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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023

OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from          to          

Commission File Number: 000-56598
logoa18.jpg
NORTHWESTERN ENERGY GROUP, INC.
(Exact name of registrant as specified in its charter)
Delaware 93-2020320
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
3010 W. 69th StreetSioux FallsSouth Dakota 57108
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 605-978-2900

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common stockNWENasdaq Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for shorter period that the registrant was required to submit such files). Yes x No o
 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
x
 Accelerated Filer
Non-accelerated Filer
Smaller Reporting Company
Emerging Growth Company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Yes o  No o

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to the previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes   No x
 




The aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant was $3,404,946,692 computed using the last sales price of $56.76 per share of the registrant’s common stock on June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter.
 
As of February 9, 2024, 61,256,549 shares of the registrant’s common stock, par value $0.01 per share, were outstanding.

Documents Incorporated by Reference
Certain sections of our Proxy Statement for the 2024 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K






INDEX PAGE
 Part I
 Part II
   
 Part III 
   
 Part IV 
F-1
F-4

3



SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Annual Report on Form 10-K regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Annual Report, relating to our current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, our examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, and wildfire damages in excess of liability insurance coverage, could have a material effect on our liquidity, results of operations and financial condition;
the impact of extraordinary external events and natural disasters, such as a wide-spread or global pandemic, geopolitical events, earthquake, flood, drought, lightning, weather, wind, and fire, could have a material effect on our liquidity, results of operations and financial condition;
acts of terrorism, cybersecurity attacks, data security breaches, or other malicious acts that cause damage to our generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;
supply chain constraints, recent high levels of inflation for product, services and labor costs, and their impact on capital expenditures, operating activities, and/or our ability to safely and reliably serve our customers;
changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;
unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase operating costs or may require additional capital expenditures or other increased operating costs; and
adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part I, Item 1A of this Annual Report on Form 10-K.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Annual Report on Form 10-K, our reports on Forms 10-Q and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Annual Report on Form 10-K, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Annual Report on Form 10-K or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects
4



in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Energy Group,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Energy Group, Inc. and its subsidiaries.
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GLOSSARY

Accounting Standards Codification (ASC) - The single source of authoritative nongovernmental GAAP, which supersedes all existing accounting standards.

Allowance for Funds Used During Construction (AFUDC) - A regulatory accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

Asset Retirement Obligations (ARO) - The legal obligations associated with retirement of a long-lived asset.

Base-Load - The minimum amount of electric power or natural gas delivered or required over a given period of time at a steady rate. The minimum continuous load or demand in a power system over a given period of time usually is not temperature sensitive.

Base-Load Capacity - The generating equipment normally operated to serve loads on an around-the-clock basis.

BGGS - The Bob Glanzer Generating Station located near Huron, South Dakota, a 58 MW natural gas fired facility.

Capacity - The amount represents the maximum output of electricity a generator can produce and is related to peak demand. We must maintain a level of available capacity sufficient to meet peak demand with a sufficient reserve.

Colstrip - A jointly owned sub-bituminous coal fired facility located near Colstrip, Montana, of which we have a 30 percent ownership of Unit 4.

Commercial Customers - Consists primarily of main street businesses, shopping malls, grocery stores, gas stations, bars and restaurants, professional offices, hospitals and medical offices, motels, and hotels.

Cushion Gas - The natural gas required in a gas storage reservoir to maintain a pressure sufficient to permit recovery of stored gas.

DGGS - The Dave Gates Generating Station at Mill Creek, a 150 MW natural gas fired facility.

Environmental Protection Agency (EPA) - A Federal agency charged with protecting the environment.

Federal Energy Regulatory Commission (FERC) - The Federal agency that has jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas transmission and related services pricing, oil pipeline rates and gas pipeline certification.

Franchise - A special privilege conferred by a unit of state or local government on an individual or corporation to occupy and use the public ways and streets for benefit to the public at large. Local distribution companies typically have franchises for utility service granted by state or local governments.

GAAP - Accounting principles generally accepted in the United States of America.

Greenhouse Gas (GHG) - Gas that traps heat in the atmosphere

Hedging - Entering into transactions to manage various types of risk (e.g. commodity risk).

Industrial Customers - Consists primarily of manufacturing and processing businesses that turn raw materials into products.

Integrated Resource Plan (IRP) - A plan that is presented to a regulatory commission. The plan identifies resource needs, known and expected risks, as well as key variables to be used in evaluating energy supply resources.

Lignite Coal - The lowest rank of coal, often referred to as brown coal, used almost exclusively as fuel for steam-electric power generation. It has high inherent moisture content, sometimes as high as 45 percent. The heat content of lignite ranges from 9 to 17 million Btu per ton on a moist, mineral-matter-free basis.

Mercury Air Toxics Standard (MATS) - This standard limits the amount of mercury and other toxic emissions from power plants.

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Montana Department of Environmental Quality (MDEQ) - The state agency that works to enhance the health of Montana's natural environment and the vitality of the state's fish, wildlife, cultural, and historic resources.

Midcontinent Independent System Operator (MISO) - MISO is a nonprofit organization created in compliance with FERC as a regional transmission organization, to improve the flow of electricity in the regional marketplace and to enhance electric reliability. Additionally, MISO is responsible for managing the energy markets, managing transmission constraints, managing the day-ahead, real-time and financial transmission rights markets, and managing the ancillary market.

Midwest Reliability Organization (MRO) - MRO is one of eight regional electric reliability councils under NERC.

Montana Public Service Commission (MPSC) - The state agency that regulates public utilities doing business in Montana.

Nameplate Capacity - The intended full-load sustained output of a generating facility. Nameplate capacity is the number registered with authorities for classifying the power output of a power station usually expressed in MWs.

Nebraska Public Service Commission (NPSC) - The state agency that regulates public utilities doing business in Nebraska.

Net Operating Loss (NOL) - net operating loss as it relates to Federal and State income tax law and results from tax-deductible expenses exceeding taxable revenues for a taxable year.

North American Electric Reliability Corporation (NERC) - NERC oversees eight regional reliability entities and encompasses all of the interconnected power systems of the contiguous United States. NERC's major responsibilities include developing standards for power system operation, monitoring and enforcing compliance with those standards, assessing resource adequacy, and providing educational and training resources as part of an accreditation program to ensure power system operators remain qualified and proficient.

NorthWestern Energy Group, Inc. - The Company; Also known as NorthWestern Energy Group.

NorthWestern Corporation (NW Corp) - A direct, wholly-owned regulated utility subsidiary of NorthWestern Energy Group providing both electric and natural gas services in Montana and electric services to Yellowstone National Park.

NorthWestern Energy Public Service Corporation (NWE Public Service) - A direct, wholly-owned regulated utility subsidiary of NorthWestern Energy Group providing both electric and natural gas services in South Dakota and natural gas services in Nebraska.

Open Access - Non-discriminatory, fully equal access to transportation or transmission services offered by a pipeline or electric utility.

Open Access Transmission Tariff (OATT) -The OATT, which is established by the FERC, defines the terms and conditions of point-to-point and network integration transmission services offered by us, and requires that transmission owners provide open, non-discriminatory access on their transmission system to transmission customers.

Peak Load - A measure of the maximum amount of energy delivered at a point in time.

Power Cost and Credit Recovery Mechanism (PCCAM) - A tracker used in our Montana jurisdiction to track, for recovery through utility rates, the cost of power purchased and fuel used to generate electricity.

Qualifying Facility (QF) - As defined under the Public Utility Regulatory Policies Act of 1978 (PURPA), a QF sells power to a regulated utility at a price agreed to by the parties or determined by a public service commission that is intended to be equal to that which the utility would otherwise pay if it were to generate its own power or buy power from another source.

Request for Proposals (RFP) - The resource solicitation process that is run by a third party and evaluates the least cost resources that address key risks and needs identified by the IRP.

Reserve Margin - The difference between available capacity and peak demand used in system planning to ensure adequate power supply. A positive percentage indicates the electric system has excess capacity while a negative percentage indicates the electric system is unable to meet peak demand without using market resources.

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Securities and Exchange Commission (SEC) - The U.S. agency charged with protecting investors, maintaining fair, orderly and efficient markets and facilitating capital formation.

Secured Overnight Financing Rate (SOFR) - A broad measure of the cost of borrowing cash overnight collateralized by Treasury securities.

South Dakota Public Utilities Commission (SDPUC) - The state agency that regulates public utilities doing business in South Dakota.

Southwest Power Pool (SPP) - A nonprofit organization created in compliance with FERC as a regional transmission organization to ensure reliable supplies of power, adequate transmission infrastructure, and a competitive wholesale electricity marketplace. SPP also serves as a regional electric reliability entity under NERC.

Tariffs - A collection of the rate schedules and service rules authorized by a federal or state commission. It lists the rates a regulated entity will charge to provide service to its customers as well as the terms and conditions that it will follow in providing service.

Transmission - The flow of electricity from generating stations and interconnections with other systems over high voltage lines to substations. The electricity then flows from the substations into a distribution network.

Western Area Power Administration (WAPA) - A federal power-marketing administration and electric transmission agency established by Congress.

Western Electricity Coordination Council (WECC) - WECC is one of eight regional electric reliability councils under NERC.

YCGS - The Yellowstone County Generating Station is a 175 MW natural gas fired facility, located near Laurel, Montana, which is currently under construction and expected to be online no later than the end of the third quarter 2024.
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Measurements:

Billion Cubic Feet (Bcf) - A unit used to measure large quantities of gas, approximately equal to 1 trillion Btu.

British Thermal Unit (Btu) - A basic unit used to measure natural gas; the amount of natural gas needed to raise the temperature of one pound of water by one degree Fahrenheit.

Degree-Day - A measure of the coldness / warmness of the weather experienced, based on the extent to which the daily mean temperature falls below or above 65 degrees Fahrenheit.

Dekatherm - A measurement of natural gas; ten therms or one million Btu.

Kilovolt (kV) - A unit of electrical power equal to one thousand volts.

Megawatt (MW) - A unit of electrical power equal to one million watts or one thousand kilowatts.

Megawatt Hour (MWH) - One million watt-hours of electric energy. A unit of electrical energy which equals one megawatt of power used for one hour.

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Part I

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 775,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. We have provided service in South Dakota and Nebraska since 1923 and in Montana since 2002.

On October 2, 2023, NW Corp created a new public holding company, NorthWestern Energy Group, by initiating a holding company reorganization (the Reorganization), pursuant to an internal merger transaction through which NorthWestern Energy Group became the successor issuer to NW Corp under the Securities Exchange Act of 1934, as amended. On January 1, 2024, NorthWestern Energy Group, NW Corp, and NW Corp's wholly owned subsidiary, NWE Public Service, completed the final phase of its Reorganization by contributing the assets and liabilities of its South Dakota and Nebraska regulated utilities to NWE Public Service and distributing its equity interests in NWE Public Service and certain other unregulated subsidiaries to NorthWestern Energy Group. As a result of these transactions, (1) NW Corp owns and operates the Montana regulated utility; (2) NWE Public Service owns and operates the Nebraska and South Dakota regulated utilities; and (3) NW Corp and NWE Public Service are each direct, wholly owned subsidiaries 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.
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Territory.jpg

Environmental, Social and Governance

We are focused on meeting current energy infrastructure and service needs at a reasonable and fair cost for today’s customers while ensuring the ability to meet the needs of tomorrow’s customers. “Sustainability” requires meeting economic, societal, and environmental objectives. As a provider of essential infrastructure and service, a sustainable enterprise is vital to our customers and communities, as well as to our investors and employees.

Over the past 100 years, we have maintained our commitment to provide customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. 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.

We currently own a mix of clean and carbon-free energy resources balanced with traditional energy sources that are necessary for us to deliver affordable and reliable electricity to our customers 24/7. In 2023, approximately 55 percent of our retail needs originated from carbon-free resources, compared to approximately 40 percent (Source: U.S. Energy Information Administration, Annual Energy Review, Electricity Net Generation: Electric Power Sector) for the total U.S. electric power industry in 2022. 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. Our resource mix does not represent the actual energy delivered to our customers. Market purchases and sales fill the gap between resources and customer demand.

We are a fully regulated provider of critical infrastructure and essential services. Therefore, our success in meeting our obligations to our customers and the communities we serve depends on public policy. We believe that policy makers in the states we serve are committed to reliable, adequate, and affordable service, and a strong customer focus. We support policies that enable investment in critical infrastructure and responsible stewardship.

We believe that technological advancements, along with decreasing costs of carbon-free generation and the regionalization of intermittent generation, will significantly contribute to our goal of Net-Zero carbon emissions by 2050. The pace of transition to Net-Zero will depend on the timing of technological advancements, costs, and retirement of our existing coal fleet.
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In South Dakota and Montana, we develop an IRP every two and three years, respectively. These IRPs, which are presented to our state regulatory commissions, identify resource needs, known and expected risks, as well as key variables to be used in evaluating resources. We then undertake a transparent resource solicitation process, run by a third party, to evaluate the least cost resources that address key risks and needs identified by the IRP. All generation types have the opportunity to participate in our RFP. Therefore, the specific resources that will be acquired to meet future needs are dependent upon our current and future IRPs and the RFP process, in conjunction with the actions of our regulators during the regulatory process.

For a more detailed description of our environmental, social, governance and sustainability activities, please visit our company website at https://www.northwesternenergy.com. 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.

Pie Charts Summary.jpg



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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 2023, we delivered electricity to approximately 405,500 customers in 221 communities and their surrounding rural areas, 13 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2023, by category, residential, commercial, industrial, and other sales accounted for approximately 45%, 47%, 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
497 
Miles of 230 kV988 
Miles of 161 kV1,184 
Miles of 115 kV and lower voltage3,931 
Total Miles of Electric Transmission Lines6,600 
Electric Distribution Lines
Miles of overhead line
13,271 
Miles of underground line
5,403 
Total Miles of Electric Distribution Lines18,674 
Total Transmission and Distribution Substations395 

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 1,992 MWs on February 22, 2023. Our control area average demand for 2023 was approximately 1,376 MWs per hour, with total energy delivered of more than 12.05 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 requirements average approximately 750 MWs, 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 71 percent of our retail load requirements for 2023. We expect that approximately 85 percent of our retail obligations will be met by owned generation resources in 2024, reflecting the addition of YCGS which is expected to be online no later than the end of the third quarter 2024. In addition, we have contracts with QFs totaling 549 MWs of nameplate capacity, including 87 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 20 MWs of hydro supply. On average, our owned and long-term contracted resources are expected to provide enough energy to meet our retail energy load requirements in 2024. Load requirements during peak demand in excess of our owned and long-term contracted resources will be satisfied with market purchases.
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Owned Generation Facilities

NWE_GenerationMap_MT_2024.jpg


Details of these generating facilities are described in the following tables.

Hydro FacilitiesCODRiver
Source
FERC
License
Expiration
Owned MW
Black Eagle1927Missouri204025
Cochrane1958Missouri204062
Hauser1911Missouri204021
Holter1918Missouri204053
Madison1906Madison204012
Morony1930Missouri204049
Rowe(1)
1925West Rosebud Creek205012
Rainbow1910/2013Missouri204064
Ryan1915Missouri204072
Thompson Falls1915/1995Clark Fork202594
 Total(2)
464
(1) Formerly known as the Mystic Lake Dam.
(2) The Hebgen facility (0 MW net capacity) is excluded from the figures above. These are run-of-river dams except for Mystic, which is storage generation.
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Other FacilitiesFuel SourceOwnership
Interest
Owned
MW
Colstrip Unit 4, located near Colstrip in southeastern MontanaSub-bituminous coal30%222
DGGS, located near Anaconda, MontanaNatural Gas & Liquid Fuel100%150
Spion Kop Wind, located in Judith Basin County in MontanaWind100%40
Two Dot Wind, located in Wheatland County in MontanaWind100%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 Yellowstone County Generating Station in 2024 and the acquisition of an additional 222 MW of capacity in Colstrip in 2026. However, it also showed projected generation capacity deficits in future years.

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 64,800 in 116 communities in South Dakota. In 2023, by category, residential, commercial and other sales accounted for approximately 39%, 59%, 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:

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Electric Transmission Lines
Miles of 345 kV
25 
Miles of 230 kV18 
Miles of 115 kV and lower voltages
1,267 
 Total Miles of Electric Transmission Lines1,310 
Electric Distribution Lines
Miles of overhead line
1,634 
Miles of underground line
731 
Total Miles of Electric Distribution Lines2,365 
Total Transmission and Distribution Substations124 
 
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 340 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.
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Owned Generation Facilities

    SD Territory.jpg                            

Details of our generating facilities are described further in the following chart:
Generation FacilitiesFuel SourceOwnership
Interest
Owned
MW
Big Stone Plant, located near Big Stone City in northeastern South DakotaSub-bituminous coal23.4%111
Aberdeen Generating Units No. 1 and 2, located near Aberdeen, South DakotaNatural gas & Liquid Fuel100.0%80
Beethoven Wind Project, located near Tripp, South DakotaWind100.0%80
BGGS, located near Huron, South DakotaNatural Gas100.0%58
Neal Electric Generating Unit No. 4, located near Sioux City, IowaSub-bituminous coal8.7%57
Coyote Electric Generating Station, located near Beulah, North DakotaLignite coal10.0%43
Miscellaneous combustion turbine units and small diesel units (used only during peak periods)Combination of fuel oil and natural gas100.0%17
Total  446

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.
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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 September of 2022 that provided for the modernization of our generating fleet. That plan focused on improving reliability and flexibility. Following the competitive solicitation processes, we completed construction of the 58 MW BGGS in the summer of 2022. The BGGS plant includes flexible reciprocating internal combustion engines at a brownfield site near Huron, South Dakota. We plan to replace aging generation resources in the Aberdeen, South Dakota area by 2025 for a total projected cost of $70.0 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 2023, we distributed natural gas to approximately 212,100 customers in 118 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 48 Bcf during the year ended December 31, 2023.
Miles of Natural Gas Transmission2,235 
Miles of Natural Gas Distribution5,155 
City Gate Stations133 

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 15,100 horsepower at our storage fields, capable of moving more than 364,000 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 two 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, 2023, were approximately 22.5 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2023, were approximately 6.8 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, 2023, these owned reserves totaled approximately 31.5 Bcf and are estimated to provide approximately 2.8 Bcf in 2024, or approximately 12 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.
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South Dakota and Nebraska

Through NWE Public Service, we provide natural gas to approximately 49,800 customers in 80 South Dakota communities and approximately 43,100 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 five gas-marketing firms and one large end-user account. We delivered approximately 31.1 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.8 Bcf of third-party transportation volume on our Nebraska distribution system during 2023.

Miles of Natural Gas Transmission55 
Miles of Natural Gas Distribution - South Dakota
1,747 
Miles of Natural Gas Distribution - Nebraska
826 

Our South Dakota natural gas supply requirements for the year ended December 31, 2023, were approximately 6.3 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, 2023, were approximately 4.5 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, twelve of our Montana franchises could expire by action taken by the franchises' city or town, which account for approximately 83,947 or 40 percent of our Montana natural gas customers. Three of our South Dakota franchises and one franchise in Nebraska, which account for approximately 19,111 or 20 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.
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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, 2023:
Jurisdiction and ServiceImplementation DateAuthorized Rate Base (millions)Year-end Estimated Rate Base (millions)Authorized Overall Rate of ReturnAuthorized Return on EquityAuthorized Equity Level
Montana electric delivery and production(1)
November 2023$2,565.5$2,874.86.72%9.65%48.02%
Montana - Colstrip Unit 4November 2023276.9257.78.25%10.00%50.00%
Montana natural gas delivery and production(2)
November 2023582.8744.16.67%9.55%48.02%
   Total Montana$3,425.2$3,876.6
South Dakota electric(3) (4)
January 2024
$791.8$810.36.81%n/an/a
South Dakota natural gas(3)
December 201165.995.87.80%n/an/a
   Total South Dakota$857.7$906.1
Nebraska natural gas(3)
December 2007$24.3$50.18.49%10.40%n/a
$4,307.2$4,832.8
(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) On June 15, 2023, we filed a South Dakota electric rate review filing (2022 test year) with the SDPUC. See Note 3 - Regulatory Matters 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
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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.
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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. 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.

To this end, the Biden Administration set ambitious goals to address climate change, including the goal of a carbon free power sector by 2035 and net zero carbon emissions by 2050. Executive Orders issued by the Biden Administration included initiatives and directives intended to reduce GHG emissions, address climate change and decarbonize the energy sector. These Executive Orders established climate considerations as key components of United States foreign policy and national security, established a White House Office of Domestic Climate policy as well as a National Climate Task Force, called for agency heads to identify any fossil fuel subsidies provided by their agencies and to take steps to ensure that federal funding is not directly subsidizing fossil fuels, and directed agencies to immediately review all regulations proposed or finalized by the Trump Administration that conflict with the Biden Administration’s objectives and to take action to rescind or revise those rules.
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President Biden's Infrastructure Investment and Jobs Act and Inflation Reduction Act of 2022 contain significant climate initiatives. These initiatives present opportunities for federal grants and tax incentives intended to hasten the future economy-wide deployment of various GHG reducing technologies and approaches.

Implementation of these initiatives and directives has 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.

Estimated capital expenditures for environmental control facilities in 2024 and 2025 are not expected to be material. 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. On October 2, 2023, pursuant to an internal merger transaction, NorthWestern Energy Group became the successor issuer to NW Corp (incorporated in Delaware in November 1923) under the Securities Exchange Act of 1934, as amended. 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 by offering competitive salaries and benefits, providing a safe working environment, valuing diversity, fostering inclusion and encouraging a healthful work–life balance. Our success comes when employees feel empowered to take initiative, voice their opinions, and build on their experiences within our company and our communities.

As of December 31, 2023, we had 1,573 employees. Of these, 1,269 employees were in Montana and 304 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 Montana collective bargaining agreements will expire in 2026. Of our South Dakota and Nebraska employees, 171, or 56 percent, are covered by a collective bargaining agreement renegotiated in 2021 that expire in 2025. We consider our relations with employees to be good.

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.
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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 2023 and 2022, the compensation for our Chief Executive Officer (CEO) was approximately 22 and 26 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 2023, 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 23 to 1.

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 2023, with no corrective action required.

Diversity

We believe a diverse and inclusive workforce adds value and helps us succeed in an ever-changing environment. By embracing diversity and fostering inclusion, we aim to enable each employee, executive, and director to contribute fully to the company. We believe diversity is important because varied perspectives expand our ability to bring unique professional experiences to our business. Diversity in the workforce will be considered when relevant to hiring, promotions, work assignments, or other decisions related to the terms and conditions of employment. Our workforce reflects the relative diversity of our available talent in the communities we serve. Our employment data is tested annually by a third party as part of our Affirmative Action plan development to identify any needed corrective placement goals that are required. This testing determined that there is no current need to establish corrective placement goals in our plan.

We continue to maintain a diverse workforce, with an executive team that is 50% female and a board of directors that is 40% female and has two ethnically diverse members (20%).

Health and Safety

As stewards of critical infrastructure, providers of energy service, and members of the communities we serve, our priority is the health and safety of our employees and customers. Safety and health are considered and integrated into all work activities. We monitor several different key areas relating to safety philosophies and policies. These key metrics include the recordable incident rate (number of work-related injuries per 100 employees for a one-year period) and lost time incident rate (number of employees who lost time due to work-related injuries per 100 employees for a one-year period). During the years ended December 31, 2023 and 2022, our recordable incident rates were 1.34 and 1.57 and lost time incident rates were 0.45 and 0.59 on a company wide basis. Our five-year average safety record for the year ended December 31, 2023 was better than our industry peer group's five-year average.


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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Executive OfficerCurrent 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.
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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.
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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.
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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.
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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.
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Cyndee S. Fang
Vice President - Regulatory Affairs of NorthWestern Corporation since January 2023 and of NorthWestern Energy Public Service Corporation since January 1, 2024; formerly Director - Regulatory Affairs of NorthWestern Corporation since March 2021; prior to joining the Company, she was Origination & Portfolio Design Manager from December 2020 to March 2021, Manager of Energy Research & Analysis from August 2018 to December 2020, and Manager of Customer Pricing from June 2017 to August 2018, in each case, for San Diego Gas and Electric Company, an electric and gas utility.
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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.
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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.
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John D. HinesVice 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 2011.65
Michael R. Cashell
Vice President - Transmission of NorthWestern Corporation since May 2011 and of NorthWestern Energy Public Service Corporation since January 1, 2024.
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(1) As of February 9, 2024.

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

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. We believe that we are in compliance with environmental regulatory requirements.

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. No rules are currently in effect that require us to reduce our GHG emissions. However, laws and regulations to which we must adhere change, and the Biden Administration’s agenda includes a significant shift in environmental and energy policy, focusing on reducing GHG emissions and addressing climate change issues.
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Together, these actions reflect climate change issues and GHG emissions as central areas of focus for domestic and international regulations, orders and policies. In addition, a parallel focus on reducing GHG emissions is reflected in legislation introduced in Congress. These initiatives could lead to new and revised energy and environmental laws and regulations, including tax reforms relating to energy and environmental issues. Any such changes, as well as any enforcement actions or judicial decisions regarding those laws and regulations, could result in 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.

Although previous attempts by the EPA to regulate GHG emissions from coal-fired plants have not succeeded, if GHG and/or methane regulations are implemented, compliance with carbon dioxide (CO2) emission performance standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

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 our Yellowstone County Generating Station 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. Talen and Puget Sound Energy (Puget), a co-owner of Colstrip, have entered into a transaction in which Puget will transfer its 25% project share in Units 3 and 4 to Talen. The anticipated closing date of the transaction is December 31, 2025. 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.

The closure by third parties of Billings area generation (Corette) and Colstrip Units 1 and 2 reducing supply, together with increased customer load and the lack of dispatchable replacement generation in eastern Montana, has accelerated concerns about potential difficulties in physically serving parts of Montana including the Billings area. We are executing on multi-year plans for upgrades to the Billings area substations and other delivery infrastructure, but the addition of dispatchable generation in the area is also critical to reliable service in eastern Montana.
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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.
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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 generation and market purchases to serve customers. The accredited capacity of our Montana portfolio of owned and long-term contracted electric generation resources covers 75 percent of our recent peak electric requirements, with remaining needs, including additional reserve margin, served through market purchases. In the past, Montana had been a net exporter of electric generation and we have relied upon Montana's excess generation for grid reliability and to physically serve customers. However, that situation in Montana has changed and we are predominantly a net importer, especially during peak demand. 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.
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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.
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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.
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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 Energy Imbalance Market (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 have been analyzing our technology platforms and monitoring for signs of potential intrusions. We have also been reaching out to our vendors, suppliers and contractors requesting that they take 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, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases.
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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.

A pandemic or similar widespread public health concern could have a material negative impact on our business, financial condition and results of operations.

The actual or perceived effects of a disease outbreak, epidemic, pandemic or similar widespread public health concern, such as COVID-19, will likely negatively affect our business, financial condition and results of operations. The COVID-19 pandemic has had widespread impacts on people, economies, businesses and financial markets.

While the COVID-19 pandemic did not cause material disruptions to our operations, we could experience such disruptions in the future as a result of a pandemic (or a similar widespread public health concern) due to, among other things, quarantines, increased cyber risk due to employees working from home, worker absenteeism as a result of illness or other factors, social distancing measures and other travel, health-related, business or other restrictions. If a significant percentage of our workforce is unable to work, including because of illness, travel restrictions, or government mandates in connection with pandemics or disease outbreaks, our operations may be negatively affected.

Any such workforce implications and / or limitations or closures impact our ability to achieve our capital investment program and could have a material adverse impact on our ability to serve our customers and on our business, financial condition and results of operations.
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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 $100 million of 1% Montana secured debt maturing in 2024. 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. The U.S. is a party to the United Nations' "Paris Agreement" on climate change, and that agreement along with 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, the EPA has indicated that it is currently "evaluating additional opportunities" to reduce GHG emissions from existing power plants.
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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.
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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.

NorthWestern Energy Group is a holding company and relies on cash from its subsidiaries to pay dividends.

Through completion of a reorganization on January 1, 2024, NorthWestern Energy Group is a holding company parent entity and thus its primary assets are its 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

None

ITEM 1C. CYBERSECURITY

Cybersecurity Risk

As a fully integrated electric and gas utility, we operate and participate in regional markets and are interconnected with other entities. The operation of these systems depends on information technology systems we own and operate as well as third party systems and service providers. Strategic business partners are also leveraged to support our mission. As an operator of critical infrastructure, nefarious actors may find us a valuable target if they wish to disrupt our operations and negatively impact our customers. The systems and partnerships described above are all potential targets for a cyber-incident. Any significant interruption or failure of our information systems due to cyber-attacks, hacking or internal security breaches could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential, and other data could be compromised. This could adversely affect our business, our financial condition, operating results or liquidity. For the year ended December 31, 2023, there have been no cybersecurity incidents with a material impact on our business strategy, operations, or financial condition.

Risk Management and Strategy

We utilize a comprehensive, defense in depth approach to cybersecurity risk, which helps us to continually assess, identify and manage enterprise-wide material cybersecurity risks. Our cybersecurity risk management is integrated into our overall Enterprise Risk Management (ERM) process and is reviewed at least quarterly. Our cybersecurity strategy focuses on maintaining the confidentiality, integrity and availability of data. We leverage frameworks established by the National Institute of Standards and Technology and the Center for Information Security for our information and cybersecurity governance program. We have a comprehensive cybersecurity threat detection and monitoring program for our technology and network infrastructure, which leverages various systems, processes, and operational measures to monitor, detect, and respond to cyber incidents. Our cybersecurity processes, including our threat detection, monitoring, and response protocols are subject to ongoing vulnerability testing, and comparison to industry practices. An Incident Response and Disaster Recovery Plan is maintained and periodically exercised. The plan includes a process to identify, protect, detect, respond to and recover from cybersecurity threats and incidents. Resiliency and recoverability are paramount in the plan. This includes a clearly defined escalation process within the plan to ensure management and the Board of Directors are notified if an incident or series of events warrant escalation.

Our strategy includes employee training and awareness on cybersecurity risks and related best practices, required password complexity, the use of multi-factor authentication, information security protocols, modern end point protection against threats, patching strategy, the execution of tabletop exercises on a periodic basis, established policies and protocols for cyber incident response planning and reporting, and ongoing internal cybersecurity testing.

We monitor potential risks associated with the use of third-party service providers and vendors. Our cyber incident monitoring process includes dialog with any third party or business partner potentially impacted by a disclosed incident. Service providers and vendors must adhere to security requirements such as security incident or data breach notification and response protocols, appropriate data encryption requirements, and data disposal. In addition, we engage with third party consultants to perform penetration (PEN) studies. These independent third party assessments provide valuable insight to enhance our cybersecurity posture.

Board Governance

Our Board of Directors reviews the cybersecurity program through risk review and cybersecurity reporting on at least a quarterly basis. The Audit Committee oversees our ERM program, including cybersecurity protocols. The Safety, Environmental, Technology and Operations (SETO) Committee provides oversight and review of technology policy and strategy as it relates to cybersecurity issues impacting company operations. Both the Audit Committee and the SETO Committee include Directors with diverse experience in technology, finance, enterprise risk, and security providing effective assessment and oversight of cybersecurity risk. Of note, one member of the Board has bolstered their understanding of technology and security issues by obtaining a certificate in cybersecurity oversight.

Roles and Responsibilities of Management

Our cyber security team, which reports to the Vice President - Technology, has primary responsibility for cybersecurity strategy and assessing cyber risk. The Vice President - Technology is responsible for informing the Chief Executive Officer and other Officers, as necessary, about cybersecurity incidents, covering prevention, detection, mitigation, and remediation efforts as they are detected by the cyber security team. Collectively, our cyber security team has experience in cybersecurity, hold numerous industry certifications related to cybersecurity, and have experience in desktop support, networking, application administration and programming.
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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.

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.

ITEM 4. MINE SAFETY DISCLOSURES

None
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Part II



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 9, 2024, there were approximately 1,209 common stockholders of record.



ITEM 6. [RESERVED]
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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, 2023 compared to the year ended December 31, 2022, 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, 2022 compared with the year ended December 31, 2021, 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, 2022.

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 775,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2023, 2022 and 2021. 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.
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We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.

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


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HOW WE PERFORMED IN 2023 COMPARED TO OUR 2022 RESULTS

Year Ended December 31, 2023 vs. 2022
Income Before Income TaxesIncome Tax Benefit (Expense)Net Income
(in millions)
Year ended December 31, 2022$182.4 $0.6 $183.0 
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income:
Montana rate review - new base rates
32.6 (8.3)24.3 
Lower non-recoverable Montana electric supply costs14.2 (3.6)10.6 
Montana property tax tracker collections12.8 (3.2)9.6 
Higher Montana natural gas transportation2.2 (0.6)1.6 
Higher electric transmission revenue0.6 (0.2)0.4 
Lower natural gas retail volumes(7.0)1.8 (5.2)
Lower electric retail volumes(1.8)0.5 (1.3)
Higher revenue from lower production tax credits, offset within income tax benefit (expense)3.8 (3.8)— 
Other(1.7)0.4 (1.3)
Variance in expense items(2) impacting net income:
Higher depreciation expense(15.5)3.9 (11.6)
Higher interest expense(14.5)3.7 (10.8)
Higher operating, maintenance, and administrative expenses(14.4)3.6 (10.8)
Lower property and other taxes not recoverable within trackers3.0 (0.8)2.2 
Other4.9 (1.5)3.4 
Year ended December 31, 2023$201.6 $(7.5)$194.1 
Change in Net Income$11.1 
(1) Exclusive of depreciation and depletion shown separately below
(2) Excluding fuel, purchased supply, and direct transmission expense

Consolidated net income in 2023 was $194.1 million as compared with $183.0 million in 2022. This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, higher interest expense, higher operating, maintenance, and administrative expenses, and higher income tax expense.

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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.

Montana Rate Review Filing – On October 27, 2023, the MPSC issued a final order approving the settlement agreement filed April 3, 2023. Final rates, adjusting from interim to settled rates, were effective November 1, 2023. For additional information related to our Montana Rate Review Filing, see Note 3 - Regulatory Matters to the Consolidated Financial Statements.

South Dakota Electric Rate Review Filing – In June 2023, we filed a South Dakota electric rate review filing (2022 test year) for an annual increase to electric rates totaling approximately $30.9 million. Our request was based on a rate of return of 7.54 percent, a capital structure including 50.5 percent equity, and rate base of $787.3 million. In January 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $21.5 million and an authorized rate of return of 6.81 percent. The approved settlement is based on a capital structure of 50.5 percent equity and a rate base of $791.8 million. Final rates were effective January 10, 2024. In addition, the SDPUC approved a phase in rate plan rider that allows for the recovery of capital investments not yet included in base rates.

Holding Company Reorganization – On October 2, 2023, NW Corp and NorthWestern Energy Group completed a merger transaction pursuant to which NorthWestern Energy Group became the holding company parent of NW Corp. In this reorganization, shareholders of NW Corp (the predecessor publicly held parent company) became shareholders of NorthWestern Energy Group, maintaining the same number of shares and ownership percentage as held in NW Corp immediately prior to the reorganization. NW Corp became a wholly-owned subsidiary of NorthWestern Energy Group. The transaction was effected pursuant to a merger pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the shareholders of the constituent corporation. Immediately after consummation of the reorganization, NorthWestern Energy Group had, on a consolidated basis, the same assets, businesses and operations as NW Corp had immediately prior to the consummation of the reorganization. As a result of the reorganization, NorthWestern Energy Group became the successor issuer to NW Corp pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, and as a result, NorthWestern Energy Group's common stock was deemed registered under Section 12(b) of the Securities Exchange Act of 1934. On January 1, 2024, we completed the second and final phase of the holding company reorganization. NW Corp contributed the assets and liabilities of its South Dakota and Nebraska regulated utilities to NWE Public Service, and then distributed its equity interest in NWE Public Service and certain other subsidiaries to NorthWestern Energy Group, resulting in NW Corp owning and operating the Montana regulated utility and NWE Public Service owning and operating the Nebraska and South Dakota utilities, each as a direct subsidiary of NorthWestern Energy Group.

Power Costs and Credits Adjustment Mechanism - The MPSC's September 2022 decision approving interim rates related to our Montana rate review included a $61.1 million increase to the PCCAM Base, from $138.7 million to $199.8 million, effective October 1, 2022. The MPSC's October 2023 decision approving the Montana rate review settlement agreement increased the PCCAM Base to $208.4 million, with retroactive application to July 1, 2022. We have under-collected our total Montana electric supply costs for the July 2022 through June 2023 PCCAM year by approximately $14.5 million, which includes a $2.9 million increase to our under-collection for this tracker period to reflect the retroactive application of the higher PCCAM Base rates effective July 1, 2022. As of December 31, 2023, we have over-collected our total Montana electric supply costs for the July 2023 through June 2024 PCCAM year by approximately $4.7 million.

Under the PCCAM, net costs higher or lower than the PCCAM Base (excluding QF costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the twelve months ended December 31, 2023, we over collected supply costs of $32.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $7.0 million (10 percent of the PCCAM Base cost variance), which is inclusive of a $3.2 million increase in pre-tax earnings related to the retroactive application of higher PCCAM Base rates to July 1, 2022. For the twelve months ended December 31, 2022, we under collected costs of $64.8 million resulting in an increase to the under collection of costs, and recorded a reduction in pre-tax earnings of $7.2 million.

As discussed above, the approved Montana rate review settlement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. The updated $208.4 million PCCAM Base is retroactive to an effective date of July 1, 2022.
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Our electric supply from owned and long-term contracted resources is not adequate to meet our peak-demand needs. Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows. See the Electric Resource Planning - Montana section below for how we are working to address this market exposure.

Electric Resource Planning - Montana

Yellowstone County 175 MW plant - Construction of the new generation facility continues to progress and we expect the plant to be operational no later than the end of the third quarter 2024. The lawsuit challenging the YCGS air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and have increased costs. As of December 31, 2023, total costs of approximately $240.0 million have been incurred, with expected total costs of approximately $310.0 million to $320.0 million. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.

Acquisition of Colstrip Interest - On January 16, 2023, we entered into a definitive agreement (the Avista Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana. The Avista Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the Avista Agreement. Under the terms of this Avista Agreement, we will be responsible for operating costs starting on January 1, 2026; while Avista will retain responsibility for its pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommission and demolition costs associated with the existing facilities that comprise Avista's interest.

The Avista Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Avista Agreement is subject to customary conditions and approvals, including approval from the FERC. Closing also is conditioned on our ability to enter into a new coal supply agreement for Colstrip by December 31, 2024. Such coal supply agreement must provide a sufficient amount of coal to Colstrip to permit the generation of electric power by the maximum permitted capacity of the interest in Colstrip then held by us during the period from January 1, 2026 through, December 31, 2030.

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

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

Future Integrated Resource Planning - Resource adequacy in the Western third of the U.S. has been declining with the retirement of thermal power plants. Our owned and long-term contracted resources are inadequate to supply the necessary capacity we require to meet our peak-demand loads, which exposes us to large quantities of market purchases at typically high and volatile energy prices. To comply with regulatory resource planning requirements, we submitted an IRP to the MPSC on April 28, 2023.

We remain concerned regarding an overall lack of capacity in the West and our owned and long-term contracted capacity deficit to meet peak-demand loads. The construction of the Yellowstone County Generating Station and acquisition of Avista's Colstrip Units 3 and 4 interests are expected to reduce our exposure to market purchases.

Proposed EPA Rules

In May 2023, the EPA proposed new GHG emissions standards for coal and natural gas-fired plants. In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired); (ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units); and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired). In addition, in April 2023, EPA proposed to amend the MATS. Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. We are in compliance with existing MATS requirements. The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic.
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Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted. As MATS and GHG regulations are implemented, it could result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region.

Electric Resource Supply - South Dakota

Our electric supply resource plans for South Dakota continue to identify portfolio requirements including potential investments resulting from a completed competitive solicitation process. We anticipate filing the next resource plan in the summer of 2024.
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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):

5 Year Capex 2.14.24.jpg

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 $1.8 billion or 75 percent of our capital forecast above is projected to be spent on our distribution and transmission system. Beginning in 2021, and continuing through 2025, we expect to install automated metering infrastructure in Montana at a total cost of approximately $134.0 million, of which $41.7 million remains and is reflected in the five year capital forecast above.
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RESULTS OF OPERATIONS

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

Factors Affecting Results of Operations

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

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

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

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

Year Ended December 31, 2023 Compared with Year Ended December 31, 2022

Consolidated net income in 2023 was $194.1 million as compared with $183.0 million in 2022, an increase of $11.1 million. As described in more detail below, this increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, higher interest expense, higher operating, maintenance, and administrative expenses, and higher income tax expense.


Consolidated gross margin in 2023 was $416.3 million as compared with $376.9 million in 2022, an increase of $39.4 million or 10.5 percent. This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, and higher operating and maintenance expense.

ElectricNatural GasTotal
202320222023202220232022
(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues$1,068.8 $1,106.5 $353.3 $371.3 $1,422.1 $1,477.8 
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)262.7 324.4 157.5 167.6 420.2 492.0 
Less: Operating and maintenance166.0 167.8 54.5 53.6 220.5 221.4 
Less: Property and other taxes120.3 149.8 34.3 42.7 154.6 192.5 
Less: Depreciation and depletion174.1 162.4 36.4 32.6210.5 195.0 
Gross Margin345.7 302.1 70.6 74.8 416.3 376.9 
Operating and maintenance166.0 167.8 54.5 53.6 220.5 221.4 
Property and other taxes120.3 149.8 34.3 42.7 154.6 192.5 
Depreciation and depletion174.1 162.4 36.4 32.6 210.5 195.0 
Utility Margin(1)
$806.1 $782.1 $195.8 $203.7 $1,001.9 $985.8 
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

 Year Ended December 31,
 20232022Change% Change
 (in millions)
Utility Margin    
Electric$806.1 $782.1 $24.0 3.1 %
Natural Gas195.8 203.7 (7.9)(3.9)
Total Utility Margin(1)
$1,001.9 $985.8 $16.1 1.6 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Consolidated utility margin in 2023 was $1,001.9 million as compared with $985.8 million in 2022, an increase of $16.1 million, or 1.6 percent.
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Primary components of the change in utility margin include the following (in millions):
Utility Margin
2023 vs. 2022
Utility Margin Items Impacting Net Income
Montana rate review - new base rates
$32.6 
Lower non-recoverable Montana electric supply costs14.2 
Montana property tax tracker collections12.8 
Higher Montana natural gas transportation2.2 
Higher electric transmission revenue due to market conditions0.6 
Lower natural gas retail volumes(7.0)
Lower electric retail volumes(1.8)
Other(1.7)
Change in Utility Margin Impacting Net Income51.9 
Utility Margin Items Offset Within Net Income
Lower property taxes recovered in revenue, offset in property tax expense(35.8)
Lower operating expenses recovered in revenue, offset in operating and maintenance expense(3.1)
Lower gas production taxes recovered in revenue, offset in property and other taxes(0.7)
Higher revenue from lower production tax credits, offset in income tax expense3.8 
Change in Items Offset Within Net Income(35.8)
Increase in Consolidated Utility Margin(1)
$16.1 
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

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

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

 Year Ended December 31,
 20232022Change% Change
 (in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)    
Operating and maintenance$220.5 $221.4 $(0.9)(0.4)%
Administrative and general117.3 113.8 3.5 3.1 
Property and other taxes153.1 192.5 (39.4)(20.5)
Depreciation and depletion210.5 195.0 15.5 7.9 
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)$701.4 $722.7 $(21.3)(2.9)%
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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $701.4 million in 2023, as compared with $722.7 million in 2022. Primary components of the change include the following (in millions):
Operating Expenses
 
2023 vs. 2022
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Higher depreciation expense due to plant additions$15.5 
Higher labor and benefits expense, partly offset by higher capitalization of labor and benefits costs(1)
6.1 
Higher insurance expense2.1 
Increase in uncollectible accounts1.1 
Higher expenses at our electric generation facilities1.0 
Higher cost of materials0.8 
Lower property and other taxes not recoverable within trackers(3.0)
Other3.3 
Change in Items Impacting Net Income26.9 
Operating Expenses Offset Within Net Income
Lower property and other taxes recovered in trackers, offset in revenue(35.8)
Lower pension and other postretirement benefits, offset in other income(1)
(8.7)
Lower operating expenses recovered in trackers, offset in revenue(3.1)
Lower natural gas production taxes recovered in trackers, offset in revenue(0.7)
Higher deferred compensation, offset in other income0.1 
Change in Items Offset Within Net Income(48.2)
Decrease in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)$(21.3)
(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 2023 was $300.5 million as compared with $263.1 million in 2022. This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, and higher operating, maintenance, and administrative expense.

Consolidated interest expense in 2023 was $114.6 million, as compared with $100.1 million in 2022. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC.

Consolidated other income in 2023 was $15.8 million, as compared with $19.4 million in 2022. This decrease was primarily due to an increase in the non-service cost component of pension expense, partly offset by the prior year CREP penalty and higher capitalization of AFUDC.

Consolidated income tax expense in 2023 was $7.5 million, as compared to an income tax benefit of $0.6 million in 2022. Our effective tax rate for the twelve months ended December 31, 2023 was 3.7 percent as compared with (0.3) percent for the same period of 2022. 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 12.0 percent to 14.0 percent in 2024. Based on the significant NOL we generated during the year ended December 31, 2023, we anticipate paying minimal cash for income taxes into 2028.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
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 Year Ended December 31,
20232022
Income Before Income Taxes$201.6 $182.4 
Income tax calculated at federal statutory rate42.4 21.0 %38.3 21.0 %
Permanent or flow through adjustments:
State income taxes, net of federal provisions0.6 0.3 0.6 0.3 
Flow-through repairs deductions(25.9)(12.9)(22.7)(12.4)
Production tax credits(10.3)(5.1)(13.2)(7.2)
Unregulated Tax Cuts and Jobs Act excess deferred income taxes(3.4)(1.7)— — 
Release of unrecognized tax benefits
(3.2)(1.6)— — 
Amortization of excess deferred income taxes(2.2)(1.1)(1.7)(0.9)
Plant and depreciation of flow through items6.6 3.3 (0.2)(0.1)
Reduction to previously claimed alternative minimum tax credit
3.2 1.6 — — 
Prior year permanent return to accrual adjustments0.0 0.0 (1.4)(0.8)
Other, net(0.3)(0.1)(0.3)(0.2)
(34.9)(17.3)(38.9)(21.3)
Income Tax Expense (Benefit) $7.5 3.7 %$(0.6)(0.3)%

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.
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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, 2023 Compared with Year Ended December 31, 2022

 RevenuesChangeMWHsAvg. Customer Counts
 20232022$%2023202220232022
 (in thousands)  
Montana$408,341 $357,384 $50,957 14.3 %2,795 2,868 322,489 316,968 
South Dakota67,888 69,809 (1,921)(2.8)603 596 51,261 51,069 
   Residential 476,229 427,193 49,036 11.5 3,398 3,464 373,750 368,037 
Montana431,357 368,634 62,723 17.0 3,238 3,237 74,438 73,093 
South Dakota103,194 108,202 (5,008)(4.6)1,101 1,114 12,973 12,897 
Commercial534,551 476,836 57,715 12.1 4,339 4,351 87,411 85,990 
Industrial45,958 39,773 6,185 15.6 2,660 2,590 79 76 
Other32,756 31,007 1,749 5.6 134 161 6,443 6,406 
Total Retail Electric$1,089,494 $974,809 $114,685 11.8 %10,531 10,566 467,683 460,509 
Regulatory amortization(105,608)46,382 (151,990)(327.7)
Transmission78,436 77,791 645 0.8 
Wholesale and Other6,511 7,583 (1,072)(14.1)
Total Revenues$1,068,833 $1,106,565 $(37,732)(3.4)%
Fuel, purchased supply and direct transmission expense(1)
262,755 324,434 (61,679)(19.0)
Utility Margin(2)
$806,078 $782,131 $23,947 3.1 %
(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
2023 as compared with:
20232022Historic Average2022Historic Average
Montana44160245527% cooler3% cooler
South Dakota1,0359537529% warmer38% warmer

 Heating Degree Days
2023 as compared with:
20232022Historic Average2022Historic Average
Montana(1)
7,2378,0047,59210% warmer5% warmer
South Dakota7,6657,6877,675remained flatremained flat
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
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The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2023 and 2022 (in millions):
 
Utility Margin
2023 vs. 2022
Utility Margin Items Impacting Net Income
Montana rate review - new electric base rates
$29.5 
Lower non-recoverable Montana electric supply costs14.2 
Montana property tax tracker collections9.5 
Higher electric transmission revenue due to market conditions0.6 
QF liability adjustment(0.1)
Lower retail volumes(1.8)
Other(0.3)
Change in Utility Margin Items Impacting Net Income51.6