Items Impacting Net Income 41.0

Operating Expenses Offset Within Net Income

Lower property and other taxes recovered in trackers, offset in revenue (35.8)

Lower pension and other postretirement benefits, offset in other income (1)

Lower operating expenses recovered in trackers, offset in revenue (3.1)

Lower natural gas production taxes recovered in trackers, offset in revenue (0.7)

Higher deferred compensation, offset in other income 0.1

Property and other taxes recovered in trackers, offset in revenue 6.4

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

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

Deferred compensation, offset in other income 0.7

Change in Items Offset Within Net Income 14.3

Decrease in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ (21.3)

Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 55.3

(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income.

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Consolidated operating income in 2024 was $323.3 million as compared with $300.5 million in 2023.

This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, and higher operating, maintenance, and administrative expense.

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

Consol idated interest expense in 2024 was $131.7 million, as compared with $114.6 million in 2023.

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Consolidated other income in 2024 was $23.0 million, as compared with $15.8 million in 2023.

This decrease was primarily due to an increase in the non-service cost component of pension expense, partly offset by the prior year CREP penalty and higher capitalization of AFUDC.

Consolidated income tax expense in 2023 was $7.5 million, as compared to an income tax benefit of $0.6 million in 2022.

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

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

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

As further discussed in Note 12 - Income Taxes , income tax benefit for the twelve months ended December 31, 2024, includes a $21.0 million benefit related to a reduction in our unrecognized tax benefits, inclusive of $4.1 million of previously accrued interest ($16.9 million net of interest).

Additionally, during the twelve months ended December 31, 2024, we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission and distribution property.

This resulted in an income tax benefit of $7.0 million during 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years.

Income tax expense for the twelve months ended December 31, 2023, includes a one-time $3.2 million expense for the reduction of previously claimed alternative minimum tax credits as well as a $3.2 million benefit related to a reduction in our unrecognized tax benefits.

We currently estimate our effective tax rate will range between 13.0 percent to 17.0 percent in 2025.

Based on the significant NOL we generated during the year ended December 31, 2023, we anticipate paying minimal cash for income taxes into 2028.

Based on the significant NOL income tax position we have, we anticipate paying minimal cash for income taxes into 2028.

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

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

Production tax credits (10.3) (5.1) (13.2) (7.2)

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

Release of unrecognized tax benefits

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

(21.0) (9.8) (3.2) (1.6)

Production tax credits (11.1) (5.2) (10.3) (5.1)

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

Amortization of excess deferred income taxes (2.9) (1.4) (2.2) (1.1)

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

Plant and depreciation of flow through items 9.4 4.4 6.6 3.3

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

Reduction to previously claimed alternative minimum tax credit

Prior year permanent return to accrual adjustments 0.0 0.0 (1.4) (0.8)

Other, net 1.2 0.7 (0.3) (0.1)

(54.5) (25.4) (34.9) (17.3)

Income Tax Expense (Benefit) $ 7.5 3.7 % $ (0.6) (0.3) %

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

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

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2024 2023 Historic Average 2023 Historic Average

Montana 441 602 455 27% cooler 3% cooler

South Dakota 1,035 953 752 9% warmer 38% warmer

Montana 485 441 448 10% warmer 8% warmer

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

Heating Degree Days 2024 as compared with:

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

South Dakota 7,665 7,687 7,675 remained flat remained flat

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

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

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Utility Margin Items Impacting Net Income

Montana rate review - new electric base rates

Lower non-recoverable Montana electric supply costs 14.2

Base rates $ 51.0

Electric transmission revenue due to market conditions and rates 18.6

Montana interim rates (subject to refund) 2.8

Montana property tax tracker collections 1.2

Higher electric transmission revenue due to market conditions 0.6

Non-recoverable Montana electric supply costs (7.9)

QF liability adjustment (4.2)

Lower retail volumes (1.8)

Retail volumes (0.9)

Change in Utility Margin Items Impacting Net Income 59.7

Utility Margin Items Offset Within Net Income

Lower property taxes recovered in revenue, offset in property tax expense (28.1)

Lower operating expenses recovered in revenue, offset in operating and maintenance expense (3.3)

Higher revenue from lower production tax credits, offset in income tax expense 3.8

Property and other taxes recovered in revenue, offset in property and other taxes 3.4

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

Production tax credits, offset in income tax expense 0.2

Change in Items Offset Within Net Income 5.3

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

Lower retail volumes were driven by unfavorable weather in Montana impacting residential demand and lower commercial demand as compared to the prior year, partly offset by customer growth.

The adjustment to our electric QF liability (unrecoverable costs associated with contracts covered by the Public Utility Regulatory Policies Act of 1978 (PURPA) as part of a 2002 stipulation with the MPSC and other parties) reflects a $5.0 million gain in 2023, as compared with a $5.1 million gain for the same period in 2022, due to the combination of:

• A $0.8 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $1.8 million favorable reduction in costs in the prior period;

• A favorable adjustment, decreasing the QF liability by $4.2 million, reflecting annual actual contract price escalation for the 2023-2024 contract year, which was less than previously estimated.

The 2023-2024 contract year is the last year of the contract that contains variable pricing terms.

This is compared to a favorable adjustment of $3.3 million in the prior year due to less than previously estimated actual price escalation.

For the twelve months ended December 31, 2023, we over collected supply costs of $32.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $7.0 million, which was inclusive of a $3.2 million increase in pre-tax earnings related to the retroactive application of higher PCCAM Base rates to July 1, 2022.

The less favorable adjustment to our electric QF liability (unrecoverable costs associated with contracts covered by the Public Utility Regulatory Policies Act of 1978 (PURPA) as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, as further explained above in the consolidated results of operations for the twelve months ended December 31, 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.

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7,265 7,478 7,791 3% warmer 7% warmer

South Dakota 7,665 7,687 7,675 remained flat remained flat

Nebraska 5,893 5,767 6,044 2% colder 2% warmer

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

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

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

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Utility Margin Items Impacting Net Income

Base rates 11.4

Montana natural gas transportation 2.3

Montana interim rates (subject to refund) 2.0

Retail volumes (4.0)

Montana property tax tracker collections

Montana rate review - new natural gas base rates

Higher Montana natural gas transportation 2.2

Lower retail volumes (7.0)

Change in Utility Margin Impacting Net Income 9.5

Utility Margin Items Offset Within Net Income

Lower property taxes recovered in revenue, offset in property tax expense (7.7)

Lower gas production taxes recovered in revenue, offset in property and other taxes (0.7)

Higher operating expenses recovered in revenue, offset in operating and maintenance expense 0.2

Property and other taxes recovered in revenue, offset in property and other taxes 3.0

Operating expenses recovered in revenue, offset in operating and maintenance expense 0.7

Change in Items Offset Within Net Income 3.7

Decrease in Utility Margin (1)

Increase in Utility Margin (1)

(1) Non-GAAP financial measure.

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

Lower retail volumes were driven by unfavorable weather in Montana, partly offset by favorable weather in Nebraska and customer growth.

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

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

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Property, plant and equipment additions (549.3) (566.9)

Investment in equity securities (3.9) (1.7)

Other investing activity

Cash Used in Investing Activities (554.5) (570.8)

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Dividends on common stock (158.6) (154.1)

Line of credit (repayments) borrowings, net (132.0) 77.0

Line of credit borrowings (repayments), net

Financing costs (1.1) (4.3)

Other 1.1 0.6

Treasury stock activity 1.2 1.1

Cash Provided by Financing Activities 151.5 84.3

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Cash provided by operating activities totaled $406.8 million for the year ended December 31, 2024 as compared with $489.2 million for the year ended December 31, 2023.

As shown in the table below, this increase in operating cash flows is primarily due to a $123.9 million improvement in net cash inflows for previously uncollected energy supply costs and interim and final rates from our Montana rate review.

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

Net under-collected supply costs (in millions)

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Improvement in annual net cash inflows

As discussed above, on October 27, 2023 the MPSC issued their final order approving our Montana rate review settlement which included an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery.

The updated $208.4 million PCCAM Base is retroactive to an effective date of July 1, 2022.

As of December 31, 2023, we have under-collected our total Montana electric supply costs for the July 2022 through June 2023 PCCAM year by approximately $14.5 million that we began collecting in October 2023.

As of December 31, 2023, we have over-collected our total Montana electric supply costs for the July 2023 through June 2024 PCCAM year by approximately $4.7 million.

With the adjusted PCCAM Base, we anticipate continued improvements in our cash flows from operations.

However, continued higher overall market prices, which could be further exacerbated by extreme weather events, could create additional costs with deferred recovery that would offset these anticipated cash flow improvements.

Investing Activities

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As discussed above in the “Significant Infrastructure Investments and Initiatives” section, our capital expenditures are forecasted to be $531.0 million in 2024.

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

Financing Activities

Cash provided by financing activities totaled $151.5 million during the year ended December 31, 2024 as compared with $84.3 million during the year ended December 31, 2023.

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

During the year ended December 31, 2022, cash provided by financing activities reflects proceeds received from the issuance of common stock of $277.0 million and net issuances under our revolving lines of credit of $77.0 million, partly offset by payment of dividends of $140.1 million.

During the year ended December 31, 2024, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $215.0 million, short-term borrowings of $100.0 million, and net issuances under our revolving lines of credit of $95.0 million, partly offset by payment of dividends of $158.6 million and repayment of 1.00 percent, $100.0 million of Montana First Mortgage Bonds.

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

Cash Requirements and Capital Resources

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Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary.

To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.

To fund our strategic

growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.

Short-term Borrowings

For further information on our short-term borrowings, see Note 10 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein.

NorthWestern Energy Group has $100.0 million of short-term borrowings maturing in 2025, which we intend to refinance.

Credit Facilities

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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 to the Consolidated Financial Statements included herein.

For further information on our credit facilities, see Note 10 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein.

The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2024 (in millions):

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Minimum amount outstanding $ 69.0

As discussed further within Note 10 - Unsecur ed Credit Fa cilities , our credit facility availability as of December 31, 2023 was $232.0 million.

With the completion of the holding company reorganization and associated restructuring of our credit facilities on January 1, 2024, our total credit facility availability increased by $50.0 million to $282.0 million.

As of February 7, 2025, availability under our revolving credit facilities was approximately $233.0 million, and there were no letters of credit outstanding.

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

We have $100 million of debt maturing in 2024, which we intend to refinance.

We have $300.0 million of long-term debt maturing in 2025, which we intend to refinance.

For further information on our long-term debt, see Note 11 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein.

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BBB - BBB Stable

Moody’s - - - -

BBB - - Stable

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(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.

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Finance leases 5,461 3,596 1,865 — — — —

Short-term borrowings

100,000 100,000 — — — — —

Estimated pension and other postretirement obligations (2)

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(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.

(7) The table above excludes potential tax payments related to unrecognized tax benefits as they are not practicable to estimate.

Additionally, the table above excludes reserves for environmental remediation (See Note 18 - Commitments and Contingencies ) and AROs (see Note 6 - Asset Retirement Obligations ) as the amount and timing of cash payments may be uncertain.

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This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year projected benefit cash flow from our plans.

Based on this analysis as of December 31, 2023, our discount rate on both the NorthWestern Corporation pension plan and NorthWestern Energy pension plan is 4.95-5.00 percent.

Based on this analysis as of December 31, 2024, our discount rate for both NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan is 5.50 percent and 5.60 percent, respectively.

In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions.

Our expected long-term rate of return on assets assumptions are 5.15% percent and 6.65% percent on the NorthWestern Corporation and NorthWestern Energy pension plan, respectively, for 2024.

Our expected long-term rate of return on assets assumptions are 4.58% percent and 6.17% percent on the NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan, respectively, for 2025.

Cost Sensitivity

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

What changed 10-K

Item 7. Management’s Discussion and Analysis