EDGAR 10-K Filing

Company CIK: 1993004
Filing Year: 2025
Filename: 1993004_10-K_2025_0001993004-25-000021.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
OVERVIEW
NorthWestern Energy - Delivering a Bright Future
NorthWestern Energy Group, doing business as NorthWestern Energy, provides essential energy infrastructure and valuable services that enrich lives and empower communities while serving as long-term partners to our customers and communities. We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We provide electricity and / or natural gas to approximately 787,000 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. We have provided service in South Dakota and Nebraska since 1923 and in Montana since 2002.
On January 1, 2024, we completed the second and final phase of our 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.
We manage our businesses by the nature of services provided, and operate principally in two operating segments: electric utility operations and natural gas utility operations. Our electric utility operations include the generation, purchase, transmission and distribution of electricity, and our natural gas utility operations include the production, purchase, transmission, storage, and distribution of natural gas. Our customer base consists of a mix of residential, commercial, and diversified industrial customers.
Our electric and natural gas utility operations are not dependent on a single customer, or even a few customers, and the loss of any one or even a few of our largest customers is not reasonably likely to have a material adverse effect on our financial condition. Our utility operations are seasonal and weather patterns can have a material impact on operating performance. Consumption of electricity is often greater in the summer and winter months for cooling and heating, respectively. Because natural gas is used primarily for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season.
For over a century, we have upheld our commitment to providing reliable and affordable electric and natural gas services while also being good stewards of the environment. Our approach to sustainability encompasses not only environmental care but also strong corporate governance, meaningful community engagement, and a dedication to delivering long-term value for all stakeholders.
Our energy portfolio reflects a balanced mix of clean and traditional resources, ensuring we can deliver reliable electricity to customers around the clock. In 2024, approximately 58 percent of our electric portfolio-comprising owned and long-term resources-was carbon-free, exceeding the U.S. electric power industry average of 41 percent in 2023 (source: U.S. Energy Information Administration). However, our resource mix may not fully represent the actual energy delivered to customers due to market-based energy exchanges. We do not receive all of the related Renewable Energy Credits (RECs) from our contracted electric supply resources and periodically sell RECs produced by our own carbon-free energy resources. The owner of the RECs claims the renewable attributes of the energy.
Over time, we have increased our environmental sustainability efforts and our access to carbon-free energy resources. In February 2022, we made a commitment to achieving Net-Zero by the year 2050 for Scope 1 and Scope 2 carbon and methane emissions. Our Scope 1 emissions are primarily from owned electric generation plants, fugitive emissions from our natural gas production, gathering, transmission and distribution systems and company owned transportation fleet. Our Scope 2 emissions are primarily from the electric and natural gas utilized to heat, cool and power our offices, warehouses and other facilities.
Delivering affordable, reliable energy is central to our mission and reflects our responsibility to customers and the communities we serve. Our reliability standards consistently rank in the first or second quartile compared to industry peers, and our typical residential energy bills remain significantly below the national average.
We recognize that our employees are key to our success, and we are committed to providing fulfilling careers with competitive pay, excellent benefits, and a strong work-life balance. This commitment has earned us recognition from Newsweek as one of the "Great Places to Work" in 2023 and 2024.
Our governance practices underscore our dedication to ethical conduct, transparency, and accountability. We adhere to a robust Code of Conduct and Ethics that applies to employees, board members, vendors, and contractors, with additional requirements for senior leaders to ensure the highest standards of integrity in financial reporting and decision-making.
MONTANA ELECTRIC OPERATIONS
Our regulated electric utility business in Montana, which is conducted through NW Corp, includes generation, transmission and distribution. Our service territory covers approximately 107,600 square miles, representing approximately 73 percent of Montana's land area. During 2024, we delivered electricity to approximately 413,400 customers in 224 communities and their surrounding rural areas, 13 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2024, by category, residential, commercial, industrial, and other sales accounted for approximately 46%, 46%, 5%, and 3%, respectively, of our Montana retail electric utility revenue.
Transmission and Distribution
Our electric system is composed of high voltage transmission lines and low voltage distribution lines as follows:
Electric Transmission Lines
Miles of 500 kV
Miles of 230 kV 988
Miles of 161 kV 1,184
Miles of 115 kV and lower voltage 3,927
Total Miles of Electric Transmission Lines 6,596
Electric Distribution Lines
Miles of overhead line
13,282
Miles of underground line
5,512
Total Miles of Electric Distribution Lines 18,794
Total Transmission and Distribution Substations 396
In addition to delivering energy to distribution systems to serve customers, we also transmit electricity for nonregulated entities owning generation, and utilities, cooperatives, and power marketers serving the Montana electricity market. Our total control area peak demand reached a peak of approximately 2,079 MWs on January 13, 2024. Our control area average demand for 2024 was approximately 1,372 MWs per hour, with total energy delivered of approximately 11.53 million MWHs.
Our transmission system is directly interconnected with Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; WAPA; and Montana Alberta Tie. Such interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase, and sale of power among all major electric systems in the west interconnecting with the winter-peaking northern and summer-peaking southern regions of the western power system. We provide wholesale transmission service and firm and non-firm transmission services for eligible transmission customers pursuant to our FERC OATT.
Electric Supply
Our annual retail electric supply load requirement averages approximately 759 MWs per day, with a peak load of approximately 1,300 MWs, and are supplied by owned and contracted resources and market purchases with multiple counterparties.
Owned generation resources supplied approximately 65 percent of our retail load requirements for 2024. We expect that approximately 81 percent of our retail obligations will be met by owned generation resources in 2025, reflecting the full year addition of YCGS which was placed into service in October 2024. In addition, we have contracts with QFs totaling 556 MWs of nameplate capacity, including 94 MWs from waste petroleum coke and waste coal, 268 MWs from wind, 17 MWs from hydro, and 177 MWs from solar projects. We have several other long-term power purchase agreements including contracts for 135 MWs nameplate capacity from wind generation, 310 MWs from unspecified resources, 52 MWs of natural gas generation, and 13 MWs of hydro supply. Load requirements during peak demand in excess of our owned and long-term contracted resources will be satisfied with market purchases.
Owned Generation Facilities
Details of these generating facilities are described in the following tables.
Hydro Facilities COD River
Source FERC
License
Expiration Owned MW
Black Eagle 1927 Missouri 2040 25
Cochrane 1958 Missouri 2040 64
Hauser 1911 Missouri 2040 22
Holter 1918 Missouri 2040 53
Madison 1906 Madison 2040 12
Morony 1930 Missouri 2040 49
Rowe(1)
1925 West Rosebud Creek 2050 12
Rainbow 1910/2013 Missouri 2040 64
Ryan 1915 Missouri 2040 72
Thompson Falls 1915/1995 Clark Fork 2025(2)
Total(3)
(1) The FERC Project is still called Mystic Lake, one of the 3 dams is now called Rowe Dam
(2) We are in the process of relicensing the Thompson Falls hydro facility. We anticipate that the FERC will issue an annual license for 2026, and that this annual license will renew on an annual basis until our relicensing proceeding is complete.
(3) The Hebgen facility (0 MW net capacity) is excluded from the figures above. These are run-of-river dams except for Mystic, Cochrane, Ryan and Morony.
Other Facilities Fuel Source Ownership
Interest Owned
MW
Colstrip Unit 4, located near Colstrip in southeastern Montana Sub-bituminous coal 30% 222
DGGS, located near Anaconda, Montana Natural Gas & Liquid Fuel 100% 150
YCGS, located near Laurel, Montana Natural Gas 100% 175
Spion Kop Wind, located in Judith Basin County in Montana Wind 100% 40
Two Dot Wind, located in Wheatland County in Montana Wind 100% 11
Colstrip Unit 4 provides base-load supply and is operated by Talen Montana, LLC (Talen). Talen has a 30 percent ownership interest in Colstrip Unit 3. We have a reciprocal sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15 percent of the respective combined output and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or 4. However, each party is responsible for its own fuel-related costs. Colstrip Unit 4 is supplied with fuel from adjacent coal reserves under a coal supply agreement in effect through 2025. See Item 1A Risk Factors "Regulatory, Legislative and Legal Risks" for further discussion regarding the service life of generation facilities.
Resource Planning
Resource planning is an important function necessary to meet our customers' future energy needs and is used to guide resource acquisition activities. We filed our latest resource plan with the MPSC in April of 2023. The filing showed a capacity adequate resource portfolio in the near term that included an online date of the YCGS in 2024 and the acquisition of an additional 222 MW of capacity in Colstrip in 2026. In July of 2024, NorthWestern announced that an additional 370 MW would be acquired at Colstrip in 2026. These two additional Colstrip acquisitions would increase NorthWestern’s current Colstrip ownership from 222 MW to 814 MW, effective January 1, 2026. For additional information regarding the acquisition of additional Colstrip capacity, see Note 5 - Property, Plant, and Equipment, to the Consolidated Financial Statements.
In addition to our responsibility to meet peak demand, national NERC reliability standards increased the need for us to have greater dispatchable generation capacity available and be capable of increasing or decreasing output to address intermittent generation such as wind and solar. Our generation portfolio is a balanced mix of energy and capacity resources having different operating characteristics and fuel sources designed to provide energy at the lowest possible cost to meet our obligation to serve retail customers while maintaining reliability.
Western Energy Imbalance Market
We entered the Western Energy Imbalance Market (EIM), operated by the California Independent System Operator, on June 16, 2021. We have EIM transfer capability with PacifiCorp, Idaho Power Company, Bonneville Power Administration, Avista Corp, and Tacoma Power.
SOUTH DAKOTA ELECTRIC OPERATIONS
Our South Dakota electric utility business, which is conducted through NWE Public Service, operates as a vertically integrated generation, transmission and distribution utility. We have the exclusive right to serve an area in South Dakota comprised of 25 counties. We provide retail electricity to more than 65,300 customers in 117 communities in South Dakota. In 2024, by category, residential, commercial and other sales accounted for approximately 38%, 60%, and 2%, respectively, of our South Dakota retail electric utility revenue.
Transmission and Distribution
Our electric system includes high voltage transmission and low voltage distribution lines as follows:
Electric Transmission Lines
Miles of 345 kV
Miles of 230 kV 18
Miles of 115 kV and lower voltages
1,306
Total Miles of Electric Transmission Lines 1,349
Electric Distribution Lines
Miles of overhead line
1,630
Miles of underground line
Total Miles of Electric Distribution Lines 2,386
Total Transmission and Distribution Substations 123
Our South Dakota system is interconnected with the transmission facilities of Otter Tail Power Company; Montana-Dakota Utilities Co.; Xcel Energy Inc.; and WAPA. We also have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative.
We are a transmission-owning member in the SPP, with our transmission facilities residing in zone 19 of the SPP footprint. Each year, we review all new or modified transmission assets and transfer functional control of assets that qualify under the SPP Tariff to the SPP. This annual update goes into effect on April 1st each year. To date, we have transferred control of 333 line miles of 115 kV facilities and over 158 line miles of 69 kV facilities. Along with SPP, our South Dakota facilities have ties to MISO. We have grandfathered agreements in MISO, which provide us the access to move the power from the Coyote, Big Stone, and Neal power plants to our customers. Along with operating the transmission system, SPP also coordinates regional transmission planning for all of its members on an annual basis through its Integrated Transmission Planning (ITP) process. Our annual participation in the ITP process includes model development, system needs assessment, and solution development to address identified needs.
Electric Supply
Our annual retail electric supply load requirements average approximately 200 MWs, with a peak load of approximately 325 MWs, and are supplied by owned and contracted resources and market purchases. We use market purchases and peaking generation to provide peak supply in excess of our base-load capacity. We are a member of the SPP. As a market participant in SPP, we buy and sell wholesale energy and reserves in both day-ahead and real-time markets through the operation of a single, consolidated SPP balancing authority. We and other SPP members submit into the SPP market both offers to sell our generation and bids to purchase power to serve our load. SPP optimizes next-day and real-time generation dispatch across the region and provides participants with greater access to economic energy. Marketing activities in SPP are handled for us by a third-party provider acting as our agent.
Electric supply resources include 211 MWs from jointly owned coal plants and 138 MWs from two natural gas-fired plants. Additional resources include several peaking units and an 80 MW wind facility. We also purchase the output of four wind projects, three of which are QFs, under power purchase agreements. Actual output for our wind resources varies based upon weather conditions.
Owned Generation Facilities
Details of our generating facilities are described further in the following chart:
Generation Facilities Fuel Source Ownership
Interest Owned
MW
Big Stone Plant, located near Big Stone City in northeastern South Dakota Sub-bituminous coal 23.4% 111
Aberdeen Generating Unit No. 2, located near Aberdeen, South Dakota(1)
Natural gas & Liquid Fuel 100.0% 60
Beethoven Wind Project, located near Tripp, South Dakota Wind 100.0% 80
BGGS, located near Huron, South Dakota Natural Gas 100.0% 58
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa Sub-bituminous coal 8.7% 56
Coyote Electric Generating Station, located near Beulah, North Dakota Lignite coal 10.0% 43
Miscellaneous combustion turbine units and small diesel units (used only during peak periods) Combination of fuel oil and natural gas 100.0% 12
Total 420
(1) We are currently upgrading Aberdeen Generating Unit No. 1. Refer to the Resource Planning section below for further information.
The Big Stone, Coyote and Neal plants are owned jointly with unaffiliated parties. Each of the jointly owned plants is subject to a joint management structure, and we are not the operator of any of these plants. Based on our ownership interest, we are entitled to a proportionate share of the capacity of our jointly owned plants and are responsible for a proportionate share of the operating costs.
The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. Coyote is a mine-mouth generating facility. Neal Unit No. 4 and Big Stone receive their fuel supply via rail. The average delivered cost by type of fuel burned varies between generation facilities due to differences in transportation costs and owner purchasing power for coal supply. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs.
Resource Planning
We have a resource plan that includes estimates of customer usage and programs to provide for the economic, reliable and timely supply of energy. We continue to update our load forecast to identify the future electric energy needs of our customers, and we evaluate additional generating capacity requirements on an ongoing basis.
We submitted a plan to the SDPUC in December of 2024 that provided for the modernization of our generating fleet. That plan focused on improving reliability and flexibility. We are currently upgrading Aberdeen Generating Unit No. 1 to a 28 MW natural gas fired generating facility. This generating facility includes two simple cycle natural gas combustion turbines and we anticipate it being in service in 2026 for a total projected cost of $65.0 million.
NATURAL GAS OPERATIONS
Montana
Our regulated natural gas utility business in Montana, which is conducted through NW Corp, includes production, storage, transmission and distribution. During 2024, we distributed natural gas to approximately 214,500 customers in 121 Montana communities over a system that consists of approximately 5,200 miles of underground distribution pipelines. We also serve several smaller distribution companies that provide service to approximately 34,000 customers. We transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of approximately 50 Bcf during the year ended December 31, 2024.
Miles of Natural Gas Transmission 2,133
Miles of Natural Gas Distribution 5,221
City Gate Stations 135
We have connections in Montana with four major, unaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, and Spur Energy. Twelve compressor sites provide more than 48,600 horsepower on the transmission line and an additional 15,900 horsepower at our storage fields, capable of moving more than 400,000 dekatherms per day. In addition, we own and operate two transmission pipelines through our subsidiaries, Canadian-Montana Pipe Line Corporation and Havre Pipeline Company, LLC.
Natural gas is used primarily for residential and commercial heating, and as fuel for three electric generating facilities. The demand for natural gas largely depends upon weather conditions. Our Montana retail natural gas supply requirements for the year ended December 31, 2024, were approximately 22.4 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2024, were approximately 8.0 Bcf. We have contracted with several major producers and marketers with varying contract durations to provide the anticipated supply to meet ongoing requirements. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, short-term market purchases and owned production. Our portfolio approach to natural gas supply is intended to enable us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in significant natural gas producing regions in the United States, primarily the Rocky Mountains (Colorado), Montana, and Alberta, Canada.
Owned Production and Storage - Since 2010, we have acquired gas production and gathering system assets as a part of an overall strategy to provide rate stability and customer value: as we own these assets, which are regulated, our customers are protected from potential price spikes in the market. As of December 31, 2024, these owned reserves totaled approximately 28.2 Bcf and are estimated to provide approximately 2.6 Bcf in 2025, or approximately 11 percent of our expected annual retail natural gas load in Montana. In addition, we own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 17.85 Bcf and maximum aggregate daily deliverability of approximately 194,000 dekatherms.
South Dakota and Nebraska
Through NWE Public Service, we provide natural gas to approximately 50,500 customers in 81 South Dakota communities and approximately 43,300 customers in 4 Nebraska communities. In South Dakota, we also transport natural gas for nine gas-marketing firms and three large end-user accounts. In Nebraska, we transport natural gas for four gas-marketing firms and one large end-user account. We delivered approximately 31.4 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.7 Bcf of third-party transportation volume on our Nebraska distribution system during 2024.
Miles of Natural Gas Transmission 55
Miles of Natural Gas Distribution - South Dakota
1,796
Miles of Natural Gas Distribution - Nebraska
Our South Dakota natural gas supply requirements for the year ended December 31, 2024, were approximately 5.5 Bcf. We contract with a third party under an asset management agreement to manage transportation and storage of supply to minimize cost and price volatility to our customers. In Nebraska, our natural gas supply requirements for the year ended December 31, 2024, were approximately 4.0 Bcf. We contract with a third party under an asset management agreement that includes pipeline capacity, supply, and asset optimization activities. To supplement firm gas supplies in South Dakota and Nebraska, we contract for firm natural gas storage services to meet the heating season and peak day requirements of our customers.
Municipal Natural Gas Franchise Agreements
We have municipal franchises to provide natural gas service in the communities we serve. The terms of the franchises vary by community. Our Montana franchises typically have a fixed 10-year term and continue for additional 10-year terms unless and until canceled, with 5 years notice. The maximum term permitted under Nebraska law for these franchises is 25 years while the maximum term permitted under South Dakota law is 20 years. Our policy generally is to seek renewal or extension of a franchise in the last year of its term. We continue to serve those customers while we obtain formal renewals. During the next five years, eleven of our Montana franchises could expire by action taken by the franchises' city or town, which account for approximately 79,362 or 37.95 percent of our Montana natural gas customers. Three of our South Dakota franchises and two franchises in Nebraska, which account for approximately 39,496 or 42 percent of our South Dakota and Nebraska natural gas customers, are scheduled to reach the end of their fixed term during the next five years. We do not anticipate termination of any of these franchises.
GOVERNMENT REGULATION
Our provision of utility service is regulated by the MPSC, the SDPUC, the NPSC, and the FERC. We are also regulated by many other state and federal agencies. For example, because our operations impact land, waterways and the air, we are subject to a wide range of regulations administered by the federal EPA, the U.S. Fish & Wildlife Service, and parallel state agencies regulating environmental and natural resources in Montana, South Dakota and Nebraska. Another example relates to our provision of natural gas service. The U.S. Department of Transportation through the Pipeline and Hazardous Materials Safety Administration, along with its state partners, regulates natural gas pipeline and natural gas storage field safety. As a publicly-traded company, we are subject to the SEC’s requirements regarding financial reporting, disclosures, and laws and regulations protecting investors. We are subject to the Occupational Safety and Health Administration (OSHA), which regulates workplace safety. We are also subject to local zoning laws and regulations.
As detailed below, the rates we charge our utility customers are set through approval by the regulatory commission with jurisdiction in each of our respective service territories. Base rates are the rates that are intended to allow us the opportunity to collect from our customers total revenues (revenue requirements) equal to our cost of providing delivery and rate-based supply services, plus a reasonable rate of return on invested capital. We have both electric and natural gas base rates and cost tracking clauses. We may ask the respective regulatory commission to increase base rates from time to time. Rate increase requests are normally reviewed based on historical data and any resulting approvals may not always keep pace with increasing costs. For more information on current regulatory matters, see Note 3 - Regulatory Matters, to the Consolidated Financial Statements.
The following is a summary of our rate base (amounts we earn a return on) and authorized rates of return in each jurisdiction, estimated as of December 31, 2024:
Jurisdiction and Service Implementation Date Authorized Rate Base (millions) Year-end Estimated Rate Base (millions) Authorized Overall Rate of Return Authorized Return on Equity Authorized Equity Level
Montana electric delivery and production(1)
November 2023 $2,565.5 $3,330.9 6.72% 9.65% 48.02%
Montana - Colstrip Unit 4 November 2023 276.9 257.8 8.25% 10.00% 50.00%
Montana natural gas delivery and production(2)
November 2023 582.8 814.8 6.67% 9.55% 48.02%
Total Montana $3,425.2 $4,403.5
South Dakota electric(3)
January 2024
$791.8 $813.1 6.81% n/a n/a
South Dakota natural gas(3)(4)
December 2024 96.2 117.6 6.91% n/a n/a
Total South Dakota $888.0 $930.7
Nebraska natural gas(3)(4)
December 2007 $24.3 $52.5 8.49% 10.40% n/a
$4,337.5 $5,386.7
(1) The revenue requirement associated with the FERC regulated portion of Montana electric transmission and ancillary services are included as revenue credits to our MPSC jurisdictional customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns.
(2) The Montana gas revenue requirement includes a step down which approximates annual depletion of our natural gas production assets included in rate base.
(3) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms.
(4) In June 2024, we filed a South Dakota natural gas rate review filing (2023 test year) with the SDPUC and a Nebraska natural gas rate review filing. (2023 test year) with the NEPSC. See Note 3 - Regulatory Matters, to the Consolidated Financial Statements for additional discussion of this rate review filing.
MPSC Regulation
Our Montana operations are subject to the jurisdiction of the MPSC with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations, including when we issue, assume, or guarantee securities in Montana, or when we create liens on our regulated Montana properties. We have an obligation to provide service to our customers with an opportunity to earn a regulated rate of return.
Electric Supply Tracking Mechanism - The PCCAM tracks, for recovery through utility rates, the cost of power purchased and fuel used to generate electricity. The PCCAM incorporates sharing of a portion of the business risk or benefit associated with the energy supply costs with 90 percent of the variance above or below the established base revenues and actual costs collected from or refunded to customers. Certain PCCAM rates are adjusted on a quarterly basis for volumes and costs during
each July to June 12-month tracking period based on the established base revenues and actual costs collected from or refunded to customers. Customer prices may be adjusted annually to absorb the difference for the annual tracking period. Annual filings are based on a July through June 12-month tracking period, and are subject to review by the MPSC to determine if electric supply procurement activities were prudent. If the MPSC subsequently determines that a procurement activity was imprudent, recovery of such costs may be disallowed.
Natural Gas Supply Tracker - Rates for our Montana natural gas supply are set by the MPSC. Certain supply rates are adjusted on a monthly basis for volumes and costs during each July to June 12-month tracking period based on the established base revenues and actual costs collected from or refunded to customers. Customer prices may be adjusted annually to absorb the difference for the annual tracking period. Annual filings are based on a July through June 12-month tracking period, and are subject to review by the MPSC to determine if natural gas supply procurement activities were prudent. If the MPSC subsequently determines that a procurement activity was imprudent, recovery of such costs may be disallowed.
Montana Property Tax Tracker - We file an annual property tax tracker (including other state/local taxes and fees) with the MPSC for an automatic rate adjustment, which reflects the incremental property taxes since our last base rate filing adjusted for the associated income tax benefit.
SDPUC Regulation
Our South Dakota operations are subject to SDPUC jurisdiction with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our electric and natural gas operations. Our retail electric rates, approved by the SDPUC, provide several options for residential, commercial and industrial customers, including dual-fuel, interruptible, special all-electric heating, and other special rates. Our retail natural gas tariffs include gas transportation rates for transportation through our distribution systems by customers and natural gas marketers from the interstate pipelines at which our systems take delivery to the end-user. Such transporting customers nominate the amount of natural gas to be delivered daily. On a daily basis, we monitor usage for these customers and balance it against their respective supply agreements.
Adjustment Clauses - An electric adjustment clause provides for quarterly adjustment based on differences in the delivered cost of energy, delivered cost of fuel, ad valorem taxes paid and commission-approved fuel incentives. A purchased gas adjustment provision in our natural gas rate schedules permits the monthly adjustment of charges to customers to reflect increases or decreases in purchased gas, gas transportation, and ad valorem taxes. The adjustment clauses for both electric and gas utilities go into effect upon filing, and are deemed approved within 10 days after the information filing unless the SDPUC Staff requests changes during that period.
Phase In Rate Plan Rider - Effective January 2024, we received approval of a Phase in Rate Plan Rider, which may allow recovery of capital investments without filing a general electric rate review. SDPUC approval of the plan and associated project cost recovery are required.
NPSC Regulation
Our Nebraska natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated by the NPSC. High volume customers are not subject to such regulation, but can file complaints if they allege discriminatory treatment. Under the Nebraska State Natural Gas Regulation Act, a regulated natural gas utility may propose a change in rates to its regulated customers, if it files an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the proposed rate change if the affected communities representing more than 50 percent of the affected ratepayers agree to direct negotiations, or it may proceed to have the NPSC review the filing and make a determination. Our tariffs have been approved by the NPSC, and the NPSC has adopted certain rules governing the terms and conditions of service of regulated natural gas utilities. Our retail natural gas tariffs provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for biannual, or more often if needed, adjustments based on changes in gas supply and interstate pipeline transportation costs.
FERC Regulation
We are subject to FERC's jurisdiction and regulations with respect to rates for electric transmission service and electricity sold at wholesale, hydro licensing and operations, the issuance of certain securities, incurrence of certain long-term debt, and compliance with mandatory reliability standards, among other things. Under FERC's open access transmission policy, as
owners of transmission facilities, we are required to provide open access to our transmission facilities under filed tariffs at cost-based rates. In addition, we are required to comply with FERC's Standards of Conduct for Transmission Providers.
Our Montana wholesale transmission customers, such as cooperatives, industrial customers, and other customers that have third-party commodity supply providers, receive transmission delivery service under our OATT, which is on file with FERC. The OATT defines the terms, conditions, and rates of our Montana transmission service, including ancillary services. These transmission rates are adjusted annually through formula rates. Our South Dakota transmission operations are in the SPP, and transmission service is provided under the SPP OATT. These transmission rates are adjusted annually through formula rates.
Our natural gas transportation pipelines are generally not subject to FERC's jurisdiction, although we are subject to state regulation. We conduct limited interstate transportation in Montana and South Dakota that is subject to FERC jurisdiction, and FERC has allowed the MPSC and SDPUC to set the rates for this interstate service. We have capacity agreements in South Dakota and Nebraska with interstate pipelines that are also subject to FERC jurisdiction.
Our hydroelectric generating facilities are licensed by the FERC and operated under the terms of those licenses and FERC regulations. In connection with the relicensing of these generating facilities, applicable law permits the FERC to issue a new license to the existing licensee, to a new licensee, or alternatively allows the U.S. government to take over the facility. If the existing licensee is not relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of the property taken, plus reasonable severance damages to other property affected by the lack of relicensing.
Reliability Standards - We must comply with the standards and requirements that apply to the NERC functions for which we have registered in both the MRO for our South Dakota operations and the WECC for our Montana operations. WECC and the MRO have responsibility for monitoring and enforcing compliance with the FERC-approved mandatory reliability standards within their respective regions. We expect that the reliability standards will continue to evolve and change as a result of modifications, guidance, and clarification following industry implementation and ongoing audits and enforcement.
COMPETITION
We are subject to public policies that promote competition and development of energy markets. Certain of our industrial and large commercial customers have the ability to choose their electric supplier and may generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region. Customers have the opportunity to supply their own power with distributed generation including solar generation, and in Montana, can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. These incentives and federal tax subsidies make distributed generating resources viable potential competitors to our electric service business.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. Our wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use our transmission systems to serve their load. There is also competition for available transmission capacity to meet our electric supply needs to serve customers.
ENVIRONMENTAL
The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, and protection of natural resources and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are issued, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.
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. It is not yet clear how existing regulations affecting existing fossil fuel assets will be reconsidered or repealed. If the MATS Rules remain enforced, between now and 2028 total compliance costs for the Colstrip plant is estimated to range from $350 million to $665 million, of which we would be responsible for our proportionate share.
This estimate has been developed by the Colstrip operator and represents an initial high-level scoping estimate that will require significant refinement to narrow the range of costs, which is currently underway. Without change, implementation of existing climate related regulations have the potential to limit or curtail our operations, including the burning of fossil fuels at our coal-fired and some natural gas power plants. While we strive to comply with all environmental regulations applicable to our operations, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to energy and environmental laws and regulations, or new administrative or judicial interpretations or enforcement decisions regarding them.
For more information on environmental regulations and contingencies and related capital expenditures, see Note 18 - Commitments and Contingencies, to the Consolidated Financial Statements.
CORPORATE INFORMATION AND WEBSITE
We were incorporated in Delaware on May 30, 2023. Our Internet address is https://www.northwesternenergy.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, along with our annual report to shareholders and other information related to us, are available, free of charge, on our Internet website as soon as reasonably practicable after we electronically file those documents with, or otherwise furnish them to, the SEC. This information is available in print to any shareholder who requests it. Requests should be directed to: Investor Relations, NorthWestern Energy Group, 3010 W. 69th Street, Sioux Falls, South Dakota 57108 and our telephone number is (605) 978-2900. References to our website in this report are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this report.
HUMAN CAPITAL RESOURCES
Our ability to achieve the objectives of our business strategy and serve our customers within our service territory depends on employing and continually investing in the development of skilled individuals at all levels of our organization. We aspire to be an employer of choice and a great workplace by offering competitive salaries and benefits and providing a safe working environment where employees can grow personally and in their careers. We value diversity, foster inclusion and encourage a healthful work-life balance that includes taking personal time and giving back to the communities we live and work in. Our success comes when employees feel purpose in the work they do and empowered to take initiative, voice their opinions, and build on their experiences within our company and our communities.
As of December 31, 2024, we had 1,585 employees. Of these, 1,277 employees were in Montana and 308 were in South Dakota or Nebraska. Of our Montana employees, 462, or 36 percent, were covered by seven collective bargaining agreements involving five unions, which were renegotiated in 2022. Each of the seven Montana collective bargaining agreements negotiated in 2022 will expire in 2026. Of our South Dakota and Nebraska employees, 165, or 54 percent, are covered by a collective bargaining agreement renegotiated in 2021 that expires in 2025. Additionally, there are ten employees who are in the process of negotiating a collective bargaining agreement. We consider our relations with employees and union leadership to be positive and respectful.
Talent Management
Attraction and retention of skilled employees is key to our ongoing success. We invest resources in maintaining a culture that supports the ongoing development of our workforce. This includes an integrated learning and performance management system which includes annual performance reviews that link goals and competencies together so that managers are able to provide a holistic view to employees in regards to their performance against goals as well as key competencies as they relate to their role in the organization. This process provides opportunities to develop and enhance skills and knowledge, and enables our employees to grow professionally and perform their duties in a safe and efficient manner. This structured training and development is intended to provide employees a consistent learning experience, and maximizes learning retention and background knowledge. We offer tuition reimbursement to promote continued professional growth for current employees, and a scholarship program for students attending universities, colleges, and technical schools in our service area to assist in developing current and future skills sets needed by our employees. We support annual pre-apprentice scholarships, recruit and hire suitable candidates from the program, serve as industry advisors on the program board and have donated training assets to support the program.
Hiring, promotions, work assignments, or other decisions related to the terms and conditions of employment are made by considering skills, experience, proven track record of performance, and other traits that serve to create a team with varied strengths and backgrounds. Our workforce reflects the available talent in the communities we serve. In compliance with current mandates, our employment data is tested annually by a third party. This testing determined that there is no current need to establish corrective placement goals.
Compensation and Benefits
Our overarching compensation philosophy is structured to be consistent with our peers, and to align the long-term interests of our employees, executives, shareholders, and customers so the pay appropriately reflects performance in achieving financial and non-financial operating objectives. We offer a competitive pay and benefits package, which is benchmarked on an annual basis to external market data. Beyond base pay and incentive compensation, we offer competitive, cost-effective, and well- rounded benefits, which aligns with our desire to be an employer of choice. From considerable employer retirement contributions, to generous paid time off, to health care and well-being programs, our benefits are designed to meet the varied needs of our employees.
We are committed to internal pay equity, and the Human Resources Committee of the Board of Directors monitors the relationship between the pay our executive officers receive and the pay our non-managerial employees receive. During 2024 and 2023, the compensation for our Chief Executive Officer (CEO) was approximately 33 and 23 times, respectively, the compensation of our median employee.
We believe that a significant portion of an executive’s pay should be at risk in the form of performance-based incentive awards that are only paid if the individual and company performance targets are met. For 2024, approximately 75 percent of the targeted compensation of our CEO and about 56 percent of the targeted compensation of our other named executive officers is at risk in the form of performance-based incentive awards or time-based awards tied to the value of equity. Our Board of Directors establishes the metrics and targets for these incentive awards, based upon advice from the Board of Directors’ independent compensation consultant. In addition, our compensation practices have led to a relatively low CEO to median employee ratio of approximately 33 to 1 for 2024.
We engage nationally recognized outside compensation and benefits consulting firms to independently evaluate the effectiveness of our compensation and benefits programs and to provide benchmarking against our peers within the industry. We provide pay equity between our employees performing equal or substantially similar work. We engage a third party to review our pay equity and share the results with our Board of Directors. Our most recent study was performed in 2024, with no corrective action required.
Health and Safety
As stewards of critical infrastructure, providers of energy service, and members of the communities we serve, our top service value is the safety and well-being of our employees and customers. We integrate safety and health into every aspect of our business, continuously monitoring various areas related to safety practices and policies. Key metrics include the recordable incident rate (the number of work-related injuries per 100 employees over a one-year period) and the lost time incident rate (the number of employees who miss work due to work-related injuries per 100 employees over a one-year period). During the years ended December 31, 2024 and 2023, our recordable incident rates were 1.65 and 1.34, respectively, and lost time incident rates were 0.57 and 0.45, respectively, on a company wide basis. As of December 31, 2024, our five-year average safety performance exceeded the five-year average of our industry peers.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Executive Officer Current Title and Prior Employment Age(1)
Brian B. Bird President and Chief Executive Officer and Director of NorthWestern Energy Group, Inc., since October 2, 2023, and of NorthWestern Energy Public Service Corporation since January 1, 2024, and of NorthWestern Corporation since January 2023; formerly President and Chief Operating Officer of NorthWestern Corporation since February 2021 and Chief Financial Officer from December 2003 to February 2021.
Crystal D. Lail Vice President and Chief Financial Officer of NorthWestern Energy Group, Inc., since October 2, 2023, and of NorthWestern Energy Public Service Corporation since January 1, 2024, and of NorthWestern Corporation since February 2021; formerly Vice President and Chief Accounting Officer of NorthWestern Corporation since April 2020; and Vice President and Controller from October 2015 to April 2020.
Shannon M. Heim Vice President - General Counsel and Federal Government Affairs of NorthWestern Energy Group, Inc., since October 2, 2023, and of NorthWestern Energy Public Service Corporation since January 1, 2024, and of NorthWestern Corporation since January 2023; formerly Director, Regulatory Corporate Counsel of NorthWestern Corporation since June 2020; and formerly Equity Shareholder at the law firm of Moss & Barnett, P.A. from 2017 to 2020.
Bleau J. Lafave Vice President - Asset Management & Business Development of NorthWestern Corporation since June 2023 and of NorthWestern Energy Public Service Corporation since January 1, 2024; formerly Director of Long-Term Resources of NorthWestern Corporation since 2003.
Bobbi L. Schroeppel Vice President - Customer Care, Communications and Human Resources of NorthWestern Corporation since May 2009 and of NorthWestern Energy Public Service Corporation since January 1, 2024.
Jason C. Merkel Vice President - Distribution of NorthWestern Corporation since September 2022 and of NorthWestern Energy Public Service Corporation since January 1, 2024; formerly General Manager - Operations and Construction of NorthWestern Corporation since 2007.
Jeanne M. Vold Vice President - Technology of NorthWestern Corporation since February 2021 and of NorthWestern Energy Public Service Corporation since January 1, 2024; formerly Business Technology Officer of NorthWestern Corporation since 2012.
John D. Hines Vice President - Supply and Montana Government Affairs of NorthWestern Corporation since January 2018 and of NorthWestern Energy Public Service Corporation since January 1, 2024; formerly Vice President - Supply of NorthWestern Corporation since May 2011. 66
Michael R. Cashell Vice President - Transmission of NorthWestern Corporation since May 2011 and of NorthWestern Energy Public Service Corporation since January 1, 2024.
(1) As of February 7, 2025.
Officers are elected annually by, and hold office at the pleasure of the Board of Directors (Board), and do not serve a “term of office” as such.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Regulatory, Legislative and Legal Risks
Our profitability depends on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We are subject to potential unfavorable litigation, and state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs or collect them in a timely manner, which could adversely impact our results of operations and liquidity.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and rates that we can charge customers. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital and rates are generally set through a process called a rate review (or rate case) in which the utility commission analyzes our costs incurred during a historical test year and decides whether they may be included in our base rates. In addition to formal general rate reviews, we also have cost tracking mechanisms that are intended to allow us to recover prudently incurred costs. There can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in rates that allow us the opportunity to earn our authorized return or provide for timely and full recovery of such costs. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Differing schedules and regulatory practices between our state commissions and FERC expose us to the risk that we may not fully recover our costs due to timing of filings, specific calculations and issues such as cost allocation methodologies. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Adverse regulatory rulings could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on our common stock.
We are subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.
We are subject to regulations under a wide variety of U.S. federal and state regulations and policies. Regulation affects almost every aspect of our business. Changes to federal and state laws and regulations are continuous and ongoing and the federal administration, the U.S. Congress, state legislatures and state administrations may enact and implement new laws and regulations that could adversely and materially affect us. For example, legislation and regulations may be enacted that require or facilitate alternative generation or storage which, in turn, could result in customers using less of our energy or facilities which could reduce our revenues and our growth opportunities. We cannot predict future changes in laws and regulations, how they will be implemented and interpreted, or the ultimate effect that this changing environment will have on us. There can be no assurance that laws, regulations and policies will not be changed in ways that have a material adverse effect on our operations, financial condition, results of operations, and cash flows.
We are subject to extensive and changing energy, and environmental laws and regulations, including legislative, judicial, and regulatory responses to climate change, with which compliance may be difficult and costly.
Our operations are subject to laws and regulations imposed by federal, state and local government authorities regarding energy policy, permitting/siting for energy projects, climate change, the environment, air and water quality, GHG emissions, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other environmental considerations.
In response to recent regulatory and judicial decisions and international accords, GHG emissions, most significantly CO2, could be restricted in the future as a result of federal or state legal requirements or litigation relating to GHG emissions. Recently promulgated federal rules under the Biden Administration will potentially impose requirements on fossil fuel assets, but the Trump Administration is evaluating energy-related regulations impacting reliability and affordability. It is currently unclear whether the promulgated GHG or MATS Rules will be enforced, revised, or repealed. If these promulgated GHG and
MATS Rules are implemented and enforced as currently written, they may affect our ability to reliably serve our customers and we could be subject to significant additional compliance costs that would affect our future financial position, results of operations, and cash flows if such costs are not recovered through regulated rates. Such changes also could affect the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.
To the extent that costs exceed our estimated environmental liabilities, or we are not successful in recovering remediation costs or costs to comply with the proposed or any future changes in rules or regulations, our results of operations and financial position could be adversely affected. Certain environmental laws and regulations also provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities.
In addition, there is a risk of environmental damage claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.
We are also at risk of unfavorable litigation outcomes related to zoning and environmental permits. See discussion related to YCGS below in “Management’s Discussion and Analysis - Significant Trends and Regulation.” Adverse litigation outcomes could cause us to delay or terminate projects, increase costs and impact our ability to service our customers.
Early closure of our owned and jointly owned electric generating facilities due to environmental risks, litigation or public policy changes could have a material adverse impact on our results of operations and liquidity.
While a majority of our Company-wide electric supply portfolio is carbon-free, it does include fossil-fuel resources. Environmental advocacy groups, certain investors and other third parties oppose the operation of fossil-fuel generation, expressing concerns about the environmental and climate-related impacts from fossil fuels. This opposition may increase in scope and frequency depending on a number of variables, including the course of Federal and State laws and environmental regulations and the financial resources devoted to opposition efforts. These risks include litigation against us due to GHG or other emissions or coal combustion residuals disposal and storage; activist shareholder proposals; and increased activism before our regulators. We cannot predict the effect that any such opposition may have on our ability to operate and recover the costs of our generating facilities. In addition, defense costs associated with litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
In particular, as described more fully below in Note 18 - Commitments and Contingencies, we are a co-owner of Colstrip Unit 4. The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. On January 16, 2023 we entered into an agreement with Avista Corporation pursuant to which it will transfer to us its 15% project share in Units 3 and 4 on December 31, 2025. On July 30, 2024, we entered into an agreement with Puget Sound Energy pursuant to which it will transfer to us its 25% project share in Units 3 and 4 on December 31, 2025.
Increased risks of regulatory penalties could negatively impact our business.
We must comply with established reliability standards and requirements including Critical Infrastructure Protection Reliability Standards, which apply to NERC functions. NERC reliability standards protect the nations’ bulk power system against potential disruptions from cyber and physical security breaches. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Penalties for the most severe violations can reach nearly $1.2 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.
Additionally, the Pipeline and Hazardous Materials Safety Administration, Occupational Safety and Health Administration and other federal or state agencies have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties. If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
Federally mandated purchases of power from QFs, and integration of power generated from those projects in our system, may increase costs to our customers and decrease system reliability, limit our ability to make generation investments and adversely affect our business.
We are generally obligated under federal law to purchase power from certain QF projects, regardless of current load demand, availability of lower cost generation resources, transmission availability or market prices. Although some of these resources include a battery component, they are primarily intermittent generation whose prices may be in excess of market prices during times of lower customer demand, and may not be able to generate electricity during peak times. These resources typically do not meet the requirements set forth in our supply plans for resource procurement. These requirements to purchase supply that is inconsistent with customer need may have multiple impacts, including increasing the likelihood and frequency that we will be required to reduce output from owned generation resources, negatively impacting our ability to make our own generation investments and increasing the likelihood that we will need to upgrade or build additional transmission facilities to serve QF projects. Any of these results would increase costs to customers and impact our investment plan. Further, balancing load and power generation on our system is challenging, and we expect that operational costs will increase as a result of integration of these intermittent, non-dispatchable generation projects. If we are unable to timely recover those costs, those increased costs may negatively affect our liquidity, results of operations and financial condition.
In addition, requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs that are inconsistent with resource plans developed based on a lowest cost and least risk basis while placing upward pressure on overall customer bills. This may impact our investment plans and financial condition. Finally, the requirement to procure power from these QF sources may impact our transmission system and require additional transmission facilities to be developed in order to integrate these resources, which also can impact overall customer bills.
Operational Risks
Our electric and natural gas operations involve numerous activities that may result in accidents, fires, system outages and other operating risks and costs that are unique to our industry.
Inherent in our electric transmission and distribution and natural gas transmission and distribution operations are a variety of hazards and operating risks, such as breakdown or failure of equipment or processes, interruptions in fuel supply, supply chain interruptions, labor disputes, operator error, and catastrophic events such as fires, electric contacts, leaks, explosions, floods and intentional acts of destruction. For our natural gas lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks could be significant. These risks could cause a loss of human life, facility shutdown or significant damage to property, service interruption, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others.
Fire risk is significant in the western United States, including in our service territory. Various factors in recent years have contributed to increasing fire risk including dead and dying trees, warmer air temperatures, drought, wind, forest management practices, and land management practices. These factors increase the risk of a fire in both forests and grasslands. In forested areas, this issue has been heightened by mountain pine beetle and other infestations weakening and killing trees in our service territory. Worsening conditions as a result of climate change may increase the likelihood and magnitude of damages that may be caused by fires. Residential and commercial development into the wildland-urban interface has also led to an increasing trend in the degree of destruction from wildfires.
Fires alleged to have been caused by our equipment potentially expose us to significant penalties and/or damage awards based on claims of strict liability, negligence, gross negligence, inverse condemnation, nuisance, trespass and others. Our equipment has been alleged to be involved in igniting wildfires although none have had a material adverse effect on our financial condition or results of operations.
For our electric generating facilities, operational risks include facility shutdowns due to breakdown or failure of equipment or processes, interruptions in fuel supply, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation, litigation or regulation. The loss of a major electric generating facility would require us to find other sources of supply or ancillary services, if available, and expose us to higher purchased power costs and potential litigation which may not be recovered from customers.
We maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
Additionally, during peak-load periods our electric and natural gas systems in Montana are constrained. These constraints limit our ability to transmit electric energy within Montana and access electric energy from outside the service area. Our electric transmission facilities are also interconnected with those of third parties, and thus operation of these facilities could be adversely affected by unexpected or uncontrollable events. Our natural gas system is also constrained, which limits our on-system deliverability and the ability to transport gas. We are similarly exposed to risk of interconnection with third-party pipelines and are dependent upon their operation to serve customers. These transmission constraints and events could result in failure to provide reliable service to customers due to the inability to deliver energy supply resources, or could result in significant cost increases due to the inability to access lower cost sources of energy supply.
Our electric and natural gas portfolios rely significantly on market purchases. This exposure adversely affects our ability to manage our operational requirements to reliably serve our customers, while exposing us to market volatility, which ultimately could adversely affect our results of operations and liquidity.
We are obligated to supply power to retail customers and certain wholesale customers and procure natural gas to supply fuel for our natural gas fired generation. Our need to acquire flexible energy supply and capacity in the market to meet our electric and natural gas load serving obligations exposes us to certain risks including the ability to reliably serve customers and significant uncertainty in the cost of supply, which may not be recoverable. We rely upon a combination of base-load supply from our owned and long-term contracted generation and market purchases to serve customers. During peak periods, power demand could exceed, and has exceeded, the available capacity of our owned and long-term contracted generation capacity, requiring us to purchase capacity and energy from the market. In the past, we have relied upon both in-state and out-of-state power purchase agreements for grid reliability and to physically serve customers. A significant number of base-load generation facilities, which may also serve to meet peak requirements, in the state and region have been retired or are scheduled to be retired in the next five to ten years.
This includes Colstrip Units 1 and 2, representing 614 MWs of generation on a capacity basis, which ceased operations in January 2020. A decrease in the state and region’s electric capacity, whether for operational reasons or litigation outcomes, may impair the reliability of the grid, particularly during peak demand periods. There can be no assurance that there will be available counterparties to contract with to serve our customers' needs, or that these counterparties will fulfill their obligations to us. There is also no assurance that the transmission capacity required to import market purchases will be available on transmission systems owned by us or by third parties. In addition, the suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us. These conditions could result in an inability to physically deliver electricity to our customers. Losing electric service during extreme conditions carries significant consequences, as without our services our customers may be subjected to dire circumstances.
Commodity pricing is an inherent risk component of our business operations and our financial results. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our costs are recoverable, as discussed above. The prevailing market prices for electricity may fluctuate substantially over relatively short periods of time, potentially adversely impacting our results of operations, financial condition and cash flows due to our need for market purchases and the sharing component of the Montana PCCAM. During recent periods, we have had a significant under-collection of these costs impacting our results of operations and cash flows.
In addition, our natural gas system serves both retail customers and the needs of natural gas fired electric generation. The natural gas system has capacity constraints that expose us to risks to be able to deliver natural gas during periods of peak demand.
Fluctuations in actual weather conditions, generation availability, transmission constraints, and generation reserve margins may all have an impact on market prices for energy and capacity and the electricity consumption of our customers on a given day. Extreme weather conditions may force us to purchase electricity in the short-term market on days when weather is unexpectedly severe, and the pricing for market energy may be significantly higher on such days than the cost of electricity in our existing generation and contracts. Unusually mild weather conditions could leave us with excess power which may be sold in the market at a loss if the market price is lower than the cost of electricity in our existing contracts.
Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our ability to manage our operational requirements to serve our customers, and ultimately adversely affect our results of operations and liquidity.
Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters or cool summers could adversely affect our results of operations and financial position. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas. Our sensitivity to weather volatility is significant due to the absence of regulatory mechanisms, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs.
Severe weather impacts, including but not limited to, blizzards, thunderstorms, high winds, microbursts, floods, fires, tornadoes and snow or ice storms can disrupt energy generation, transmission and distribution. We derive a significant portion of our energy supply from hydroelectric facilities, and the availability of water can significantly affect operations. Higher temperatures may decrease the Montana snowpack and impact the timing of run-off and may require us to purchase replacement power. Dry conditions, which exist in the West and in our service territory, also increase the threat of fires, which could threaten our communities and electric distribution and transmission lines and facilities. In addition, fires that are alleged to have been caused by our system could expose us to substantial property damage and other claims. Any damage caused as a result of fires could negatively impact our financial condition, results of operations or cash flows.
The physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate.
Extreme weather conditions, especially those of prolonged duration, create high energy demand on our own and/or other systems and increase the risk we may be unable to reliably serve customers, causing brownouts and/or blackouts of our electric
systems, and loss of gas supply. Risk of losing electricity or gas supply during extreme weather carries significant consequences as without our services our customers may be subjected to dire circumstances. Additionally, extreme weather conditions may raise market prices as we buy short-term energy to serve our own system. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. In addition, we may not recover all costs related to mitigating these physical and financial risks.
Our results of operations may be impacted by disruptions to fuel supply or the electric grid that are beyond our control.
We are exposed to risks related to performance of contractual obligations by our suppliers, which includes parties transporting natural gas. We are dependent on coal and natural gas for a significant portion of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short- and long-term contracts. We have certain supply and transportation contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply and deliver coal and natural gas to us. For instance, there currently is litigation pending relating to adequacy of certain permits for the Rosebud Mine in Montana, which supplies coal to Colstrip and contains significant quantities of coal. In order to operate the Colstrip facility through its currently identified depreciable life of 2042, it will be necessary to identify and contract for coal supply subsequent to expiration of our current contract. Moreover, the suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply or transport coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather, availability of equipment and labor shortages. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm, generator or transmission facility outage on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position, results of operations and cash flows.
Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions or response to price increases. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.
Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, and the use of distributed generation resources or other emerging technologies for electricity. Advances in distributed generation technologies that produce power, including fuel cells, micro-turbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production. Customer-owned generation itself reduces the amount of electricity purchased from utilities and may have the effect of inappropriately increasing rates generally and increasing rates for customers who do not own generation, unless retail rates are designed to collect distribution grid costs across all customers in a manner that reflects the benefit from their use. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy.
Decreasing use per customer (driven, for example, by appliance and lighting efficiency) and the availability of cost-effective distributed generation, put downward pressure on load growth. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, market participants, transmission availability, the availability of generation, and the ongoing development of the Western EIM, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.
Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations. Failure to maintain the security of personally identifiable information could adversely affect us.
Business Operations - We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber attacks, physical security breaches and other disruptive activities of individuals or groups, and theft of our critical infrastructure information. Our generation, transmission and distribution facilities are deemed critical infrastructure and provide the framework for our service infrastructure. Cyber crime, which includes the use of malware, phishing attempts, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years. The advancement of artificial intelligence and large language models has given rise to additional vulnerabilities and potential entry points for cyber crime. Our assets and the information technology systems on which they depend could be direct targets of, or indirectly affected by, cyber attacks and other disruptive activities, including those that impact third party facilities that are interconnected to us. Any significant interruption of these assets or systems could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential and other data could be compromised.
Security threats continue to evolve and transform. The risk of cyber-based attacks is heightened due to recent geopolitical events as well as employees working and accessing our technology infrastructure remotely. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, to confidential data, or to disrupt operations. With the continuing rise in ransomware and other cyber-based threats we continuously analyze our technology platforms and monitoring for signs of potential intrusions. There is also a risk of exposure of confidential or proprietary data through the inadvertent use of open artificial intelligence tools. We periodically engage with our vendors, suppliers and contractors to establish that they are taking appropriate measures. None of these attempts has individually or in the aggregate resulted in a security incident with a material impact on our financial condition or results of operations. However, despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact.
These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for electricity, natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.
Personally Identifiable Information - Our information systems and those of our third-party vendors contain confidential information, including information about customers and employees. Customers, shareholders, and employees expect that we will adequately protect their personal information. The regulatory environment surrounding information security and privacy is increasingly demanding. A data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject us to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies. It could also reduce the value of proprietary information, and harm our reputation.
We maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
We may have difficulty cost-effectively completing certain operations activities and construction projects due to inflationary pressures or if our third-party business partners are unable to deliver ordered supplies or complete contracted services timely, including workforce shortages or macro supply chain disruptions.
We place significant reliance on our third-party business partners to supply materials, equipment and labor necessary for us to operate our utility and reliably serve current customers and future customers. As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, potential tariffs, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases.
Should these economic conditions and issues continue, we could have difficulty completing the operational activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations.
Failure to attract and retain an appropriately qualified workforce could affect our operations.
We require skilled labor to perform specialized utility functions. Turnover of key employees without appropriate replacements may lead to operating challenges and increased costs. Some of the challenges include lack of resources, loss of knowledge, and time required for replacement employees to develop necessary skills. Wage inflation nationally and increased competitive labor markets may make it difficult to attract employees. Failure to identify qualified replacement employees could result in decreased productivity and increased safety costs. If we are unable to attract and retain an appropriately qualified workforce, our operations could be negatively affected. We are also subject to multiple collective bargaining agreements. Future negotiation of these collective bargaining agreements could lead to work stoppages or other disruptions to our operations, which could adversely affect our financial condition and results of operations.
Liquidity and Financial Risks
We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.
Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers. Additionally, insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which we may be subject, including liability and losses associated with wildfires, natural gas and storage field explosions, cyber-security breaches, environmental hazards and natural disasters.
Our plans for future expansion through the acquisition of assets, capital improvements to existing assets, generation investments, and transmission grid expansion involve substantial risks.
Our business strategy includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The completion of generation and natural gas investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to permitting, financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.
Acquisitions include a number of risks, including but not limited to, regulatory approval, regulatory conditions, additional costs, the assumption of material liabilities, the diversion of our attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, and securing adequate capital to support the transaction. The regulatory process in which rates are determined may not result in rates that produce full recovery of our investments, or a reasonable rate of return. Uncertainties also exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to successfully integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.
Access to capital markets is critical to our operations and our capital structure. Increasing interest rates could have a material negative impact on our financial condition.
We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, U.S. and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms. We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time-to-time. For example, we have $300 million of secured long-term debt and $100 million of short-term borrowings maturing in 2025. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.
We are subject to financial risks associated with the transition to a lower carbon economy.
The risks related to our transition to a lower-carbon economy, creates financial risk. Transition risks represent those risks related to the social and economic changes needed to shift toward a lower carbon future. These risks are often interconnected, representing policy and regulatory changes, technology and market risks, and risks to our reputation and financial performance.
Potential regulation associated with climate change legislation could pose financial risks to us. Although the U.S. is no longer a party to the United Nations' "Paris Agreement" on climate change, other potential legislation and regulation discussed above, could result in enforceable GHG emission reduction requirements that could lead to increased compliance costs for us. For example, during the Biden Administration, the EPA indicated that it was "evaluating additional opportunities" to reduce GHG emissions from existing power plants. Although the Trump Administration has directed federal executive agencies to
review all energy related regulations implicating reliability and affordability, it is not yet clear what the impact will be on existing regulations or future legislation or regulations affecting GHG.
As we expand our energy generation asset mix, the ability to integrate renewable technologies into our operations and maintain reliability and affordability is a risk. The intermittency of renewables remains a critical challenge particularly as cost-efficient energy storage is still in development. Other technology risks include the need for significant upfront financial investments, lengthy development timelines, and the uncertainty of integration and scalability across our entire service territory.
To the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory costs, CO2 taxes or imposed costs, we may be adversely impacted. There are also increasing risks for energy companies from shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change who may elect in the future to shift some or all of their investments into entities that emit lower levels of GHG emissions or into non-energy related sectors. Institutional investors and lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable investing and lending practices and some of them may elect not to provide funding for fossil fuel energy companies. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We may be subject to financial risks from private party litigation relating to GHG emissions. Defense costs associated with such litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.
A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. We continue to maintain our investment grade credit ratings. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms and would increase our borrowing costs. Higher interest rates on borrowings with variable interest rates could also have an adverse effect on our results of operations.
Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to make up the difference.
As part of a stipulation in 2002 with the MPSC and other parties, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH through June 2029. This obligation is reflected in the electric QF liability, which reflects the unrecoverable costs associated with these specific QF contracts per the stipulation. The annual minimum energy requirement is achievable under normal operations of these facilities, including normal periods of planned and forced outages. However, to the extent the supplied power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to purchase the difference from other sources. The anticipated source for any shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted rates. To the extent the cost of replacement power is higher than contracted rates, our results of operations, cash flows and financial position could be adversely affected.
Changes in tax law may significantly impact our business.
We are subject to taxation by the various taxing authorities at the federal, state and local levels where we operate. Similar to the Tax Cuts and Jobs Act, sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate will affect our utility customers and the time period over which that change will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates and therefore may impact our results of operations, cash flows and financial position.
We are subject to counterparty credit risk.
We enter into transactions to buy and sell power, natural gas, and transmission service. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. Certain of these contracts may result in the receipt of, or posting of, collateral with counterparties. Fluctuations in commodity prices that lead to the posting of collateral with counterparties negatively impact liquidity, and downgrades in our credit ratings may lead to additional collateral posting requirements.
We are a participant in the energy markets, including the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation. The EIM has collateral posting requirements based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the EIM and any such credit losses could be socialized to all EIM participants, including us. A significant failure of a participant in the EIM to make payments when due on its obligations could have a ripple effect on various of our counterparties in the power and gas markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of our counterparties to perform on their obligations.
We also extend credit to our customers in the ordinary course of business in each of our operating segments. Our customers' ability to pay depends on a variety of factors including macroeconomic conditions, local economic conditions, including unemployment rates, and industry conditions in which our commercial and industrial customers operate. Increased customer delinquencies and bad debts could adversely impact our operating results and liquidity.
Poor investment performance of plan assets of our defined benefit pension and postretirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.
We have a holding company structure and rely on cash from our subsidiaries to pay dividends.
As a holding company, our primary assets are our investments in our subsidiaries, NW Corp and NWE Public Service. Substantially all operations are conducted by NW Corp (and its subsidiaries) and NWE Public Service. We depend on earnings, cash flows and dividends from our subsidiaries to pay dividends on our common stock. Regulatory, contractual and legal limitations, as well as subsidiary capital requirements, affect the ability of a subsidiary to pay dividends up to the parent entity and thereby could restrict or influence our ability or decision to pay dividends on our common stock, which could adversely affect our stock price.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None

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

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

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
None
Part II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, which is traded under the ticker symbol NWE, is listed on the Nasdaq Stock Market. As of February 7, 2025, there were approximately 1,201 common stockholders of record.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023, on both a consolidated basis and on a segment basis. For a discussion of our financial results and cash flows for the year ended December 31, 2023 compared with the year ended December 31, 2022, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023.
This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 20 - Segment and Related Information, to the Consolidated Financial Statements.
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 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 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 787,000 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. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2024, 2023 and 2022. Following is a discussion of our strategy and significant trends.
We work to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. 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.
In 2024, approximately 58 percent of our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 41 percent for the total U.S. electric power industry. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050. Our vision for the future builds on the progress we have made, including our hydroelectric system in Montana, which is 100 percent carbon free and is readily available capacity. For us, wind generation is a close second and continues to grow. While utility-scale solar energy has not been a significant portion of our energy mix to date, we recently entered into power purchase agreements with two solar projects totaling 160-megawatts that began delivering energy to our Montana customers in 2023. We expect solar to further evolve along with advances in energy storage. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system.
HOW WE PERFORMED IN 2024 COMPARED TO OUR 2023 RESULTS
Year Ended December 31, 2024 vs. 2023
Income Before Income Taxes Income Tax Benefit (Expense) Net Income
(in millions)
December 31, 2023 $ 201.6 $ (7.5) $ 194.1
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income:
Base rates 62.4 (15.8) 46.6
Electric transmission revenue
18.6 (4.7) 13.9
Montana interim rates (subject to refund) 4.8 (1.2) 3.6
Montana natural gas transportation 2.3 (0.6) 1.7
Montana property tax tracker collections 1.1 (0.3) 0.8
Production tax credits, offset within income tax benefit (expense)
0.2 (0.2) -
Non-recoverable Montana electric supply costs
(7.9) 2.0 (5.9)
QF liability adjustment
(4.2) 1.1 (3.1)
Natural gas retail volumes
(4.0) 1.0 (3.0)
Electric retail volumes
(0.9) 0.2 (0.7)
Other (3.2) 0.8 (2.4)
Variance in expense items(2) impacting net income:
Operating, maintenance, and administrative
(19.4) 4.9 (14.5)
Depreciation
(17.1) 4.3 (12.8)
Interest expense
(17.1) 4.3 (12.8)
Property and other taxes not recoverable within trackers
(4.4) 1.1 (3.3)
Release of unrecognized tax benefits (inclusive of related interest previously accrued)
- 17.8 17.8
Gas repairs safe harbor method change
- 7.0 7.0
Other 1.9 (4.8) (2.9)
December 31, 2024 $ 214.7 $ 9.4 $ 224.1
Change in Net Income $ 30.0
(1) Exclusive of depreciation and depletion shown separately below.
(2) Excluding fuel, purchased supply, and direct transmission expense.
Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023. 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
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 (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 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. The lawsuit challenging the YCGS air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and increased costs. On January 3, 2025, the Montana Supreme Court ordered that the YCGS air quality permit be reinstated. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.
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.
EPA Rules
In April 2024, the EPA released GHG Rules for existing coal-fired facilities and new coal and natural gas-fired facilities as well as MATS Rules. 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 18 - 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
Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions):
Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments. For additional information related to our electric supply resource plans, see Item 1. Business, where we discuss electric resource planning for our Montana and South Dakota jurisdictions.
Distribution and Transmission Modernization and Maintenance - The primary goals of our infrastructure investments are to reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. We are taking a proactive and pragmatic approach to replacing these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications. Over $2.2 billion or 82 percent of our capital forecast above is projected to be spent on our distribution and transmission system. 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
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 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
Year Ended December 31, 2024 Compared with Year Ended December 31, 2023
Consolidated net income in 2024 was $224.1 million as compared with $194.1 million in 2023, an increase of $30.0 million. 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. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment, electric and natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.
Consolidated gross margin in 2024 was $460.8 million as compared with $416.3 million in 2023, an increase of $44.5 million or 10.7 percent. 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
2024 2023 2024 2023 2024 2023
(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues $ 1,200.7 $ 1,068.8 $ 313.2 $ 353.3 $ 1,513.9 $ 1,422.1
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 329.6 262.7 104.2 157.5 433.8 420.2
Less: Operating and maintenance 171.7 166.0 56.1 54.5 227.8 220.5
Less: Property and other taxes 126.5 120.3 37.4 34.3 163.9 154.6
Less: Depreciation and depletion 190.0 174.1 37.6 36.4 227.6 210.5
Gross Margin 382.9 345.7 77.9 70.6 460.8 416.3
Operating and maintenance 171.7 166.0 56.1 54.5 227.8 220.5
Property and other taxes 126.5 120.3 37.4 34.3 163.9 154.6
Depreciation and depletion 190.0 174.1 37.6 36.4 227.6 210.5
Utility Margin(1)
$ 871.1 $ 806.1 $ 209.0 $ 195.8 $ 1,080.1 $ 1,001.9
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Year Ended December 31,
2024 2023 Change % Change
(in millions)
Utility Margin
Electric $ 871.1 $ 806.1 $ 65.0 8.1 %
Natural Gas 209.0 195.8 13.2 6.7
Total Utility Margin(1)
$ 1,080.1 $ 1,001.9 $ 78.2 7.8 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated utility margin in 2024 was $1,080.1 million as compared with $1,001.9 million in 2023, an increase of $78.2 million, or 7.8 percent.
Primary components of the change in utility margin include the following (in millions):
Utility Margin
2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates $ 62.4
Electric transmission revenue due to market conditions and rates 18.6
Montana interim rates (subject to refund) 4.8
Montana natural gas transportation 2.3
Montana property tax tracker collections 1.1
Non-recoverable Montana electric supply costs
(7.9)
QF liability adjustment
(4.2)
Natural gas retail volumes (4.0)
Electric retail volumes (0.9)
Other (3.0)
Change in Utility Margin Impacting Net Income 69.2
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes 6.4
Operating expenses recovered in revenue, offset in operating and maintenance expense 2.4
Production tax credits, offset in income tax expense 0.2
Change in Items Offset Within Net Income 9.0
Increase in Consolidated Utility Margin(1)
$ 78.2
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Lower electric residential and commercial retail volumes were driven by unfavorable weather in South Dakota impacting residential demand and lower commercial demand in all jurisdictions as compared to the prior year, partly offset by higher industrial demand and customer growth. 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,
2024 2023 Change % Change
(in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance $ 227.8 $ 220.5 $ 7.3 3.3 %
Administrative and general 137.4 117.3 20.1 17.1
Property and other taxes 163.9 153.1 10.8 7.1
Depreciation and depletion 227.6 210.5 17.1 8.1
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 756.7 $ 701.4 $ 55.3 7.9 %
Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $756.7 million in 2024, as compared with $701.4 million in 2023. Primary components of the change include the following (in millions):
Operating Expenses
2024 vs. 2023
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Depreciation expense due to plant additions and higher depreciation rates $ 17.1
Labor and benefits(1)
7.9
Insurance expense, primarily due to increased wildfire risk premiums 7.7
Property and other taxes not recoverable within trackers 4.4
Litigation outcome (Pacific Northwest Solar) 2.4
Electric generation maintenance 2.0
Non-cash impairment of alternative energy storage investment 1.7
Technology implementation and maintenance 1.5
Uncollectible accounts (1.4)
Other (2.3)
Change in Items Impacting Net Income 41.0
Operating Expenses Offset Within Net Income
Property and other taxes recovered in trackers, offset in revenue 6.4
Pension and other postretirement benefits, offset in other income(1)
4.8
Operating and maintenance expenses recovered in trackers, offset in revenue 2.4
Deferred compensation, offset in other income 0.7
Change in Items Offset Within Net Income 14.3
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 55.3
(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.
Consolidated operating income in 2024 was $323.3 million as compared with $300.5 million in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenue, Montana interim rates, subject to refund, and Montana property tax tracker collections. 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, and administrative and general costs.
Consolidated interest expense in 2024 was $131.7 million, as compared with $114.6 million in 2023. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC.
Consolidated other income in 2024 was $23.0 million, as compared with $15.8 million in 2023. 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 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):
Year Ended December 31,
2024 2023
Income Before Income Taxes $ 214.7 $ 201.6
Income tax calculated at federal statutory rate 45.1 21.0 % 42.4 21.0 %
Permanent or flow through adjustments:
State income taxes, net of federal provisions 0.4 0.2 0.6 0.3
Flow-through repairs deductions (23.1) (10.8) (25.9) (12.9)
Release of unrecognized tax benefits (2024 is inclusive of $4.1 million of related interest previously accrued)
(21.0) (9.8) (3.2) (1.6)
Production tax credits (11.1) (5.2) (10.3) (5.1)
Gas repairs safe harbor method change (7.0) (3.3) - -
Amortization of excess deferred income taxes (2.9) (1.4) (2.2) (1.1)
Prior year permanent return to accrual adjustments (0.4) (0.2) - -
Plant and depreciation of flow through items 9.4 4.4 6.6 3.3
Unregulated Tax Cuts and Jobs Act excess deferred income taxes - - (3.4) (1.7)
Reduction to previously claimed alternative minimum tax credit
- - 3.2 1.6
Other, net 1.2 0.7 (0.3) (0.1)
(54.5) (25.4) (34.9) (17.3)
Income Tax (Benefit) Expense $ (9.4) (4.4) % $ 7.5 3.7 %
Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.
ELECTRIC OPERATIONS
We have various classifications of electric revenues, defined as follows:
•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
•Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Transmission: Reflects transmission revenues regulated by the FERC.
•Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.
Year Ended December 31, 2024 Compared with Year Ended December 31, 2023
Revenues Change MWHs Avg. Customer Counts
2024 2023 $ % 2024 2023 2024 2023
(in thousands)
Montana $ 398,790 $ 408,341 $ (9,551) (2.3) % 2,804 2,795 328,420 322,489
South Dakota 70,012 67,888 2,124 3.1 557 603 51,467 51,261
Residential 468,802 476,229 (7,427) (1.6) 3,361 3,398 379,887 373,750
Montana 408,977 431,357 (22,380) (5.2) 3,197 3,238 75,878 74,438
South Dakota 111,813 103,194 8,619 8.4 1,093 1,101 13,084 12,973
Commercial 520,790 534,551 (13,761) (2.6) 4,290 4,339 88,962 87,411
Industrial 46,637 45,958 679 1.5 2,924 2,660 80 79
Other 32,811 32,756 55 0.2 146 134 6,544 6,443
Total Retail Electric $ 1,069,040 $ 1,089,494 $ (20,454) (1.9) % 10,721 10,531 475,473 467,683
Regulatory amortization 24,908 (105,608) 130,516 (123.6)
Transmission 97,052 78,436 18,616 23.7
Wholesale and Other 9,701 6,511 3,190 49.0
Total Revenues $ 1,200,701 $ 1,068,833 $ 131,868 12.3 %
Fuel, purchased supply and direct transmission expense(1)
329,578 262,755 66,823 25.4
Utility Margin(2)
$ 871,123 $ 806,078 $ 65,045 8.1 %
(1) Exclusive of depreciation and depletion.
(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 as compared with:
2024 2023 Historic Average 2023 Historic Average
Montana 485 441 448 10% warmer 8% warmer
South Dakota 778 1,035 752 25% cooler 3% warmer
Heating Degree Days 2024 as compared with:
2024 2023 Historic Average 2023 Historic Average
Montana(1)
7,033 7,237 7,554 3% warmer 7% warmer
South Dakota 6,501 7,665 7,724 15% warmer 16% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2024 and 2023 (in millions):
Utility Margin
2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates $ 51.0
Electric transmission revenue due to market conditions and rates 18.6
Montana interim rates (subject to refund) 2.8
Montana property tax tracker collections 1.2
Non-recoverable Montana electric supply costs (7.9)
QF liability adjustment (4.2)
Retail volumes (0.9)
Other (0.9)
Change in Utility Margin Items Impacting Net Income 59.7
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes 3.4
Operating expenses recovered in revenue, offset in operating and maintenance expense 1.7
Production tax credits, offset in income tax expense 0.2
Change in Items Offset Within Net Income 5.3
Increase in Utility Margin(1)
$ 65.0
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Lower electric residential and commercial retail volumes were driven by unfavorable weather in South Dakota impacting residential demand and lower commercial demand in all jurisdictions as compared to the prior year, partly offset by higher industrial demand and customer growth.
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, 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. 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 OPERATIONS
We have various classifications of natural gas revenues, defined as follows:
•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Year Ended December 31, 2024 Compared with Year Ended December 31, 2023
Revenues Change Dekatherms Avg. Customer Counts
2024 2023 $ % 2024 2023 2024 2023
(in thousands)
Montana $ 110,215 $ 136,097 (25,882) (19.0) % 13,749 14,008 185,644 183,810
South Dakota 26,884 36,638 (9,754) (26.6) 2,709 3,179 42,577 42,053
Nebraska 21,205 35,539 (14,334) (40.3) 2,294 2,581 37,958 37,793
Residential 158,304 208,274 (49,970) (24.0) 18,752 19,768 266,179 263,656
Montana 59,925 73,721 (13,796) (18.7) 7,782 8,036 26,164 25,725
South Dakota 18,069 25,869 (7,800) (30.2) 2,791 3,169 7,383 7,232
Nebraska 11,432 22,114 (10,682) (48.3) 1,664 1,916 5,056 5,023
Commercial 89,426 121,704 (32,278) (26.5) 12,237 13,121 38,603 37,980
Industrial 1,041 1,392 (351) (25.2) 147 157 237 232
Other 1,352 1,681 (329) (19.6) 207 209 197 190
Total Retail Gas $ 250,123 $ 333,051 $ (82,928) (24.9) % 31,343 33,255 305,216 302,058
Regulatory amortization 19,017 (25,012) 44,029 (176.0)
Wholesale and other 44,057 45,271 (1,214) (2.7)
Total Revenues $ 313,197 $ 353,310 $ (40,113) (11.4) %
Fuel, purchased supply and direct transmission expense(1)
104,238 157,507 (53,269) (33.8)
Utility Margin(2)
$ 208,959 $ 195,803 $ 13,156 6.7 %
(1) Exclusive of depreciation and depletion.
(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 as compared with:
2024 2023 Historic Average 2023 Historic Average
Montana(1)
7,265 7,478 7,791 3% warmer 7% warmer
South Dakota 6,501 7,665 7,724 15% warmer 16% warmer
Nebraska 5,241 5,893 6,085 11% warmer 14% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2024 and 2023 (in millions):
Utility Margin
2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates 11.4
Montana natural gas transportation 2.3
Montana interim rates (subject to refund) 2.0
Retail volumes (4.0)
Montana property tax tracker collections
(0.1)
Other (2.1)
Change in Utility Margin Impacting Net Income 9.5
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes 3.0
Operating expenses recovered in revenue, offset in operating and maintenance expense 0.7
Change in Items Offset Within Net Income 3.7
Increase in Utility Margin(1)
$ 13.2
(1) Non-GAAP financial measure. 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.
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
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 to the Consolidated Financial Statements for more information regarding these dividend restrictions.
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 December 31, 2024, our total consolidated net liquidity was approximately $191.3 million, including $4.3 million of cash and $187.0 million of revolving credit facility availability with no letters of credit outstanding.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
Year Ended December 31,
2024 2023
Operating Activities
Net income $ 224.1 $ 194.1
Non-cash adjustments to net income 213.5 210.1
Changes in working capital (18.9) 115.6
Other noncurrent assets and liabilities (11.9) (30.6)
Cash Provided by Operating Activities 406.8 489.2
Investing Activities
Property, plant and equipment additions (549.3) (566.9)
Other investing activity
(5.2) (3.9)
Cash Used in Investing Activities (554.5) (570.8)
Financing Activities
Proceeds from issuance of common stock, net - 73.6
Issuance of long-term debt 215.0 300.0
Dividends on common stock (158.6) (154.1)
Line of credit borrowings (repayments), net
95.0 (132.0)
Financing costs (1.1) (4.3)
Treasury stock activity 1.2 1.1
Cash Provided by Financing Activities 151.5 84.3
Net Increase in Cash, Cash Equivalents, and Restricted Cash $ 3.8 $ 2.7
Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 25.2 $ 22.5
Cash, Cash Equivalents, and Restricted Cash, end of period $ 29.0 $ 25.2
Operating Activities
As of December 31, 2024, cash, cash equivalents, and restricted cash were $29.0 million as compared with $25.2 million as of December 31, 2023. Cash 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 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)
Beginning of year End of year Net cash inflows
2023 $ 115.4 $ 7.8 $ 107.6
2024 $ 7.8 $ 5.9 $ 1.9
Improvement in annual net cash inflows
$ (105.7)
Investing Activities
Cash used in investing activities totaled $554.5 million during the year ended December 31, 2024, as compared with $570.8 million during 2023. Plant additions during 2024 include capital maintenance additions of approximately $324.0 million and capacity related capital expenditures of approximately $225.3 million. Plant additions during 2023 included capital maintenance additions of approximately $321.9 million and capacity related capital expenditures of approximately $245.0 million. 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, 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
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, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to be $531 million in 2025, $549 million in 2026, and $557 million in 2027. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt issuances and future rate increases. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic
growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
Short-term Borrowings
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
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 - 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):
Amount outstanding at year end $ 413.0
Daily average amount outstanding $ 237.1
Maximum amount outstanding $ 413.0
Minimum amount outstanding $ 69.0
As of February 7, 2025, availability under our revolving credit facilities was approximately $233.0 million, and there were no letters of credit outstanding.
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $300.0 million of long-term debt maturing in 2025, which we intend to refinance.
For further information on our long-term debt, see Note 11 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
For further information regarding equity, see Note 16 - Common Stock to the Consolidated Financial Statements included herein.
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 February 7, 2025, our current ratings with these agencies are as follows:
Issuer Rating Senior Secured Rating Senior Unsecured Rating Outlook
NorthWestern Energy Group
Fitch(1)
BBB - BBB Stable
Moody’s
- - - -
S&P
BBB - - Stable
NW Corp
Fitch(1)
BBB A- BBB+ Stable
Moody’s
Baa2 A3 Baa2 Stable
S&P
BBB A- - Stable
NWE Public Service
Fitch(1)
BBB A- BBB+ Stable
Moody’s
Baa2 A3 - Stable
S&P
BBB A- - Stable
(1) This Fitch Issuer Rating represents the Issuer Default Rating.
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. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2024. See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements.
Total 2025 2026 2027 2028 2029 Thereafter
(in thousands)
Long-term debt(1)
$ 3,007,660 $ 300,000 $ 105,000 $ - $ 592,660 $ 33,000 $ 1,977,000
Finance leases 5,461 3,596 1,865 - - - -
Short-term borrowings
100,000 100,000 - - - - -
Estimated pension and other postretirement obligations(2)
50,310 11,310 9,750 9,750 9,750 9,750 N/A
QF liability(3)
228,952 60,360 55,393 56,665 42,400 14,134 -
Supply and capacity contracts(4)
4,228,637 345,821 365,202 350,381 349,347 350,201 2,467,685
Contractual interest payments on debt(5)
1,650,442 133,927 122,884 120,847 118,780 89,359 1,064,645
Commitments for significant capital projects(6)
66,837 57,975 8,862 - - - $ -
Total Commitments(7)
$ 9,338,299 $ 1,012,989 $ 668,956 $ 537,643 $ 1,112,937 $ 496,444 $ 5,509,330
(1) Represents cash payments for long-term debt and excludes $12.4 million of debt discounts and debt issuance costs, net.
(2) We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other 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 $229.0 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $205.8 million.
(4) We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts (exclusive of the qualifying facilities liability discussed above). These commitments range from one to 24 years.
The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC, as further described in Note 3 - Regulatory Matters.
(5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 5.71 percent on the outstanding balance through maturity of the credit facilities.
(6) Represents significant firm purchase commitments for construction of planned capital projects.
(7) The table above excludes potential tax payments related to unrecognized tax benefits as they are not practicable to estimate. 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.
Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $15.8 million and $15.7 million as of December 31, 2024 and 2023, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced.
CRITICAL ACCOUNTING ESTIMATES
Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated 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 have identified the policies and related procedures below that contain accounting estimates that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations.
Regulatory Assets and Liabilities
Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets.
While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 4 - Regulatory Assets and Liabilities to the Consolidated Financial Statements for further discussion.
Pension and Postretirement Benefit Plans
We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 14 - Employee Benefit Plans to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
•Discount rates used in determining the future benefit obligations;
•Expected long-term rate of return on plan assets; and
•Mortality assumptions.
We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions.
We set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. 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, 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 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
The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):
Actuarial Assumption Change in Assumption Impact on Pension Cost Impact on Projected
Benefit Obligation
Discount rate increase 0.25 % $ 195 $ (11,443)
Discount rate decrease (0.25) % 1,171 11,973
Rate of return on plan assets increase 0.25 % (982) N/A
Rate of return on plan assets decrease (0.25) % 982 N/A
Accounting Treatment
We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees.
Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates.
The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $9.6 million as of December 31, 2024. The resolution of tax matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows. See Note 12 - Income Taxes to the Consolidated Financial Statements for further discussion.
NEW ACCOUNTING STANDARDS
See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.
Interest Rate Risk
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facilities. Our credit facilities bear interest at rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. As of December 31, 2024, we had $413.0 million in borrowings under our revolving credit facilities. A 1.0 percent increase in interest rates would increase our annual interest expense by approximately $4.1 million.
Commodity Price Risk
We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases and sales, including forward contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is mitigated because these commodity costs are included in our Montana, South Dakota and Nebraska cost tracking mechanisms and are recoverable from customers subject to a regulatory review for prudency and, in Montana, a sharing mechanism.
Counterparty Credit Risk
We are exposed to counterparty credit risk related to the ability of counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. If counterparties seek financial protection under bankruptcy laws, we are exposed to greater financial risks. We are also exposed to counterparty credit risk related to providing transmission service to our customers under our OATT and under gas transportation agreements. We have risk management policies in place to limit our transactions to high quality counterparties. We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial information, including the reports of independent registered public accounting firm and the quarterly financial information, required by this Item 8 are indexed in Item 15 of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
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 December 31, 2024, our disclosure controls and procedures are 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.
Management's Annual Report on Internal Control over Financial Reporting
The management of NorthWestern is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board regarding the preparation and fair presentation of published financial statements.
All internal controls over financial reporting, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention or overriding of controls. Therefore, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
Our management, including our chief executive officer and chief financial officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2024. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on our evaluation, management concluded that, as of December 31, 2024, our internal control over financial reporting was effective based on those criteria.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. Their report appears on page.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
During the three months ended December 31, 2024, no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading agreement" or "non-Rule 10b5-1 trading agreement," as each term is defined in Item 408(a) of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item with respect to directors and corporate governance will be set forth in NorthWestern Energy Group's Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to our Executive Officers is included under "Information about our Executive Officers" in Item 1 of this report.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item will be set forth in NorthWestern Energy Group's Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item will be set forth in NorthWestern Energy Group's Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information concerning relationships and related transactions of the directors and officers of NorthWestern Energy Group and director independence will be set forth in NorthWestern Energy Group's Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information concerning fees paid to the principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34), for each of the last two years will be set forth in NorthWestern Energy Group's Proxy Statement for its 2025 Annual Meeting of Shareholders, which is incorporated herein by reference.
Part IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
(1)Consolidated Financial Statements.
The following items are included in Part II, Item 8 of this annual report on Form 10-K:
CONSOLIDATED FINANCIAL STATEMENTS:
Page
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2024, 2023, and 2022
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2024, 2023 and 2022
Consolidated Balance Sheets as of December 31, 2024 and 2023
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023, and 2022
Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2024, 2023, and 2022
Notes to Consolidated Financial Statements
Fourth Quarter Unaudited Financial Data for the Years Ended December 31, 2024 and 2023
Schedule 1 - Condensed Financial Information of NorthWestern Energy Group
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes thereto.
(2)Exhibits.
The exhibits listed below are hereby filed with the SEC, as part of this Annual Report on Form 10-K. Certain of the following exhibits have been previously filed with the SEC pursuant to the requirements of the Securities Act of 1933 or the Securities Exchange Act of 1934. Such exhibits are identified by the parenthetical references following the listing of each such exhibit and are incorporated by reference. We will furnish a copy of any exhibit upon request, but a reasonable fee may be charged to cover our expenses in furnishing such exhibit.
Exhibit
Number Description of Document
2.1(a)
Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated October 20, 2004, Commission File No. 1-10499).
2.1(b)
Order Confirming the Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.2 of NorthWestern Corporation's Current Report on Form 8-K, dated October 20, 2004, Commission File No. 1-10499).
2.1(c)
Agreement and Plan of Merger, dated October 2, 2023 by and among NorthWestern Corporation, NorthWestern Energy Group, Inc. and NorthWestern Energy Merger Company, dated as of October 2, 2023 (incorporated by reference to Exhibit 2(a) of NorthWestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023).
2.1(d)
Colstrip Units 3&4 Interests Abandonment and Acquisition Agreement, dated as of January 16, 2023, by and between Avista Corporation and Northwestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated January 17, 2023, Commission File No. 1-10499).
2.1(e)
Colstrip Units 3&4 Interests Abandonment and Acquisition Agreement, dated as of July 30, 2024 by and between Northwestern Corporation and Puget Sound Energy Inc. (incorporated by reference to Exhibit 2.1 of NorthWestern Energy Group, Inc.'s Current Report on Form 8-K, dated July 30, 2024 Commission File No. 000-56598).
3.1(a)
Amended and Restated Certificate of Incorporation of NorthWestern Energy Group, Inc., dated as of September 25, 2023 (incorporated by reference to Exhibit 3(a) of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023).
3.2(b)
Amended and Restated Bylaws of NorthWestern Energy Group, Inc., dated as of September 29, 2023 (incorporated by reference to Exhibit 3(b) of Northwestern Energy Group Inc.'s Current Report on Form 8-K, date October 2, 2023).
4.1(a) First Mortgage and Deed of Trust, dated as of October 1, 1945, by The Montana Power Company in favor of Guaranty Trust Company of New York and Arthur E. Burke, as trustees (incorporated by reference to Exhibit 7(e) of The Montana Power Company's Registration Statement, Commission File No. 002-05927).
4.1(b)
Eighteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of August 5, 1994 (incorporated by reference to Exhibit 99(b) of The Montana Power Company's Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739).
4.1(c)
Twenty-Eighth Supplemental Indenture, dated as of October 1, 2009, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, Commission File No. 1-10499).
4.1(d)
Twenty-Ninth Supplemental Indenture, dated as of May 1, 2010, among NorthWestern Corporation and The Bank of New York Mellon and Ming Ryan, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499).
4.1(e)
Thirtieth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon and Philip L. Watson, as trustees under the Mortgage and Deed of Trust dated as of October 1, 1945 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).
4.1(f)
Thirty-First Supplemental Indenture, dated as of December 1, 2013, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2013, Commission File No. 1-10499).
4.1(g)
Thirty-Second Supplemental Indenture, dated as of November 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.4(n) of the Company's Report on Form 10-K for the year ended December 31, 2014, Commission File No. 1-10499).
4.1(h)
Thirty-Third Supplemental Indenture, dated as of November 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 14, 2014, Commission File No. 1-10499).
4.1(i)
Thirty-Fourth Supplemental Indenture, dated as of January 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.4(p) of the Company's Report on Form 10-K for the year ended December 31, 2014, Commission File No. 1-10499).
4.1(j)
Thirty-Fifth Supplemental Indenture, dated as of June 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2015, Commission File No. 1-10499).
4.1(k)
Thirty-Seventh Supplemental Indenture, dated as of November 1, 2017, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated November 8, 2017, Commission File No. 1-10499).
4.1(l)
Thirty-Eighth Supplemental Indenture, dated as of June 1, 2019, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated July 2, 2019, Commission File No. 1-10499).
4.1(m)
Thirty-Ninth Supplemental Indenture, dated as of September 1, 2019, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated September 20, 2019, Commission File No. 1-10499).
4.1(n)
Fortieth Supplemental Indenture, dated as of April 1, 2020, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 15, 2020, Commission File No. 1-10499).
4.1(o)
Forty-Second Supplemental Indenture, dated as of March 1, 2023, between the Company and The Bank of New York Mellon and Mary Miselis, as trustees, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 30, 2023, Commission File No. 1-10499).
4.1(p)
Forty-third Supplemental Indenture, dated as of May 1, 2023, between the Company and The Bank of New York Mellon and Mary Miselis, as trustees. (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated June 5, 2023, Commission File No. 1-10499).
4.1(q)
Forty-fourth Supplemental Indenture, dated as of June 1, 2023, between NorthWestern Corporation and The Bank of New York Mellon and Mary Miselis, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).
4.1(r)
Forty-fifth Supplemental Indenture, dated as of March 1, 2024, between NW Corp and The Bank of New York Mellon and Dimple Gandhi, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated March 28, 2024, Commission File No. 000-56598).
4.2(a) General Mortgage Indenture and Deed of Trust, dated as of August 1, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(a) of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 1993, Commission File No. 1-10499).
4.2(b)
Supplemental Indenture, dated as of November 1, 2004, by and between NorthWestern Corporation (formerly known as Northwestern Public Service Company) and JPMorgan Chase Bank (successor by merger to The Chase Manhattan Bank (National Association)), as Trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.5 of NorthWestern Corporation's Current Report on Form 8-K, dated November 1, 2004, Commission File No. 1-10499).
4.2(c)
Ninth Supplemental Indenture, dated as of May 1, 2010, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499).
4.2(d)
Tenth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon, as trustees under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).
4.2(e)
Eleventh Supplemental Indenture, dated as of December 1, 2013, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2013, Commission File No. 1-10499).
4.2(f)
Twelfth Supplemental Indenture, dated as of December 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2014, Commission File No. 1-10499).
4.2(g)
Thirteenth Supplemental Indenture, dated as of September 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, Commission File No. 1-10499).
4.2(h)
Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499).
4.2(i)
Fifteenth Supplemental Indenture, dated as of September 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 6, 2016, Commission File No. 1-10499).
4.2(j)
Sixteenth Supplemental Indenture, dated as of April 1, 2020, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 15, 2020, Commission File No. 1-10499).
4.2(k)
Seventeenth Supplemental Indenture, dated as of March 1, 2023, between the Company and The Bank of New York Mellon, as trustee, (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 30, 2023, Commission File No. 1-10499).
4.2(l)
Eighteenth Supplemental Indenture, dated as of May 1, 2023, between the Company and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 1, 2023, Commission File No. 1-10499).
4.2(m)
Nineteenth Supplemental Indenture, dated as of June 1, 2023, between the Company and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 5, 2023, Commission File No. 1-10499).
4.2(n)
Twentieth Supplemental Indenture, dated as of January 1, 2024, between NWE Public Service and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1of NorthWestern Energy Group's Current Report on Form 8-K, dated January 2, 2024, Commission File No. 000-56598).
4.2(o)
Twenty-first Supplemental Indenture, dated as of March 1, 2024, between NWE Public Service and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Energy Group's Current Report on Form 8-K, dated March 28, 2024, Commission File No. 000-56598).
4.3(a)
Indenture, dated as of August 1, 2016, between City of Forsyth, Rosebud County, Montana and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(b)
Loan Agreement, dated as of August 1, 2016, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit 4.2 of the Company's Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(c)
Bond Delivery Agreement, dated as of August 1, 2016, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(d)
Thirty-Sixth Supplemental Indenture, dated as of August 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(e)
Forty-First Supplemental Indenture, dated as of March 1, 2021, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 26, 2021, Commission File No. 1-10499).
4.3(f)
Indenture, dated as of June 1, 2023 between City of Forsyth, Rosebud County, Montana and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).
4.3(g)
Loan Agreement, dated as of June 1, 2023, by and between the City of Forsyth, Rosebud County, Montana, and NorthWestern Corporation (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).
4.3(h)
Bond Delivery Agreement, dated as of June 1, 2023, between NorthWestern Corporation and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).
4.3(i)
20th Supplemental Indenture, dated January 1, 2024 (incorporated by reference to Exhibit 4.1 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated January 2, 2024).
4.5
Description of Securities (incorporated by reference to Exhibit 99(b) of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023).
10.1(a) †
NorthWestern Corporation Officers Deferred Compensation Plan, as amended October 2, 2023. (incorporated by reference to Exhibit 10.1a of NorthWestern Energy Group's Report on Form 10-K for the year ended December 31, 2023, Commission File No. 000-56598).
10.1(b) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 23, 2019, Commission File No. 1-10499).
10.1(c) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2020, Commission File No. 1-10499).
10.1(d) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2021, Commission File No. 1-10499).
10.1(e) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2022, Commission File No. 1-10499).
10.1(f) †
NorthWestern Energy 2023 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 13, 2022, Commission File No. 1-10499).
10.1(g) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 13, 2022, Commission File No. 1-10499).
10.1(h) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 17, 2023, Commission File No. 1-10499).
10.1(i) †
Form of NorthWestern Corporation Restricted Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 17, 2023, Commission File No. 1-10499).
10.1(j) †
NorthWestern Energy Group, Inc., Deferred Compensation Plan for Non-Employee Directors, as amended and renamed effective October 2, 2023 (incorporated by reference to Exhibit 10.1(b) of NorthWestern Group Inc.’s Current Report on form 10-Q, dated October 27, 2023, Commission File No. 000-56598).
10.1(k) †
NorthWestern Energy Group Inc.'s 2024 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 20, 2023, Commission File No. 000-56598).
10.1(l) †
Form of 2024 Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Energy Group’s Current Report on Form 8-K, dated February 20, 2024, Commission File No. 000-56598).
10.1(m) †
Form of 2024 Restricted Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Energy Group’s Current Report on Form 8-K, dated February 20, 2024, Commission File No. 000-56598).
10.1(n) †
NorthWestern Corporation Amended and Restated Key Employee Severance Plan, as amended and restated effective April 25, 2024. (incorporated by reference to Exhibit 10.7 of NorthWestern Energy Group's Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, Commission File No. 000-56598).
10.1(o) †
NorthWestern Energy Group, Inc. Amended and Restated Equity Compensation Plan, as amended and restated effective April 25, 2024. (incorporated by reference to Exhibit 10.8 of NorthWestern Energy Group's Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, Commission File No. 000-56598).
10.1 (p) †
NorthWestern Energy Group Inc.'s 2025 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 12, 2024, Commission File No. 000-56598).
10.2(a)
Second Amended and Restated Credit Agreement, dated November 29, 2023 (incorporated by reference to Exhibit 10.1 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated December 5, 2023).
10.2(b)
$200,000,000 Credit Agreement, dated November 29, 2023 (incorporated by reference to Exhibit 10.2 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated December 5, 2023).
10.2 (c)
Term Loan Credit Agreement, dated April 12, 2024 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated April 12, 2024, Commission File No. 000-56598).
10.3(a)
Engineering, Procurement, and Construction Contract, dated April 19, 2021, between Northwestern Energy and Burns & McDonnell Engineering Company, Inc. (incorporated by reference to Exhibit 10.3 of NorthWestern Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, Commission File No. 1-10499).
10.3(b)
Procurement Contract, dated April 19, 2021, between Northwestern Energy and Caterpillar Power Generation Systems, LLC (incorporated by reference to Exhibit 10.4 of NorthWestern Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, Commission File No. 1-10499).
10.5
Asset and Stock Transfer Agreement, dated December 27, 2023 (incorporated by reference to Exhibit 10.1 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated January 2, 2024).
19*
Policy for insider trading
21*
Subsidiaries of NorthWestern Group, Inc.
23*
Consent of Independent Registered Public Accounting Firm
24* Power of Attorney (included on the signature page of this Annual Report on Form 10-K)
31.1*
Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1*
Certification of Brian B. Bird pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification of Crystal Lail pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Policy for the recovery of erroneously awarded compensation (incorporated by reference to Exhibit 97 of the NorthWestern Energy Group, Inc.'s Report on Form 10-K for the year ended December 31, 2023, Commission File No. 000-56598)
101.INS* Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH* Inline XBRL Taxonomy Extension Schema Document
101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* Inline XBRL Taxonomy Label Linkbase Document
101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
† Management contract or compensatory plan or arrangement.
* Filed herewith.
All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are not applicable, and, therefore, have been omitted.