EDGAR 10-K Filing

Company CIK: 73088
Filing Year: 2022
Filename: 73088_10-K_2022_0000073088-22-000019.json

---

ITEM 1. BUSINESS
ITEM 1. BUSINESS
OVERVIEW
NorthWestern Energy - Delivering a Bright Future
NorthWestern Corporation, 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 are working to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees. We provide electricity and / or natural gas to approximately 753,600 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. We have provided service in South Dakota and Nebraska since 1923 and in Montana since 2002.
We manage our businesses by the nature of services provided, and operate principally in three business segments: electric utility operations; natural gas utility operations; and all other, which primarily consists of unallocated corporate costs. 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.
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. For a full description of our environmental, social, governance and sustainability activities, please see our reports at https://www.northwesternenergy.com.
We strive to balance legal requirements to provide cost-effective, reliable and stably priced energy with being good stewards of natural resources and a diligent focus on sustainability. As discussed below, we currently have a commitment to reduce the carbon intensity of our electric energy portfolio for Montana by 90 percent by 2045. Further, as part of our continued efforts in environmental stewardship, we are developing a comprehensive company-wide carbon reduction plan we intend to announce during 2022.
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 2021, approximately 56 percent of our retail needs originated from carbon-free resources, compared to approximately 40 percent for the total U.S. electric power industry. We do not receive all the related Renewable Energy Credits (RECs) from our contracted electric supply 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.
Output from our carbon-free resources decreased from 65% of total supply needs in 2020 to 56% in 2021 due primarily to lower hydro generation caused by drought conditions in Montana. The reduced hydro output was supplemented by market purchases and increased output from dispatchable generation facilities.
Montana - Commitment to Reduction in Carbon Intensity
Nearly 60% of the electric energy we supply in Montana comes from carbon-free sources, including hydro, wind and solar. In December 2019, we announced a commitment to reduce the carbon intensity of our electric energy portfolio for Montana by 90 percent by 2045 as compared with our 2010 carbon intensity as a baseline. Since 2010, we have already reduced the carbon intensity of our Montana generation portfolio by more than 50 percent.
MONTANA ELECTRIC OPERATIONS
Our regulated electric utility business in Montana includes generation, transmission and distribution. Our service territory covers approximately 107,600 square miles, representing approximately 73 percent of Montana's land area. During 2021, we delivered electricity to approximately 391,400 customers in 208 communities and their surrounding rural areas, 11 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2021, by category, residential, commercial, industrial, and other sales accounted for approximately 44%, 47%, 5%, and 4%, respectively, of our Montana retail electric utility revenue.
Transmission and Distribution
Our electric system is composed of high voltage transmission lines and low voltage distribution lines as follows:
Electric Transmission Lines
Miles of 500 kV
Miles of 230 kV 987
Miles of 161 kV 1,184
Miles of 115 kV and lower voltage 4,151
Total Miles of Electric Transmission Lines 6,819
Electric Distribution Lines
Miles of overhead line
13,061
Miles of underground line
5,116
Total Miles of Electric Distribution Lines 18,177
Total Transmission and Distribution Substations 400
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 was approximately 1,909 MWs on January 27, 2021. Our control area average demand for 2021 was approximately 1,321 MWs per hour, with total energy delivered of more than 11.57 million MWHs.
Our transmission system is directly interconnected with Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; WAPA; and Montana Alberta Tie Ltd. 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 Open Access Transmission Tariff. Our 500 kV transmission system, which is jointly owned, along with our 230 kV and 161 kV facilities, form the key assets of our Montana transmission system. Lower voltage systems provide transmission for local area service needs.
Electric Supply
Our annual retail electric supply load requirements average approximately 750 MWs, with a peak load of approximately 1,200 MWs, and are supplied by owned and contracted resources and market purchases with multiple counterparties.
Owned generation resources supplied approximately 60 percent of our retail load requirements for 2021. We expect that approximately 60 percent of our retail obligations will be met by owned generation resources in 2022. In addition, QFs provide a total of 389 MWs of contracted resources, including 87 MWs from waste petroleum coke and waste coal, 268 MWs from
wind, 16 MWs from hydro, and 17 MWs from solar projects. We have several other long and medium-term power purchase agreements including contracts for 135 MWs of wind generation, 52 MWs of natural gas generation, and 21 MWs of seasonal base-load hydro supply. For 2022, including both owned and contracted resources, we have resources to provide over 90 percent of the capacity necessary to meet our forecasted retail load requirements.
The following chart depicts the makeup of our current owned and long-term contracted resources within our Montana Electric generation portfolio. Hydro generation is by far our largest and most important resource, as it is reliable, dramatically lowers the portfolio's carbon intensity, and reduces economic risks associated with future carbon costs.
Owned Generation Facilities
Details of these generating facilities are described in the following tables.
Hydro Facilities COD River
Source FERC
License
Expiration Owned MW(1)
Black Eagle 1927 Missouri 2040 21
Cochrane 1958 Missouri 2040 62
Hauser 1911 Missouri 2040 19
Holter 1918 Missouri 2040 53
Madison 1906 Madison 2040 8
Morony 1930 Missouri 2040 49
Mystic 1925 West Rosebud Creek 2050 12
Rainbow 1910/2013 Missouri 2040 64
Ryan 1915 Missouri 2040 71
Thompson Falls 1915/1995 Clark Fork 2025 94
Total 453
(1) 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.
Other Facilities Fuel Source Ownership
Interest Owned
MW
Colstrip Unit 4, located near Colstrip in southeastern Montana Sub-bituminous coal 30% 222
DGGS, located near Anaconda, Montana Natural Gas & Liquid Fuel 100% 150
Spion Kop Wind, located in Judith Basin County in Montana Wind 100% 40
Two Dot Wind, located in Wheatland County in Montana Wind 100% 11
Colstrip Unit 4 provides base-load supply and is operated by Talen Montana, LLC (Talen). Talen has a 30 percent ownership interest in Colstrip Unit 3. We have a reciprocal sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15 percent of the respective combined output and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or 4. However, each party is responsible for its own fuel-related costs. Colstrip Unit 4 is supplied with fuel from adjacent coal reserves under a coal supply agreement in effect through 2025. See Item 1A Risk Factors "Regulatory, Legislative and Legal Risks" for further discussion regarding the service life of generation facilities.
Resource Planning
Resource planning is an important function necessary to meet our customers' future energy needs and is used to guide resource acquisition activities. We filed our latest resource plan with the MPSC in August 2019 and supplemented that plan in December 2020. Both filings projected generation capacity deficits and negative reserve margins. Since that time, we have been working to address the deficit with a combination of owned resources and long-term capacity contracts as well as short-and-intermediate term capacity contracts.
We issued an all-source competitive solicitation request in January 2020 for up to 280 MWs of peaking and flexible capacity to be available for commercial operation in early 2023. 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 the irregular nature of intermittent generation such as wind or 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 (Western EIM), operated by the California Independent System Operator (California ISO), on June 16, 2021. We studied the value and costs of the Western EIM for several years prior to the decision to participate in the Western EIM. Utilities in the western United States outside the California ISO have traditionally relied upon a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply. Under this traditional framework, these utilities have limited capability to transact within the hour outside their balancing area. In contrast, energy imbalance markets use automated intra-hour economic dispatch of generation from committed resources to serve loads. The Western EIM is intended to reduce power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power more effectively, and to enhance reliability. We have Western EIM transactions enabled with PacifiCorp and Idaho Power Company. We expect Avista and the Bonneville Power Administration to join the Western EIM by the second quarter of 2022, allowing us to enable EIM transactions with those parties, as well. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States. The Western EIM currently includes over 14 participating authorities.
SOUTH DAKOTA ELECTRIC OPERATIONS
Our South Dakota electric utility business 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 64,200 customers in 110 communities in South Dakota. In 2021, by category, residential, commercial and other sales accounted for approximately 38%, 60%, and 2%, respectively, of our South Dakota retail electric utility revenue.
Transmission and Distribution
Our electric system includes high voltage transmission and low voltage distribution lines as follows:
Electric Transmission Lines
Miles of 345 kV
Miles of 230 kV 18
Miles of 115 kV and lower voltages
1,265
Total Miles of Electric Transmission Lines 1,308
Electric Distribution Lines
Miles of overhead line
1,615
Miles of underground line
Total Miles of Electric Distribution Lines 2,320
Total Transmission and Distribution Substations 120
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 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. 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. The Coyote, Big Stone, and Neal power plants, which we jointly own, are connected directly to the MISO system. Our ownership rights in the transmission lines from these plants to our distribution system allow us to move the power to our customers. Along with operating the transmission system, SPP also coordinates regional transmission planning for all of its members.
Electric Supply
Our annual retail electric supply load requirements average approximately 200 MWs, with a peak load of 344 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.
Our electric supply resources include 210 MWs from jointly owned coal plants and an 80 MW natural gas plant. Additional resources include several natural gas peaking units and an 80 MW wind facility. We also purchase the output of four wind projects, three of which are QFs, under power purchase agreements. Actual output for our wind resources varies based upon weather conditions.
Owned Generation Facilities
Details of our generating facilities are described further in the following chart:
Generation Facilities Fuel Source Ownership
Interest Owned
MW
Big Stone Plant, located near Big Stone City in northeastern South Dakota Sub-bituminous coal 23.4% 111
Aberdeen Generating Units No. 1 and 2, located near Aberdeen, South Dakota Natural gas & Liquid Fuel 100.0% 80
Beethoven Wind Project, located near Tripp, South Dakota Wind 100.0% 80
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa Sub-bituminous coal 8.7% 56
Coyote I Electric Generating Station, located near Beulah, North Dakota Lignite coal 10.0% 43
Miscellaneous combustion turbine units and small diesel units (used only during peak periods) Combination of fuel oil and natural gas 100.0% 25
Total 395
The Big Stone, Coyote and Neal plants are owned jointly with unaffiliated parties. Each of the jointly owned plants is subject to a joint management structure, and we are not the operator of any of these plants. Based on our ownership interest, we are entitled to a proportionate share of the capacity of our jointly owned plants and are responsible for a proportionate share of the operating costs.
The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. Coyote is a mine-mouth generating facility. Neal #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 2018 to provide for the modernization of our generating fleet, which is focused on improving reliability and flexibility. Based on the results of associated competitive solicitation processes, we are currently constructing the 58 MW Bob Glanzer Plant. This plant, which is expected to be in service in the second quarter of 2022, includes flexible reciprocating internal combustion engines at a brownfield site near Huron, South Dakota, with an estimated construction cost of approximately $80 million. We expect to file an updated resource plan in late 2022.
NATURAL GAS OPERATIONS
Montana
Our regulated natural gas utility business in Montana includes production, storage, transmission and distribution. During 2021, we distributed natural gas to approximately 206,600 customers in 118 Montana communities over a system that consists of approximately 4,900 miles of underground distribution pipelines. We also serve several smaller distribution companies that provide service to approximately 37,000 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 44 Bcf during the year ended December 31, 2021.
Miles of Natural Gas Transmission 2,166
Miles of Natural Gas Distribution 4,945
City Gate Stations 138
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 38,000 horsepower on the transmission line and an additional 15,000 horsepower at our storage fields, capable of moving more than 350,000 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, 2021, were approximately 20.8 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2021, were approximately 4.2 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, 2021, these owned reserves totaled approximately 38.8 Bcf and are estimated to provide approximately 3.3 Bcf in 2022, or about 15 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 203,400 dekatherms.
South Dakota and Nebraska
We provide natural gas to approximately 48,600 customers in 62 South Dakota communities and approximately 42,800 customers in three Nebraska communities. In South Dakota, we also transport natural gas for nine gas-marketing firms and three large end-user accounts. In Nebraska, we transport natural gas for four gas-marketing firms and one large end-user account. We delivered approximately 30.0 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.7 Bcf of third-party transportation volume on our Nebraska distribution system during 2021.
Miles of Natural Gas Transmission 55
Miles of Natural Gas Distribution 2,517
Our South Dakota natural gas supply requirements for the year ended December 31, 2021, were approximately 5.6 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, 2021, were approximately 4.2 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, seven of our Montana franchises could expire by action taken by the city or town, which account for approximately 89,534 or 21.7 percent of our Montana natural gas customers. Five of our South Dakota franchises and one franchise in Nebraska, which account for approximately 25,900 or 28 percent of our South Dakota and Nebraska natural gas customers, are scheduled to reach the end of their fixed term during the next five years. We do not anticipate termination of any of these franchises.
GOVERNMENT REGULATION
NorthWestern’s provision of utility service is regulated by the MPSC, the SDPUC, the NPSC, and the FERC. NorthWestern is also regulated by many other state and federal agencies. For example, because NorthWestern’s operations impact land, waterways and the air, NorthWestern is subject to a wide range of regulations administered by the federal Environmental Protection Agency, 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 NorthWestern’s 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 increases are normally granted based on historical data and those increases 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, 2021:
Jurisdiction and Service Implementation Date Authorized Rate Base (millions) Estimated Rate Base (millions) Authorized Overall Rate of Return Authorized Return on Equity Authorized Equity Level
Montana electric delivery and production(1)
April 2019 $2,030.1 $2,596.5 6.92% 9.65% 49.38%
Montana - Colstrip Unit 4 April 2019 304.0 270.1 8.25% 10.00% 50.00%
Montana natural gas delivery and production(2)
September 2017 430.2 536.7 6.96% 9.55% 46.79%
Total Montana $2,764.3 $3,403.3
South Dakota electric(3)
December 2015 $557.3 $635.8 7.24% n/a n/a
South Dakota natural gas(3)
December 2011 65.9 80.8 7.80% n/a n/a
Total South Dakota $623.2 $716.6
Nebraska natural gas(3)
December 2007 $24.3 $39.5 8.49% 10.40% n/a
$3,411.8 $4,159.4
_____________________
(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.
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 Power Cost and Credit Adjustment Mechanism (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. 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. Annually, supply rates are adjusted to include any differences between the previous tracking year's revenues and expenses for recovery during the subsequent tracking year. We submit annual natural gas tracker filings for the actual 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our natural gas energy 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.
Fixed Cost Recovery Mechanism Pilot - In our 2018 Montana electric rate settlement, the MPSC approved a Fixed Cost Recovery Mechanism Pilot (FCRM), intended to decouple our recovery of fixed, test-year based transmission, distribution, and production costs from sales of energy. At our request, the MPSC delayed implementation of the pilot to July 1, 2022. The FCRM is expected to function over a four-year pilot period, applying primarily to residential customers.
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.
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. The adjustment goes into effect upon filing, and is deemed approved within 10 days after the information filing unless the SDPUC staff requests changes during that period. 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.
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 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 promulgated in Order No. 888, as owners of transmission facilities, we are required to provide open access to our transmission
facilities under filed tariffs at cost-based rates. In addition, we are required to comply with FERC's Standards of Conduct for Transmission Providers.
Our Montana wholesale transmission customers, such as cooperatives, industrial customers, and other customers that have third-party commodity supply providers, are served 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. Our South Dakota transmission operations are in the SPP, and transmission service is provided under the SPP OATT.
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.
In addition, 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 the 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 greenhouse gas (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. Months later, President Biden officially rejoined the Paris Accord. More recently, President Biden's proposed Build Back Better legislation contains significant climate initiatives.
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 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 2022 and 2023 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 in November 1923. 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 Corporation, 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 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, 2021, we had 1,483 employees. Of these, 1,187 employees were in Montana and 296 were in South Dakota or Nebraska. Of our Montana employees, 440, or 37 percent, were covered by seven collective bargaining agreements involving five unions. Due to the continuing impact of the COVID-19 pandemic, we negotiated a one-year contract extension with a wage proposal for six Montana contracts that were expiring in 2021. All seven of the Montana contracts expire in 2022 and we expect them to be renegotiated. Of our South Dakota and Nebraska employees, 165, or 56 percent, are covered by a collective bargaining agreement renegotiated in 2021 that expires 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.
Compensation
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 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 2021 and 2020, the compensation for our CEO was approximately 28 and 25 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 2021, approximately 79 percent of the targeted compensation of our CEO and about 63 percent of the targeted compensation of our other named executive officers is at risk in the form of performance-based incentive awards. Our Board of Directors establishes the metrics and targets for these incentive awards, based upon advice from the Board of Directors’ independent compensation consultant.
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.
Diversity
We believe a diverse and inclusive workforce adds value to our company 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.
Of our total workforce, 28 percent of our employees are female, and 26 percent of our employees in management positions are female, including four of our nine executive officers. Additionally, 2020 Women on Boards has previously recognized our gender diversity, with three females among our eight directors who sit on our board. We have implemented methods to provide pay equity between our female and male employees performing equal or substantially similar work. We have engaged with a third party to review our pay equity between our male and female employees, share the results with our Board of Directors, and take corrective action as necessary. Our most recent study was performed in 2019, with no corrective action required.
Health and Safety
As stewards of critical infrastructure, providers of energy service, and members of the communities we serve, our 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 to review and evaluate our operations, to measure progress, and to enhance compliance with our 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, 2021 and December 31, 2020 our recordable incident rates were 1.64 and 1.36 and lost time incident rates were 0.46 and 0.39 on a company wide basis. Our five-year average safety record for the year ended December 31, 2021 was better than our industry peer group's five-year average.
COVID-19
In response to the COVID-19 pandemic, we implemented a variety of protocols to help slow the spread of the virus, protect both our employees and the communities we serve, and enable us to continue to provide our customers with safe and reliable energy service. This effort, which has continued throughout the pandemic, provides safety and health measures to keep our employees on the job and able to perform their duties.
Specifically, we adopted benefit programs to provide additional paid time off due to pandemic related absences to encourage employees to remain home from work if sick. During the pandemic, we have not had to lay off or furlough any
employees. Personal protective equipment was procured and remains available, and enhanced facility cleaning and sanitation protocols have been implemented. We made arrangements for employees that are able to do so to work remotely, and we continue to support this practice as the pandemic progresses. We continue to encourage mask wearing and physical distancing as some employees have strategically returned to main work locations. We continue to contact trace employee illnesses to minimize exposure to co-workers, and employees consistently receive a “Covid Briefing” and other communication tools to keep them informed.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Executive Officer Current Title and Prior Employment Age(1)
Robert C. Rowe Chief Executive Officer and Director since February 2021; formerly President, Chief Executive Officer and Director since August 2008. Mr. Rowe also serves on the board of directors of a NorthWestern subsidiary. 66
Brian B. Bird President and Chief Operating Officer since February 2021; formerly Chief Financial Officer since December 2003. Mr. Bird serves on the board of directors of a NorthWestern subsidiary. 59
Crystal D. Lail Vice President and Chief Financial Officer since February 2021; formerly Vice President and Chief Accounting Officer since April 2020; and formerly Vice President and Controller since October 2015. 43
Michael R. Cashell Vice President - Transmission since May 2011. Mr. Cashell serves on the board of directors of a NorthWestern subsidiary. 59
Heather H. Grahame Vice President - General Counsel and Regulatory and Federal Government Affairs since January 2018; formerly Vice President and General Counsel since August 2010. 66
John D. Hines Vice President - Supply and Montana Government Affairs since January 2018; formerly Vice President - Supply since May 2011. 63
Curtis T. Pohl Vice President - Distribution since May 2011. Mr. Pohl serves on the board of directors of a NorthWestern subsidiary. 57
Bobbi L. Schroeppel Vice President - Customer Care, Communications and Human Resources since May 2009. 53
Jeanne M. Vold Vice President - Technology since February 2021; formerly Business Technology Officer since 2012. 55
(1) As of February 4, 2022.
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.

---

ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Regulatory, Legislative and Legal Risks
Our profitability is dependent 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 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 provide service at rates established by several regulatory commissions. 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 rates. Rate reviews can be highly contested proceedings. There is no guarantee that the costs we seek to recover in future rates will be allowed. There is also typically a significant lag between the time we incur a cost and recover that cost in rates.
In addition to rate cases, our cost tracking mechanisms are a significant component of how we recover our costs. Trackers can also be highly contested dockets and, as with a rate case, there is no guarantee that the applicable regulatory commission will approve our request to recover costs. We have recently received, and may in the future receive, unfavorable rulings from the MPSC. For example, on December 2, 2021, the MPSC issued a final order rejecting our request to reset the PCCAM Base revenue amount outside of a formal rate case, which means that we will likely continue to under-collect our power costs until we are allowed to update the PCCAM Base in a rate case. There can be no assurance that the MPSC will allow recovery of costs in the future, which could have a material adverse effect on our financial results.
Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. 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. For instance, our Montana electric utility is regulated by the MPSC and the FERC. Differing schedules and regulatory practices between the MPSC and FERC expose us to the risk that we may not 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.
Before we added Colstrip Unit 4, DGGS, hydroelectric and Spion Kop electric generation resources to our electric generation supply portfolio, we received a determination from the MPSC that these acquisitions were in the public interest and approval for cost recovery, subject to a prudence review. This advance approval process is established in Montana's "preapproval" statute. On May 28, 2021, a non-profit environmental advocacy organization, together with three individuals, filed suit in Montana District Court (Missoula) seeking a declaratory judgement that the Montana preapproval statute is unconstitutional. The case is fully briefed and we expect a decision from the court by the end of the first quarter of 2022. If the preapproval statute is found unconstitutional, there will be no explicit statutory mechanism that facilitates advanced approval of generating resource selection. Preapproval can affect credit ratings by reducing risk. The less risk that NorthWestern is perceived to face, the stronger its credit rating. An MPSC decision granting preapproval reduces risk and often ultimately results in lower debt costs and lower rates paid by customers. A decision by the MPSC also enables NorthWestern to take a more orderly approach to financing, which can also result in lower debt costs that benefit customers. The MPSC provides comments on our resource plan that we file every two to three years, but it does not provide a review and approval of this planning.
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. There can be no assurance that laws, regulations and policies will not be changed in ways that result in significant impacts to our business. 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. Any changes may have a material adverse effect on our financial condition, results of operations, and cash flows.
We are subject to extensive and changing energy, and environmental laws and regulations, including legislative 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, 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.
However, laws and regulations to which we must adhere change, and the Biden Administration’s agenda represents a significant shift in environmental and energy policy, focusing on reducing GHG emissions and addressing climate change issues. This new direction is reflected in several Executive Orders that President Biden issued in January 2021 and subsequent executive actions that have been undertaken, such as methane emission regulations recently proposed by the EPA or federally driven initiatives to promote electrification over the use of natural gas for domestic purposes.. Together, these orders and regulatory proposals reflect climate change issues and GHG reductions 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. Representative examples include legislation introduced in March 2021 in the U.S. House of Representatives, called the CLEAN Future Act, tax reforms, methane fees, the Clean Electricity Performance Program, and Build Back Better Act. We expect other legislation to be introduced and considered by the U.S. House and the U.S. Senate focusing on GHG emission reduction, environmental and energy policy.
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 affect our costs and 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, it is widely expected that the Biden Administration and/or the U.S. Congress will develop alternative plans for reducing GHG emissions from coal-fired plants and methane emissions from natural gas operations as demonstrated by the recently proposed methane emission regulations from the EPA. As GHG and/or methane regulations are implemented, it could result in additional compliance costs that could affect our future results of operations and financial position if such costs are not recovered through regulated rates. Complying with the 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.
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.
Early closure of our generation facilities due to economic conditions, environmental regulations and / or litigation could result in regulatory impairments, increased cost of operations and inability to serve our customers in periods of peak demand. If recovery of our remaining investment in such facilities and the costs associated with early closure, including decommissioning, remediation, reclamation, and restoration are not recovered from customers, it could have a material adverse impact on our results of operations.
Colstrip - As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down those units no later than July 2022. In January 2020, the owners of Units 1 and 2 closed those two units. We do not have ownership in Units 1 and 2, and decisions regarding those units, including their shut down, were made by their respective owners. The six owners of Units 3 and 4 currently share the operating costs pursuant to the terms of the Ownership and Operation Agreement (O&O Agreement). Costs of common facilities were historically shared among the owners of all four units. With the closure of Units 1 and 2, we are incurring additional operating costs with respect to our interest in Unit 4 and may experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines. We would expect to incorporate any reduction in revenue in our next general electric rate filing, resulting in lower revenue credits to certain customers.
The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the closure of the facility is subject to MPSC approval. Three of the joint owners of Units 3 and 4 are subject to regulation in Washington and in May 2019, the Washington state legislature enacted a statute mandating Washington electric utilities to “eliminate coal-fired resources from [their] allocation of electricity” on or before December 31, 2025, after which date they may no longer include their share of coal-fired resources in their regulated electric supply portfolio. As a result of the Washington legislation, four of the six joint owners of Units 3 and 4 requested the operator prepare a 2021 budget reflecting closure of Units 3 and 4 by 2025, and alternately a closure of Unit 3 by 2025 and a closure of Unit 4 by 2027. Differing viewpoints on closure dates delayed approval of the 2021 budget, until it was approved on March 22, 2021. Budgeting for 2022 was also initially delayed, with the same four joint owners demanding substantial budget reductions. Ultimately agreement was reached and a budget approved on January 21, 2022. Such budgeting pressures may result in future budgets that may not be sufficient to maintain the reliability of Units 3 and 4.
While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the O&O Agreement. On March 12, 2021, we initiated the Arbitration under the O&O Agreement (the Arbitration), which seeks to resolve the primary issue of whether closure of Units 3 and 4 can be accomplished without each joint owner's consent and to clarify the obligations of the joint owners to continue to fund operations until all joint owners agree on closure.
The Arbitration has given rise to three lawsuits, concerning the number of arbitrators, the venue and the applicable arbitration laws. The four joint owners from the Pacific Northwest assert the Arbitration must be conducted under the O&O Agreement, with one arbitrator, in Spokane County, Washington, and pursuant to the Washington Arbitration Act. The fifth joint owner asserts the Arbitration must be conducted per the terms of Montana Senate Bill 265, which requires the Arbitration must be conducted, with three arbitrators, in Montana and pursuant to the Montana Uniform Arbitration Act. The three initiated lawsuits do not make direct financial demands, and instead, are intended to address issues related to process for the Arbitration.
Since the Arbitration was initiated, and despite the litigation, we have worked and continue to work with the other joint owners to arrive at an agreed upon process for the Arbitration.
In addition, we have joint ownership in and operate the associated 500 kV transmission system. The closure of generation at Colstrip may impact the operation of this 500 kV system, and the joint owners may have differing needs with regard to ongoing operation of this system. The 500 kV transmission system is an integral, essential part of our overall transmission system in Montana in order to maintain reliability, regardless of the status of the generation facilities.
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 North American Electric Reliability Corporation (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 as high as approximately $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. These resources are primarily intermittent, non-dispatchable 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 several impacts, including increasing the likelihood and frequency that we will be required to reduce output from owned generation resources and that we will need to upgrade or build additional transmission facilities to serve QF projects. Either of these results would increase costs to customers. Further, balancing load and power generation on our system is challenging, and we expect that operational costs will increase as a result of integration of these intermittent, non-dispatchable generation projects. If we are unable to timely recover those costs, those increased costs may negatively affect our liquidity, results of operations and financial condition.
In addition, requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs that are inconsistent with resource plans developed based on a lowest cost and least risk basis while placing upward pressure on overall customer bills. This may impact our investment plans and financial condition. Finally, the requirement to procure power from these QF sources may impact our transmission system and require additional transmission facilities to be developed in order to integrate these resources, which also can impact overall customer bills.
Operational Risks
The COVID-19 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.
The financial impact of the COVID-19 pandemic eased during 2021, but our financial results in 2020 were impacted by lower sales volumes, an increase in reserves for uncollectible accounts and an increase in interest expense, partly offset by lowering operating, general and administrative expense. The long-term impact of the COVID-19 pandemic is highly uncertain and subject to change, and also depends on factors beyond our knowledge or control, including the ultimate duration and severity of this outbreak, third-party actions taken to contain its spread and mitigate its public health effects, and possible federal or state legislative actions related to utility operations, including disconnect moratoriums, or additional economic stimulus packages.
While the COVID-19 pandemic has not caused material disruptions to our operations it, or a similar widespread public health concern, could in the future as a result of, 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.
For similar reasons, the COVID-19 pandemic has caused adverse impacts on our suppliers, their manufacturers and the overall global supply chain. Accordingly, we have experienced areas of increased costs and delays in obtaining certain supplies and services timely. During the third quarter of 2021, we decided to discontinue our plans to build a 30-40 MW electric generation plant near Aberdeen, South Dakota as a result of significant increases in estimated construction cost as a result of global supply chain challenges.
National, state and local governments have responded to the COVID-19 pandemic in a variety of ways, including, without limitation, by declaring states of emergency, restricting people from gathering in groups or interacting within a certain physical distance (i.e., social distancing), and in certain cases, ordering businesses to close or limit operations or people to stay at home. While there has been a general easing of restrictions through 2021, there can be no guarantee that this trend will continue. Although we provide critical infrastructure services and are permitted to continue to operate in each of our jurisdictions, there may be restrictions imposed on how we operate, such as disconnect moratoriums.
In addition, the Biden Administration is seeking to require broad categories of employees to be fully vaccinated against COVID-19 through an OSHA Emergency Temporary Standard (ETS), and through Executive Order 14042. The OSHA ETS provides, generally, that all employers with 100 or more employees require that all workers be vaccinated or undergo weekly COVID-19 testing. On January 13, 2022, the U.S. Supreme Court issued an order halting the ETS’s implementation and enforcement while the U.S. Court of Appeals for the Sixth Circuit reviews the ETS on its merits. On January 25, 2022, OSHA withdrew the ETS. Executive Order 14042 provides, generally, that federal agencies ensure that covered contracts and contract-like instruments include a clause that the federal contractor and any subcontractor be fully vaccinated against COVID-19 and comply with other COVID-related requirements. The Executive Order did not apply to all government contracts and we determined that the Executive Order did not apply to ours. On December 7, 2021, the U.S. District Court for the Southern District of Georgia issued an injunction, halting the enforcement of this Executive Order nationwide and that determination has been appealed to the U.S. Court of Appeals for the 11th Circuit. On January 21, 2022, the U.S. District Court clarified its December 7, 2021 Order, stating that the injunction applies only to the vaccine mandate and not to other COVID-related requirements such as masking and social distancing. As the OSHA ETS has been withdrawn and Executive Order 14042 does not apply to our existing contracts, we are not required to implement either at this time. However, our obligation to comply with Executive Order 14042 could change in the future depending on the execution of new federal contracts and the ultimate resolution of court challenges to that Order.
Any such workforce implications, significant supply chain disruptions, 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.
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, 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, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others.
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 distribution and transmission lines and facilities are exposed to many threats that may impact our infrastructure, as discussed above. These include severe weather, along with accidental and intentional acts that may cause our lines to fail.
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 either from trees or 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. In November 2021, during high wind conditions, one of our electric lines sparked a grassland fire west of Denton, Montana. The fire burned across approximately 18 miles of grassland to the town of Denton where the fire ignited a grain elevator and burned over 25 homes and structures. There was no loss of life or reported injuries. We have fire insurance and, at this time, expect any claims arising from the Denton fire over our insurance retention to be covered by insurance.
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.
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. Should these economic conditions and issues continue, we could have difficulty completing the operations 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. During the third quarter of 2021, we discontinued our plans to build a 30-40 MW electric generation plant near Aberdeen, South Dakota as a result of significant increases in estimated construction cost as a result of global supply chain challenges, and recorded a $1.6 million pre-tax charge for the write-off of preliminary construction costs.
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. 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 adapt and the risk of cyber-based attacks is heightened with many of our employees working and accessing our technology infrastructure remotely as a result of the COVID-19 pandemic. 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.
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, 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.
There is also a concern that the physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate.
Extreme weather conditions, especially those of prolonged duration, create high energy demand on our own and/or other systems and increase the risk we may be unable to reliably serve customers, causing brownouts and/or blackouts of our electric systems, and loss of gas supply. Risk of losing electricity or gas supply during extreme weather carries significant consequences as without our services our customers may be subjected to dire circumstances. Additionally, extreme weather conditions may raise market prices as we buy short-term energy to serve our own system. To the extent the frequency of extreme weather events increase, 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 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 70 percent of our recent peak electric requirements, with remaining needs, including additional reserve margin, served through market purchases. Montana has been a net exporter of electric generation and we have relied upon Montana's excess generation for grid reliability and to physically serve customers. A significant number of base-load generation facilities, which may also serve to meet peak requirements, in the state and region have been retired or are scheduled to be retired in the next five to ten years. This includes Colstrip Units 1 and 2, representing 614 MWs of generation on a capacity basis, which ceased operations in January 2020. A decrease in the state and region’s electric capacity 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 2021, market prices for electricity and natural gas in peak periods were increasingly volatile, resulting in 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.
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. Our most recent resource plans include an expected annual load growth assumption of 0.4 percent in Montana and 0.7 percent in South Dakota, which reflects low customer and usage increases, offset in part by these load reduction measures. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, market participants, transmission availability, the availability of generation, and the ongoing development of the Western Energy Imbalance Market, 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.
Liquidity and Financial Risks
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 management’s 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.
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. Moody’s Investors Service placed us on negative outlook in our 2021 review process. 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.
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.
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. In addition, we are subject to price escalation risk with one of the largest QF contracts.
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.
In addition, we are subject to price escalation risk with one of the largest contracts included in the electric QF liability due to variable contract terms. In recording the electric QF liability, we estimated an annual escalation rate of three percent over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds three percent, our results of operations, cash flows and financial position could be adversely affected.

---

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

---

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

---

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

---

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

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, which is traded under the ticker symbol NWE, is listed on the Nasdaq Stock Market. As of February 4, 2022, there were approximately 1,166 common stockholders of record.

---

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

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2021 compared to the year ended December 31, 2020, 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, 2020 compared with the year ended December 31, 2019, 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, 2020.
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.
Management believes that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow 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 Corporation, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 753,600 customers in Montana, South Dakota Nebraska, and Yellowstone National Park. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2021, 2020 and 2019. Following is a discussion of our strategy and significant trends.
We are working to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees. We seek to deliver value to our customers by providing high reliability and customer service, and an environmentally sustainable generation mix at an affordable price. The energy landscape is changing and we are committed to meeting the changing demands of our customers through continued investment to enhance reliability, security and safety, grid modernization, and integrate even more renewables, while meeting our growing demand for capacity. 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.
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 2021, approximately 56 percent of our retail needs originated from carbon-free resources, compared to approximately 40 percent for the total U.S. electric power industry. In December 2019, we announced a commitment to reduce the carbon intensity of our electric energy portfolio for Montana by 90 percent by 2045 as compared with our 2010 carbon intensity as a baseline. Since 2010, we have already reduced the carbon intensity of our energy generation in Montana by more than 50 percent. Further, as part of our continued efforts in environmental stewardship, we are developing a comprehensive company-wide carbon reduction plan we intend to announce during 2022. 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 today, we recently entered into two 80-megawatt solar power purchase agreements with two projects that are expected to begin delivering energy to our Montana customers in 2022. We expect solar to further evolve along with advances in energy storage. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system.
HOW WE PERFORMED IN 2021 COMPARED TO OUR 2020 RESULTS
Consolidated net income in 2021 was $186.8 million as compared with $155.2 million in 2020. This increase was primarily due to higher Montana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period which was impacted by COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, and a favorable electric QF liability adjustment as compared with the prior period, partly offset by higher operating costs, non-recoverable Montana electric supply costs, and income tax expense.
Year Ended December 31, 2021 vs. 2020
Income Before Income Taxes Income Tax Benefit (Expense) Net Income
(in millions)
Year ended December 31, 2020 $ 144.2 $ 11.0 $ 155.2
Items increasing (decreasing) net income:
Higher Montana electric transmission revenue 25.1 (6.4) 18.7
Higher electric retail volumes 17.1 (4.3) 12.8
Prior period disallowance of supply costs 9.4 (2.4) 7.0
Electric QF liability adjustment 4.4 (1.1) 3.3
Higher Montana natural gas volumes 1.3 (0.3) 1.0
Higher income tax expense - (2.1) (2.1)
Higher operating costs impacting net income (15.0) 3.8 (11.2)
Higher depreciation and depletion (7.8) 2.0 (5.8)
Higher non-recoverable Montana electric supply costs (5.3) 1.3 (4.0)
Other 16.8 (4.9) 11.9
Year ended December 31, 2021 $ 190.2 $ (3.4) $ 186.8
Change in Net Income $ 31.6
SIGNIFICANT TRENDS AND REGULATION
Electric Resource Planning - Montana
A shortage of critical 24/7 power capacity resources is jeopardizing reliability in the Western United States. The accredited capacity of our Montana portfolio of owned and long-term contracted electric generation resources covered approximately 70 percent of our 2021 peak electric requirements, with the remaining capacity shortfall, including reserve margin, covered through market purchases. A significant number of base-load generation facilities in the state and region have been retired or are scheduled to be retired in the next several years, which may impair grid and customer service reliability and increase volatility in market prices. Accordingly, our continued exposure to market purchases is an increasing risk to the availability and affordability of service for our Montana customers.
Future Integrated Resource Planning - We expect to submit an updated integrated resource plan by the end of 2022 or early 2023, followed by an all-source competitive solicitation request for capacity available in 2026. Due to the significant impact of our ownership in Colstrip Unit 4 to the capacity available in our portfolio, the outcome in the arbitration amongst the co-owners (See Note 18 - Commitments and Contingencies) may affect the timing of the submission of this plan.
We remain concerned regarding an overall lack of capacity in the region and our resource adequacy deficit in the near term based on our projections of load by 2025, as a risk to customer reliability and affordability. As such, in addition to the 300 MWs (325 MWs nameplate) of accredited capacity additions resulting from the prior integrated resource plan as discussed below, we have reduced our exposure to our projected 725 MW shortfall of accredited capacity by 2025 through a combination of executing short and medium term cost-competitive agreements for 225 MWs of existing capacity in the region. We also expect to have an incremental 200 MWs of capacity resource additions in this period through a combination of new and renewed QF contracts and increases to the forecasted capacity accreditation of existing intermittent resources. This reduction of risk in the near term allows for clarity on the Colstrip arbitration, further development in the western markets, and ongoing technological changes.
January 2020 Request for Proposal (RFP) - To help meet our critical power capacity and peak demands, as a result of our all-source competitive solicitation request for long-term capacity resources we entered into contracts for 325 MWs of dispatchable capacity resources. These contracts include:
•A 5-year power purchase agreement for 100 MWs of firm capacity and energy products originating predominately from the British Columbia Hydro system starting in January 2023 (Powerex Transaction);
•A 20-year agreement to purchase capacity and ancillary services produced from the 50 MW Beartooth Battery project near Billings, Montana, expected to be online by late 2023 or early 2024; and
•Contracts for the construction of a nameplate capacity 175 MW natural gas-fired generation plant in Montana, at a cost of approximately $275 million, including AFUDC, which we will own.
We initially filed an application with the MPSC for advanced approval to construct the 175 MW generation plant in Montana. We subsequently made the difficult decision to withdraw our application in order to meet the targeted commercial operation date of the plant. The upheaval in the construction market and, specifically, timely availability of critical components and escalating labor and construction costs due to the COVID-19 pandemic, necessitates the flexibility to expend capital and make commercial decisions in advance of the timeline established by the MPSC approval docket. The schedule is expected to allow the plant to serve our Montana customers during the 2023-2024 winter season.
On October 21, 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State Court, against the Montana Department of Environmental Quality (MTDEQ) and us, alleging the environmental review of our Yellowstone County plant site project was unlawful. This lawsuit could delay the project if the Montana State Court were to require a full Environmental Impact Study regarding the project, set aside the air quality permit granted for the Yellowstone County project, or determine that the underlying environmental statute violates the Montana Constitutional guarantee of a “clean and healthful environment.”
On December 21, 2021, we filed an application with the MPSC for preapproval of the Beartooth Battery agreement as a new capacity resource. This agreement is contingent upon MPSC approval of our application. The MPSC has not yet established a procedural schedule in this docket but we anticipate an MPSC decision in the fourth quarter of 2022. Our application is subject to the risk of the District Court agreeing with the plaintiffs in the litigation challenging the constitutionality of the preapproval statute.
Electric Resource Supply - South Dakota
Construction on our new Bob Glanzer Generating Station is nearing completion. The 58 MW natural gas plant in Huron, South Dakota is expected to be online early in the second quarter of 2022 with total construction costs of approximately $80 million ($77.8 million incurred through December 31, 2021).
During the third quarter of 2021, we discontinued our plans to build a 30-40 MW natural gas plant near Aberdeen, South Dakota. Originally expected to be a $60 million project to be in service early in 2024, we were experiencing significant increases in estimated construction cost as a result of global supply chain challenges. As a result of the project discontinuance, we recorded a $1.6 million pre-tax charge for the write-off of preliminary construction costs. Our energy resource plans continue to identify portfolio requirements including potential investments resulting from a completed competitive solicitation process in South Dakota. We expect to file an updated integrated resource plan in late 2022.
Impact of Fuel and Purchase Power Costs
Montana PCCAM - In April 2021, we submitted a filing with the MPSC requesting approval to increase the PCCAM Base forecasted costs used to develop rates for the recovery of electric power costs by approximately $17 million, or potentially a greater increase to reflect current market prices and new capacity contracts. On June 29, 2021, the MPSC approved our request for interim rates reflecting the $17 million increase, subject to refund. The Montana Consumer Counsel (MCC) filed a motion arguing that the PCCAM Base cannot be updated except in a general rate case and asked the MPSC to dismiss the application. On October 5, 2021, the MPSC voted to grant the MCC’s motion to dismiss and on December 2, 2021, the MPSC issued a final order dismissing our application.
In 2021, PCCAM costs exceeded base revenues by approximately $54.1 million, which are allocated 90% to Montana customers and 10% to shareholders. As a result, we deferred $48.7 million of costs during 2021 to be collected from customers (90% of the costs above base) and recorded a reduction in pre-tax earnings of $5.4 million (10% of the variance). These increased costs are not reflected in customer bills and recovered until the subsequent power cost adjustment year, adversely affecting our cash flows and liquidity. We expect to address an adjustment to the PCCAM base in our upcoming Montana electric general rate filing.
Regulatory Update
General Rate Filing - Rate cases 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. We anticipate making a Montana electric general rate filing (2021 test year) in mid-2022.
FERC Financial Audit - We are subject to FERC’s jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things. The Division of Audits and Accounting in the Office of Enforcement of FERC has initiated a routine audit of NorthWestern Corporation for the period of January 1, 2018 to the present to evaluate our compliance with FERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received from FERC, but is expected during the first quarter of 2022. Management is unable to predict the outcome or timing of the final resolution of the audit.
Supply Chain Challenges
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. Should these conditions continue, we could have difficulty completing the operations 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.
See "Electric Resource Supply - South Dakota" section above for discussion of supply chain challenges that have already impacted our business activities. Also, as we developed our forecast of capital expenditures, we estimate that these supply chain challenges have, thus far, increased our 2022 capital spend by approximately 2 percent, and it may go higher.
Financing Activities
We anticipate financing our ongoing maintenance and capital programs with a combination of cash flows from operations,
first mortgage bonds and equity issuances. See "Liquidity and Capital Resources" for additional information regarding our debt and equity financing activities. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
Fire Mitigation
With changing weather conditions which include more significant wind events, drought conditions, and warmer air temperatures, we do not consider the fire season specific to a time of year, but rather a condition that may exist at any time of year. Each year’s weather conditions impact these situations differently: early season rains encourage plant growth which fuels fires later in the growing season, and winters with little snow leave dry plant material available for late season fires. The threat is not only in forested areas, where insect infestations and resulting tree death has been severe, but across the entire system including rural areas where grassland fires could be ignited, along with urban areas where extreme weather conditions pose a great risk to heavily populated areas.
Recognizing the risk of significant wildfires in Montana, we are proactively seeking to mitigate wildfire risk through development of a comprehensive Fire Mitigation Plan addressing four key areas: situational awareness, operational practices, system assessment repair and hardening programs, and public safety and communications. This plan builds upon several key initiatives that were initiated and executed over the past several years including our transmission and distribution system infrastructure programs and our hazard tree removal program. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. We expect to include a request for costs associated with the plan in our 2022 Montana electric rate filing.
SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES
Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions):
Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments. As a result of a competitive solicitation process in Montana, we have included approximately $275 million of capital in our projections above to construct a 175 MW natural gas plant to be on line during the 2023 or 2024 winter season.
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. Beginning in 2021, and continuing through 2025, we expect to install automated metering infrastructure in Montana at a total cost of approximately $125 million, of which, $100 million remains and is reflected in the five year capital forecast above.
RESULTS OF OPERATIONS
Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.
Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather. 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. Among the most significant of these costs are those associated with fuel, purchased power, natural gas supply, and transmission expense. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.
Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.
OVERALL CONSOLIDATED RESULTS
Year Ended December 31, 2021 Compared with Year Ended December 31, 2020
Consolidated net income in 2021 was $186.8 million as compared with $155.2 million in 2020, an increase of $31.6 million. As described in more detail below, this increase was primarily due to higher Montana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period due to the COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, and a favorable electric QF liability adjustment as compared with the prior period, partly offset by higher operating costs, non-recoverable Montana electric supply costs, and income tax expense.
Consolidated gross margin in 2021 was $377.7 million as compared with $330.3 million in 2020, an increase of $47.4 million, or 14.4 percent. This increase was primarily due to higher Montana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period due to the COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, a favorable electric QF liability adjustment as compared with the prior period, and lower property and other taxes, partly offset by higher operating and maintenance expense, depreciation and depletion, and Montana non-recoverable electric supply costs.
Electric Natural Gas Total
2021 2020 2021 2020 2021 2020
(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues $ 1,052.2 $ 940.8 $ 320.1 $ 257.9 $ 1,372.3 $ 1,198.7
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 294.8 236.6 130.7 69.6 425.5 306.2
Less: Operating and maintenance 156.4 149.2 51.9 53.8 208.3 203.0
Less: Property and other taxes 134.9 140.6 38.5 38.9 173.4 179.5
Less: Depreciation and depletion 154.6 148.0 32.8 31.7 187.4 179.7
Gross Margin 311.5 266.4 66.2 63.9 377.7 330.3
Operating and maintenance 156.4 149.2 51.9 53.8 208.3 203.0
Property and other taxes 134.9 140.6 38.5 38.9 173.4 179.5
Depreciation and depletion 154.6 148.0 32.8 31.7 187.4 179.7
Utility Margin(1)
$ 757.4 $ 704.2 $ 189.4 $ 188.3 $ 946.8 $ 892.5
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Year Ended December 31,
2021 2020 Change % Change
(in millions)
Utility Margin
Electric $ 757.4 $ 704.2 $ 53.2 7.6 %
Natural Gas 189.4 188.3 1.1 0.6
Total Utility Margin(1)
$ 946.8 $ 892.5 $ 54.3 6.1 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated utility margin in 2021 was $946.8 million as compared with $892.5 million in 2020, an increase of $54.3 million, or 6.1 percent.
Primary components of the change in utility margin include the following (in millions):
Utility Margin
2021 vs. 2020
Utility Margin Items Impacting Net Income
Higher transmission rates and demand due to market conditions and pricing and the recognition of approximately $4.7 million of deferred interim revenues $ 25.1
Higher electric retail volumes 17.1
Prior period MPSC disallowance of supply costs 9.4
Electric QF liability adjustment 4.4
Higher natural gas retail volumes 1.3
Higher non-recoverable Montana electric supply costs compared to the prior period (5.3)
Reduction of rates from the step down of our Montana gas production assets (1.2)
Other 5.1
Change in Utility Margin Impacting Net Income 55.9
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (4.8)
Higher revenue from lower production tax credits, offset in income tax expense 2.5
Gas production taxes recovered in revenue, offset in property and other taxes 0.5
Operating expenses recovered in revenue, offset in operating and maintenance expense 0.2
Change in Items Offset Within Net Income (1.6)
Increase in Consolidated Utility Margin(1)
$ 54.3
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Higher electric retail volumes were driven by warmer summer weather in both Montana and South Dakota, customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer overall winter weather in Montana and South Dakota. The higher natural gas retail volumes were due to improved Montana commercial volumes as compared to the prior year due to the COVID-19 pandemic related shutdowns and customer growth, partly offset by overall warmer weather in all jurisdictions. In addition, the favorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $7.5 million gain in 2021, as compared with a $3.1 million gain for the same period in 2020, due to the combination of:
•A $2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $0.9 million favorable reduction in costs in the prior period;
•A negative adjustment, increasing the QF liability by $2.1 million, reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of $2.2 million in the prior year due to lower actual price escalation; and
•A favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term.
Year Ended December 31,
2021 2020 Change % Change
(in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance $ 208.3 $ 203.0 $ 5.3 2.6 %
Administrative and general 101.9 94.1 7.8 8.3
Property and other taxes 173.4 179.5 (6.1) (3.4)
Depreciation and depletion 187.5 179.6 7.9 4.4
$ 671.1 $ 656.2 $ 14.9 2.3 %
Consolidated operating and maintenance expenses were $208.3 million in 2021, as compared with $203.0 million in 2020. Primary components of the change include the following (in millions):
Operating & Maintenance Expenses
2021 vs. 2020
Operating & Maintenance Expenses Impacting Net Income
Higher maintenance at our electric generation facilities $ 4.6
Higher labor and benefits expenses due to increased compensation and medical costs 4.7
Write off of preliminary construction costs 1.6
Other 0.5
Change in Items Impacting Net Income 11.4
Operating & Maintenance Expenses Offset Within Net Income
Pension and other postretirement benefits, offset in other income (6.3)
Operating expenses recovered in trackers, offset in revenue 0.2
Change in Items Offset Within Net Income (6.1)
Increase in Operating and Maintenance Expenses $ 5.3
The write off of preliminary construction costs is associated with the 30-40MW flexible natural gas plant near Aberdeen, South Dakota.
Consolidated administrative and general expense was $101.9 million in 2021, as compared with $94.1 million in 2020. Primary components of the change include the following (in millions):
Administrative & General Expenses
2021 vs. 2020
Administrative & General Expenses Impacting Net Income
Higher technology implementation and maintenance expenses $ 2.4
Higher litigation expenses 2.0
Higher insurance expenses 1.5
Higher labor and benefits expenses due to increased compensation and medical costs 1.0
Decrease in uncollectible accounts expense (4.5)
Other 1.2
Change in Items Impacting Net Income 3.6
Administrative & General Expenses Offset Within Net Income
Non-employee directors deferred compensation, offset in other income 4.2
Change in Items Offset Within Net Income 4.2
Increase in Administrative & General Expenses $ 7.8
Uncollectible accounts expense decreased due to collections of previously written off amounts in the current period. In the second quarter of 2020, we voluntarily suspended service disconnections for non-payment, to help customers who may be financially impacted by the COVID-19 pandemic.
Property and other taxes were $173.4 million in 2021, as compared with $179.5 million in 2020. This decrease was primarily due to lower estimated property valuations in Montana partly offset by plant additions.
Depreciation and depletion expense was $187.5 million in 2021, as compared with $179.6 million in 2020. This increase was primarily due to plant additions.
Consolidated operating income in 2021 was $275.7 million as compared with $236.2 million in 2020. This increase was primarily driven by higher Montana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period due to the COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, a favorable electric QF liability adjustment as compared with the prior period, and lower property and other taxes, partly offset by higher operation and maintenance expense, depreciation expense, and administrative and general expense.
Consolidated interest expense in 2021 was $93.7 million, as compared with $96.8 million in 2020. This decrease was primarily due to higher capitalization of AFUDC and lower FERC deferrals, partly offset by higher borrowings.
Consolidated other income in 2021 was $8.3 million, as compared with $4.9 million in 2020. This increase was primarily due to higher capitalization of AFUDC and higher interest income, partly offset by $2.1 million in items offset in operating expenses. Items offset in operating expenses include a $6.3 million increase in pension expenses and a $4.2 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation.
Consolidated income tax expense in 2021 was $3.4 million, as compared to an income tax benefit of $11.0 million in 2020. Our effective tax rate for the twelve months ended December 31, 2021 was 1.8 percent as compared with (7.6) percent for the same period of 2020. We currently estimate our effective tax rate will range between 0.0 percent to 3.0 percent in 2022. The effective tax rate is expected to gradually increase to approximately 15 percent by 2026.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
Year Ended December 31,
2021 2020
Income Before Income Taxes $ 190.3 $ 144.2
Income tax calculated at federal statutory rate 40.0 21.0 % 30.3 21.0 %
Permanent or flow through adjustments:
State income, net of federal provisions 0.4 0.1 (1.5) (1.1)
Flow-through repairs deductions (21.9) (11.5) (23.8) (16.5)
Production tax credits (11.5) (6.1) (13.1) (9.1)
Plant and depreciation of flow through items (0.9) (0.6) 0.1 0.1
Amortization of excess deferred income taxes (DIT) (0.6) (0.3) (1.0) (0.7)
Prior year permanent return to accrual adjustments 0.0 0.0 (1.7) (1.2)
Other, net (2.1) (0.8) (0.3) (0.1)
(36.6) (19.2) (41.3) (28.6)
Income Tax Expense (Benefit) $ 3.4 1.8 % $ (11.0) (7.6) %
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, 2021 Compared with Year Ended December 31, 2020
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 334,581 $ 320,792 $ 13,789 4.3 % 2,729 2,635 311,922 307,390
South Dakota 65,429 66,603 (1,174) (1.8) 571 583 50,805 50,646
Residential 400,010 387,395 12,615 3.3 3,300 3,218 362,727 358,036
Montana 356,669 338,269 18,400 5.4 3,176 3,036 71,605 70,145
South Dakota 102,475 101,095 1,380 1.4 1,092 1,073 12,795 12,802
Commercial 459,144 439,364 19,780 4.5 4,268 4,109 84,400 82,947
Industrial 37,866 36,819 1,047 2.8 2,448 2,615 77 78
Other 32,084 31,833 251 0.8 175 173 6,333 6,333
Total Retail Electric $ 929,104 $ 895,411 $ 33,693 3.8 % 10,191 10,115 453,537 447,394
Regulatory amortization 34,395 (11,455) 45,850 (400.3)
Transmission 82,628 51,539 31,089 60.3
Wholesale and Other 6,055 5,320 735 13.8
Total Revenues $ 1,052,182 $ 940,815 $ 111,367 11.8 %
Fuel, purchased supply and direct transmission expense(1)
294,820 236,581 58,239 24.6
Utility Margin(2)
$ 757,362 $ 704,234 $ 53,128 7.5 %
(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 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 635 398 417 60% warmer 52% warmer
South Dakota 1,034 879 733 18% warmer 41% warmer
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 7,217 7,304 7,557 1% warmer 4% warmer
South Dakota 6,758 7,445 7,696 9% warmer 12% warmer
The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2021 and 2020 (in millions):
Utility Margin
2021 vs. 2020
Utility Margin Items Impacting Net Income
Higher transmission rates and demand due to market conditions and pricing and the recognition of approximately $4.7 million of deferred interim revenues $ 25.1
Higher retail volumes 17.1
Prior period disallowance of supply costs 9.4
QF liability adjustment 4.4
Higher non-recoverable Montana electric supply costs compared to the prior period (5.3)
Other 3.3
Change in Utility Margin Impacting Net Income 54.0
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (4.0)
Higher revenue from lower production tax credits, offset in income tax expense 2.5
Operating expenses recovered in revenue, offset in operating and maintenance expense 0.6
Change in Items Offset Within Net Income (0.9)
Increase in Utility Margin(1)
$ 53.1
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Higher electric retail volumes were driven by warmer summer weather in both Montana and South Dakota, customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer overall winter weather in Montana and South Dakota. The favorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $7.5 million gain in 2021, as compared with a $3.1 million gain for the same period in 2020, due to the combination of:
•A $2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $0.9 million favorable reduction in costs in the prior period;
•A negative adjustment, increasing the QF liability by $2.1 million, reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of $2.2 million in the prior year due to lower actual price escalation; and
•A favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term.
The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
NATURAL GAS OPERATIONS
We have various classifications of natural gas revenues, defined as follows:
•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Year Ended December 31, 2021 Compared with Year Ended December 31, 2020
Revenues Change Dekatherms Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 126,043 $ 103,457 22,586 21.8 % 13,885 13,893 179,637 177,335
South Dakota 26,596 21,547 5,049 23.4 2,834 2,993 41,079 40,612
Nebraska 20,964 16,861 4,103 24.3 2,480 2,561 37,603 37,576
Residential 173,603 141,865 31,738 22.4 19,199 19,447 258,319 255,523
Montana 64,681 51,349 13,332 26.0 7,446 7,166 24,927 24,497
South Dakota 19,131 14,316 4,815 33.6 2,744 3,003 6,896 6,895
Nebraska 11,371 8,066 3,305 41.0 1,755 1,784 4,963 4,974
Commercial 95,183 73,731 21,452 29.1 11,945 11,953 36,786 36,366
Industrial 1,134 840 294 35.0 135 122 229 231
Other 1,417 923 494 53.5 187 152 166 153
Total Retail Gas $ 271,337 $ 217,359 $ 53,978 24.8 % 31,466 31,674 295,500 292,273
Regulatory amortization 12,048 5,043 7,005 138.9
Wholesale and other 36,749 35,453 1,296 3.7
Total Revenues $ 320,134 $ 257,855 $ 62,279 24.2 %
Fuel, purchased supply and direct transmission expense(1)
130,728 69,609 61,119 87.8
Utility Margin(2)
$ 189,406 $ 188,246 $ 1,160 0.6 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 7,390 7,505 7,775 2% warmer 5% warmer
South Dakota 6,758 7,445 7,696 9% warmer 12% warmer
Nebraska 5,632 5,676 6,354 1% warmer 11% warmer
The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2021 and 2020 (in millions):
Utility Margin
2021 vs. 2020
Utility Margin Items Impacting Net Income
Higher retail volumes $ 1.3
Reduction of rates from the step down of our Montana gas production assets (1.2)
Other 1.8
Change in Utility Margin Impacting Net Income 1.9
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (0.8)
Operating expenses recovered in revenue, offset in operating and maintenance expense (0.4)
Gas production taxes recovered in revenue, offset in property and other taxes 0.5
Change in Items Offset Within Net Income (0.7)
Increase in Utility Margin(1)
$ 1.2
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Higher retail volumes were driven by improved Montana commercial volumes as compared to the prior year due to the COVID-19 pandemic related shutdowns and customer growth, partly offset by overall warmer weather in all jurisdictions.
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.
As of December 31, 2021, our total net liquidity was approximately $79.8 million, including $2.8 million of cash, $77.0 million of revolving credit facility availability with no letters of credit outstanding. In addition, our liquidity was further enhanced by the forward equity sale agreements noted below, which could have been physically settled with common shares in exchange for cash of $286.1 million.
Cash Flows
The primary sources and uses of cash and cash equivalents are summarized in the following condensed statement of cash flows for 2021 and 2020 (in millions):
Year Ended December 31,
2021 2020
Operating Activities
Net income $ 186.8 $ 155.2
Non-cash adjustments to net income 187.5 174.3
Changes in working capital (120.6) 48.1
Other noncurrent assets and liabilities (33.7) (25.5)
Cash Provided by Operating Activities 220.0 352.1
Investing Activities
Property, plant and equipment additions (434.3) (405.8)
Investment in equity securities (1.5) -
Cash Used in Investing Activities (435.8) (405.8)
Financing Activities
Proceeds from issuance of common stock, net 196.2 -
Issuance of long-term debt 99.9 150.0
(Repayments) issuances of short-term borrowings (100.0) 100.0
Dividends on common stock (128.5) (120.4)
Line of credit borrowings (repayments), net 151.0 (67.0)
Financing costs (0.9) (2.6)
Other (0.2) (1.3)
Cash Provided by Financing Activities 217.5 58.7
Net Increase in Cash, Cash Equivalents, and Restricted Cash $ 1.7 $ 5.0
Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 17.1 $ 12.1
Cash, Cash Equivalents, and Restricted Cash, end of period $ 18.8 $ 17.1
Operating Activities
Cash provided by operating activities totaled $220.0 million for the year ended December 31, 2021 as compared with $352.1 million during 2020. This decrease in operating cash flows is primarily due to a $122.3 million ($80.0 million from
electric operations and $42.3 million from natural gas operations) net increase in under collection of energy supply costs from customers in the current period, which includes costs incurred during a February 2021 prolonged cold weather event, the under-collected position of Montana's PCCAM, and a refund of approximately $20.5 million to our FERC regulated customers and approximately $6.1 to our Montana electric retail customers. These reductions were offset in part by an improvement in net income.
As of December 31, 2021, we have under collected our supply costs recovered through tracking mechanisms by approximately $97.8 million. We have various regulatory mechanisms that support our recovery of the energy supply costs incurred by our utilities. Through these mechanisms and the regulatory agreements for recovery of the costs incurred during the February 2021 cold weather event, we anticipate recovering a significant portion of these costs during 2022, improving our cash flows from operations. Conversely, a prolonged spike in energy market prices in our operating jurisdictions, which could be caused by further extreme weather events, could create additional costs with deferred recovery that would offset these anticipated cash flow improvements.
Investing Activities
Cash used in investing activities totaled $435.8 million during the year ended December 31, 2021, as compared with $405.8 million during 2020. Plant additions during 2021 include capital maintenance additions of approximately $314.1 million, and capacity related capital expenditures of approximately $120.2 million. Plant additions during 2020 included capital maintenance additions of approximately $269.5 million, and capacity related capital expenditures of approximately $136.3 million. As discussed above in the “Significant Infrastructure Investments and Initiatives” section, our capital expenditures are forecasted to increase to $582 million in 2022.
Financing Activities
Cash provided by financing activities totaled $217.5 million during 2021 as compared with $58.7 million during 2020. During 2021, the increase in cash provided by financing activities reflected the transactions noted below, which were undertaken primarily to fund capital expenditures in excess of our cash from operations, while maintaining our credit ratings.
We issue debt and equity securities from time to time to refinance retiring debt maturities, reduce balances on our revolving credit facilities, fund capital expenditure programs, maintain credit ratings, and for other general corporate purposes.
In March 2021, we issued and sold $100 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00% maturing in March 26, 2024. The net proceeds were used to repay in full our outstanding $100 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time
to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the
bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding,
the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming.
In April 2021, we entered into an Equity Distribution Agreement with BofA Securities, Inc., CIBC World Markets Corp, Credit Suisse Securities (USA) LLC, and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the three months ended December 31, 2021, we issued 46,723 shares of our common stock under the ATM program at an average price of $58.49, for net proceeds of $2.7 million, which is net of sales commissions and other fees paid of less than $0.1 million. During the twelve months ended December 31, 2021, we issued 1,966,117 shares of our common stock under the ATM program at an average price of $63.81, for net proceeds of $124.2 million, which is net of sales commissions and other fees paid of approximately $1.3 million. We do not expect to utilize the ATM program during 2022.
In November 2021, we entered into forward equity agreements in connection with a completed $373.8 million public offering of approximately 7.0 million shares of our common stock. The initial forward agreement was for 6.1 million shares with an additional 0.9 million shares exercised at the option of the banking counterparty. Of the total 7.0 million shares of common stock offered, we initially sold 1.4 million shares, for $75.0 million in gross proceeds, directly to the underwriters in the offering, with cash proceeds received at closing.
At December 31, 2021, the forward agreements could have been settled with physical delivery of approximately 5.6 million common shares to the banking counterparty in exchange for cash of $286.1 million. The forward instruments could have also
been settled at December 31, 2021, with delivery of approximately $24.4 million of cash or approximately 0.4 million shares of common stock to the counterparty, if we unilaterally elected to net cash or net share settlement, respectively.
The forward price used to determine amounts due at settlement is calculated based on the November 2021 public offering price for our common stock of $53.50, net of underwriting discount, for an initial forward settlement price of $51.895, per share. The initial forward settlement price is increased for the overnight bank funding rate, less a spread of 0.75 percent and less expected dividends on our common stock during the period the instruments are outstanding.
We may settle the agreements at any time up to the maturity date of February 28, 2023. Depending on settlement timing, if we elect to physically settle by delivering shares of common stock, cash proceeds are expected to be approximately $269.8 million to $286.1 million. Forward equity instruments were recognized within stockholders’ equity at fair value at the execution of the agreements and will not be subsequently adjusted until settlement.
Cash Requirements and Capital Resources
The Company believes its cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy its material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports timely recovery for many our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.
Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to increase to $582 million in 2022, $563 million in 2023, and $465 million in 2024. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt and equity issuances and future rate increases. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations or available financing could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities we evaluate the additional capital need in balance with, debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
Credit Facilities
Liquidity is generally provided by internal cash flows and the use of our unsecured revolving credit facilities. This includes the $425 million Credit Facility and a $25 million revolving credit facility to provide swingline borrowing capability. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.
Our $425 million Credit Facility was entered into in September 2020 and has a maturity date of September 2, 2023. The Credit Facility includes uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size by an additional $75 million with the consent of the lenders. The Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to the Eurodollar rate, plus a margin of 112.5 to 175.0 basis points, or a base rate, plus a margin of 12.5 to 75.0 basis points. A total of ten banks participate in the facility, with no one bank providing more than 13 percent of the total availability.
The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2021 (in millions):
Amount outstanding at year end $ 373.0
Daily average amount outstanding $ 260.3
Maximum amount outstanding $ 373.0
Minimum amount outstanding $ 171.0
As of February 4, 2022, our availability under our revolving credit facilities was approximately $112.0 million, and there were no letters of credit outstanding.
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We do not have any long-term debt maturities in 2022.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
As described above, during 2021 we entered into a three-year ATM equity offering program whereby we can offer to sell up to $200.0 million of common shares. During 2021 we raised nearly $125 million under the program, but do not anticipate needing to issue equity through this program in 2022. We also initiated a public offering of $373.8 million of our common stock in November 2021. We received approximately $75 million of cash proceeds for a portion of this offering and entered into forward equity agreements for the balance of the shares. We may settle the forward sale agreements at any time up to the maturity date of February 28, 2023. We anticipate physically settling these agreements to meet our equity capital needs for 2022. Depending on settlement timing, if we physically settle by delivering our shares of common stock, cash proceeds are expected to be approximately $269.8 million to $286.1 million.
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service (Moody's), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of February 4, 2022, our current ratings with these agencies are as follows:
Senior Secured Rating Senior Unsecured Rating Commercial Paper Outlook
Fitch A A- Stable
Moody’s A3 Baa2 Prime-2 Negative
S&P A- BBB A-2 Stable
_________________________
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2021. See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements.
Total 2022 2023 2024 2025 2026 Thereafter
(in thousands)
Long-term debt(1)
$ 2,552,660 $ - $ 517,660 $ 100,000 $ 300,000 $ 105,000 $ 1,530,000
Finance leases 14,772 2,875 3,099 3,337 3,596 1,865 -
Estimated pension and other postretirement obligations(2)
58,805 12,775 11,658 11,658 11,357 11,357 N/A
Qualifying facilities liability(3)
466,872 80,355 82,452 75,113 60,360 55,393 113,199
Supply and capacity contracts(4)
2,640,393 283,212 269,700 221,758 219,443 172,227 1,474,053
Contractual interest payments on debt(5)
1,480,783 88,457 86,270 79,760 70,791 64,701 1,090,804
Commitments for significant capital projects(6)
268,372 192,239 69,533 6,600 - - $ -
Total Commitments(7)
$ 7,482,657 $ 659,913 $ 1,040,372 $ 498,226 $ 665,547 $ 410,543 $ 4,208,056
___________________________
(1)Represents cash payments for long-term debt and excludes $11.2 million of debt discounts and debt issuance costs, net.
(2)We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.
(3)Certain QFs require us to purchase minimum amounts of energy at prices ranging from $64 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $466.9 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $388.4 million.
(4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts (exclusive of the qualifying facilities liability discussed above). These commitments range from one to 24 years and exclude contract payments associated with the Beartooth Battery agreement, which is subject to approval by the MPSC. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC, as further described in Note 3 - Regulatory Matters.
(5)Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 1.35 percent on the outstanding balance through maturity of the facilities.
(6)Represents significant firm purchase commitments for construction of planned capital projects.
(7)The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 18 - Commitments and Contingencies) and asset retirement obligations (AROs) (see Note 6 - Asset Retirement Obligations) as the amount and timing of cash payments may be uncertain.
CRITICAL ACCOUNTING ESTIMATES
Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.
We have identified the policies and related procedures below that contain accounting estimates that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations.
Regulatory Assets and Liabilities
Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets.
While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 4 - Regulatory Assets and Liabilities, to the Consolidated Financial Statements for further discussion.
Pension and Postretirement Benefit Plans
We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 14 - Employee Benefit Plans, to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
•Discount rates used in determining the future benefit obligations;
•Expected long-term rate of return on plan assets; and
•Mortality assumptions.
We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions.
We set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year projected benefit cash flow from our plans. Based on this analysis as of December 31, 2021, our discount rate on the NorthWestern Corporation pension plan is 2.65 percent and on the NorthWestern Energy pension plan is 2.75 percent.
In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Our expected long-term rate of return on assets assumptions are 3.01 percent and 4.17 percent on the NorthWestern Corporation and NorthWestern Energy pension plan, respectively, for 2022.
Cost Sensitivity
The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):
Actuarial Assumption (1) Change in Assumption Impact on Pension Cost Impact on Projected
Benefit Obligation
Discount rate increase 0.25 % $ (2,232) $ (23,069)
Discount rate decrease (0.25) % 2,415 24,377
Rate of return on plan assets increase 0.25 % (1,670) N/A
Rate of return on plan assets decrease (0.25) % 1,670 N/A
(1) Reflects sensitivity to the period pension cost only and excludes the $11.3 million settlement charge during 2021, which was associated with the partial pension annuitization described in Note 14 - Employee Benefit Plans.
Accounting Treatment
We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees.
Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates.
The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $32.0 million as of December 31, 2021. The resolution of tax matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows. See Note 12 - Income Taxes to the Consolidated Financial Statements for further discussion.
Qualifying Facilities Liability
Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Under the terms of these contracts, we are required to purchase minimum amounts of energy at prices ranging from $64 to $136 per MWH through June 2029. Our estimated gross contractual obligation is approximately $466.9 million through June 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $388.4 million through June 2029. We maintain an electric QF liability based on the net present value (discounted at 7.75 percent) of the difference between our estimated obligations under the QFs and the fixed amounts recoverable in rates.
The liability was established based on certain assumptions and projections over the contract terms related to pricing, estimated output and recoverable amounts. Since the liability is based on projections over the next several years, actual output, changes in pricing, contract amendments and regulatory decisions relating to these facilities could significantly impact the liability and our results of operations in any given year. In assessing the liability each reporting period, we compare our assumptions to actual results and make adjustments as necessary for that period.
One of the contracts contains variable pricing terms, which exposes us to price escalation risks. The estimated annual escalation rate for this contract is a key assumption and is based on a combination of historical actual results and market data available for future projections. In recording the electric QF liability, we estimated an annual escalation rate of 3 percent over the remaining term of the contract (through June 2024). The actual escalation rate changes annually, which could significantly impact the liability and our results of operations. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements for further discussion.
NEW ACCOUNTING STANDARDS
See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.
Interest Rate Risk
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing fixed-rate long-term debt with varying maturities, refinancing certain debt and, at times, hedging the interest rate on anticipated borrowings. All of our debt has fixed interest rates, with the exception of our revolving credit facilities. The $425 million revolving credit facility bears interest at rates equal to the Eurodollar rate, plus a margin of 112.5 to 175.0 basis points, or a base rate, plus a margin of 12.5 to 75.0 basis points. In addition, we have a $25 million revolving credit facility, to provide swingline borrowing capability. The $25 million revolving credit facility bears interest at the lower of prime plus a credit spread of 0.13 percent, or available rates tied to the Eurodollar rate plus a credit spread of 0.65 percent. As of December 31, 2021, we had approximately $373 million in borrowings under our revolving credit facilities. A 1.0 percent increase in interest rates would increase our annual interest expense by approximately $3.7 million.
Commodity Price Risk
We are exposed to commodity price risk due to our reliance on market purchases to fulfill a portion of our electric and natural gas supply requirements. We also participate in the wholesale electric market to balance our supply of power from our own generating resources. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
As part of our overall strategy for fulfilling our electric and natural gas supply requirements, we employ the use of market purchases and sales, including forward contracts. These types of contracts are included in our supply portfolios and in some instances, are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. These contracts are part of an overall portfolio approach intended to provide price stability for consumers. As a regulated utility, our exposure to market risk caused by changes in commodity prices is mitigated because these commodity costs are included in our Montana, South Dakota and Nebraska cost tracking mechanisms and are recoverable from customers subject to a regulatory review for prudency and, in Montana, a sharing mechanism.
Counterparty Credit Risk
We are exposed to counterparty credit risk related to the ability of counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. If counterparties seek financial protection under bankruptcy laws, we are exposed to greater financial risks. We are also exposed to counterparty credit risk related to providing transmission service to our customers under our Open Access Transmission Tariff and under gas transportation agreements. We have risk management policies in place to limit our transactions to high quality counterparties. We monitor closely the status of our counterparties and take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

---

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

---

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

---

ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of December 31, 2021, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Annual Report on Internal Control over Financial Reporting
The management of NorthWestern is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board regarding the preparation and fair presentation of published financial statements.
All internal controls over financial reporting, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention or overriding of controls. Therefore, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
Our management, including our chief executive officer and chief financial officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2021. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on our evaluation, management concluded that, as of December 31, 2021, our internal control over financial reporting was effective based on those criteria.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. Their report appears on page.

---

ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
As previously reported, on April 22, 2021 at the 2021 Annual Meeting of Stockholders, the stockholders approved the NorthWestern Corporation Amended and Restated Equity Compensation Plan (the Plan), including the issuance of an additional 700,000 shares of common stock. The Plan permits a committee of the Board to grant to designated officers, employees and non-employee directors of NorthWestern and its affiliates incentive awards in the form of performance units, restricted shares, restricted share units, unrestricted shares, deferred share units, options, share appreciation rights and other awards including the payment of stock in lieu of cash under our other incentive or bonus programs or otherwise and payment of cash based on attainment of performance goals. A more detailed summary of the material features of the Plan is set forth in our proxy statement for the 2021 Annual Meeting of Stockholders filed with the Securities and Exchange Commission on March 5, 2021. A copy of the Plan is included as an Appendix to such proxy statement.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item with respect to directors and corporate governance will be set forth in NorthWestern Corporation's Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to our Executive Officers is included under "Information about our Executive Officers" in Item 1 of this report.

---

ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item will be set forth in NorthWestern Corporation's Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated herein by reference.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item will be set forth in NorthWestern Corporation's Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated herein by reference.

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information concerning relationships and related transactions of the directors and officers of NorthWestern Corporation and director independence will be set forth in NorthWestern Corporation's Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated herein by reference.

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information concerning fees paid to the principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34), for each of the last two years will be set forth in NorthWestern Corporation's Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated herein by reference.
Part IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
(1)Consolidated Financial Statements.
The following items are included in Part II, Item 8 of this annual report on Form 10-K:
CONSOLIDATED FINANCIAL STATEMENTS:
Page
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2021, 2020, and 2019
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Balance Sheets as of December 31, 2021 and 2020
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019
Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2021, 2020, and 2019
Notes to Consolidated Financial Statements
Fourth Quarter Unaudited Financial Data for the Years Ended December 31, 2021 and 2020
All schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes thereto.
(2)Exhibits.
The exhibits listed below are hereby filed with the SEC, as part of this Annual Report on Form 10-K. Certain of the following exhibits have been previously filed with the SEC pursuant to the requirements of the Securities Act of 1933 or the Securities Exchange Act of 1934. Such exhibits are identified by the parenthetical references following the listing of each such exhibit and are incorporated by reference. We will furnish a copy of any exhibit upon request, but a reasonable fee may be charged to cover our expenses in furnishing such exhibit.
Exhibit
Number Description of Document
2.1(a)
Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated October 20, 2004, Commission File No. 1-10499).
2.1(b)
Order Confirming the Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.2 of NorthWestern Corporation's Current Report on Form 8-K, dated October 20, 2004, Commission File No. 1-10499).
3.1(a)
Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated May 3, 2016 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).
3.2(a)
Amended and Restated Bylaws of NorthWestern Corporation, dated May 12, 2016 (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 18, 2016, Commission File No. 1-10499).
4.1(a) First Mortgage and Deed of Trust, dated as of October 1, 1945, by The Montana Power Company in favor of Guaranty Trust Company of New York and Arthur E. Burke, as trustees (incorporated by reference to Exhibit 7(e) of The Montana Power Company's Registration Statement, Commission File No. 002-05927).
4.1(b)
Eighteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of August 5, 1994 (incorporated by reference to Exhibit 99(b) of The Montana Power Company's Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739).
4.1(c)
Twenty-Eighth Supplemental Indenture, dated as of October 1, 2009, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, Commission File No. 1-10499).
4.1(d)
Twenty-Ninth Supplemental Indenture, dated as of May 1, 2010, among NorthWestern Corporation and The Bank of New York Mellon and Ming Ryan, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499).
4.1(e)
Thirtieth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon and Philip L. Watson, as trustees under the Mortgage and Deed of Trust dated as of October 1, 1945 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).
4.1(f)
Thirty-First Supplemental Indenture, dated as of December 1, 2013, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2013, Commission File No. 1-10499).
4.1(g)
Thirty-Second Supplemental Indenture, dated as of November 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.4(n) of the Company's Report on Form 10-K for the year ended December 31, 2014, Commission File No. 1-10499).
4.1(h)
Thirty-Third Supplemental Indenture, dated as of November 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 14, 2014, Commission File No. 1-10499).
4.1(i)
Thirty-Fourth Supplemental Indenture, dated as of January 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.4(p) of the Company's Report on Form 10-K for the year ended December 31, 2014, Commission File No. 1-10499).
4.1(j)
Thirty-Fifth Supplemental Indenture, dated as of June 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2015, Commission File No. 1-10499).
4.1(k)
Thirty-Seventh Supplemental Indenture, dated as of November 1, 2017, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated November 8, 2017, Commission File No. 1-10499).
4.1(l)
Thirty-Eighth Supplemental Indenture, dated as of June 1, 2019, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated July 2, 2019, Commission File No. 1-10499).
4.1(m)
Thirty-Ninth Supplemental Indenture, dated as of September 1, 2019, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated September 20, 2019, Commission File No. 1-10499).
4.1(n)
Fortieth Supplemental Indenture, dated as of April 1, 2020, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 15, 2020, Commission File No. 1-10499).
4.2(a) General Mortgage Indenture and Deed of Trust, dated as of August 1, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(a) of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 1993, Commission File No. 1-10499).
4.2(b)
Supplemental Indenture, dated as of November 1, 2004, by and between NorthWestern Corporation (formerly known as Northwestern Public Service Company) and JPMorgan Chase Bank (successor by merger to The Chase Manhattan Bank (National Association)), as Trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.5 of NorthWestern Corporation's Current Report on Form 8-K, dated November 1, 2004, Commission File No. 1-10499).
4.2(c)
Ninth Supplemental Indenture, dated as of May 1, 2010, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499).
4.2(d)
Tenth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon, as trustees under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499).
4.2(e)
Eleventh Supplemental Indenture, dated as of December 1, 2013, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2013, Commission File No. 1-10499).
4.2(f)
Twelfth Supplemental Indenture, dated as of December 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2014, Commission File No. 1-10499).
4.2(g)
Thirteenth Supplemental Indenture, dated as of September 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, Commission File No. 1-10499).
4.2(h)
Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499).
4.2(i)
Fifteenth Supplemental Indenture, dated as of September 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 6, 2016, Commission File No. 1-10499).
4.2(j)
Sixteenth Supplemental Indenture, dated as of April 1, 2020, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 15, 2020, Commission File No. 1-10499).
4.3(a)
Indenture, dated as of August 1, 2016, between City of Forsyth, Rosebud County, Montana and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(b)
Loan Agreement, dated as of August 1, 2016, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit 4.2 of the Company's Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(c)
Bond Delivery Agreement, dated as of August 1, 2016, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(d)
Thirty-Sixth Supplemental Indenture, dated as of August 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499).
4.3(e)
Forty-First Supplemental Indenture, dated as of March 1, 2021, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 26, 2021, Commission File No. 1-10499).
4.5*
Description of Securities
10.1(a) †
NorthWestern Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, as amended April 21, 2010 (incorporated by reference to Exhibit 10.3 of NorthWestern Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499).
10.1(b) †
NorthWestern Corporation 2009 Officers Deferred Compensation Plan, as amended April 21, 2010 (incorporated by reference to Exhibit 10.4 of NorthWestern Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499).
10.1(c) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 5, 2011, Commission File No. 1-10499).
10.1(d) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 12, 2012, Commission File No. 1-10499).
10.1(e) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 10, 2013, Commission File No. 1-10499).
10.1(f) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 18, 2014, Commission File No. 1-10499).
10.1(g) †
NorthWestern Corporation Amended and Restated Equity Compensation Plan, as amended effective July 1, 2014 (incorporated by reference to Appendix A to NorthWestern Corporation's Proxy Statement for the 2014 Annual Meeting of Shareholders filed on March 7, 2014, Commission File No. 1-10499).
10.1(h) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2014, Commission File No. 1-10499).
10.1(i) †
NorthWestern Corporation Key Employee Severance Plan 2016 (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation's Current Report on Form 8-K, dated October 25, 2016, Commission File No. 1-10499).
10.1(j) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 13, 2016, Commission File No. 1-10499).
10.1(k) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 23, 2017, Commission File No. 1-10499).
10.1(l) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 16, 2018, Commission File No. 1-10499).
10.1(m) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 19, 2018, Commission File No. 1-10499).
10.1(n) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 15, 2019, Commission File No. 1-10499).
10.1(o) †
NorthWestern Energy 2020 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 23, 2019, Commission File No. 1-10499).
10.1(p) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 23, 2019, Commission File No. 1-10499).
10.1(q) †
NorthWestern Energy 2021 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2020, Commission File No. 1-10499).
10.1(r) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2020, Commission File No. 1-10499).
10.1(s) †
Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 11, 2021, Commission File No. 1-10499).
10.1(t) †
NorthWestern Corporation Amended and Restated Equity Compensation Plan, as amended effective May 1, 2021 (incorporated by reference to Appendix A to NorthWestern Corporation's Proxy Statement for the 2014 Annual Meeting of Shareholders filed on March 5, 2021, Commission File No. 1-10499).
10.1(u) †
NorthWestern Energy 2022 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2021, Commission File No. 1-10499).
10.1(v) †
Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2021, Commission File No. 1-10499).
10.2(a)
Commercial Paper Dealer Agreement between NorthWestern Corporation and Merrill Lynch, Pierce, Fenner & Smith Incorporated, dated as of February 3, 2011 (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation's Current Report on Form 8-K, dated February 8, 2011, Commission File No. 1-10499).
10.2(b)
Bond Purchase Agreement, dated as of October 31, 2017, between NorthWestern Corporation and initial purchasers (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on form 10-Q, dated November 2, 2017, Commission File No. 1-10499).
10.2(c)
Credit Agreement, dated September 2, 2020, among NorthWestern Corporation, as borrower; the several banks and other financial institutions or entities from time to time parties to the agreement, as lenders; BofA Securities, Inc., Credit Suisse Securities (USA) LLC, and U.S. Bank National Association as joint lead arrangers; Credit Suisse Securities (USA) LLC, and U.S. Bank National Association as co-syndication agents; Keybank National Association as documentation agent; and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation's Current Report on Form 8-K, dated September 4, 2020, Commission File No. 1-10499).
10.3(a)
Equity Distribution Agreement, dated April 23, 2021, between NorthWestern Corporation and J.P. Morgan Securities LLC, BofA Securities, Inc., CIBC World Markets Corp. and Credit Suisse Securities (USA) LLC, as sales agents and forward sellers; and JPMorgan Chase Bank, National Association, Bank of America N.A, Canadian Imperial Bank of Commerce and Credit Suisse Capital LLC, as forward purchasers. (incorporated by reference to Exhibit 1.1 of NorthWestern Corporation's Current Report on Form 8-K, dated April 23, 2021, Commission File No. 1-10499).
10.3(b)
Form of Master Forward Sale Confirmation (incorporated by reference to Exhibit 1.2 of Northwestern Corporation's Current Report on Form 8-K, dated April 23, 2021, Commission File No. 1-10499)
10.3(c)
Forward Sale Agreement, dated November 16, 2021, between NorthWestern Corporation and Bank of America, N.A., as forward purchaser (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation's Current Report on Form 8-K, dated November 15, 2021, Commission File No. 1-10499).
10.3(d)
Additional Forward Sale Agreement, dated November 17, 2021, between NorthWestern Corporation and Bank of America, N.A., as forward purchaser (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation's Current Report on Form 8-K, dated November 15, 2021, Commission File No. 1-10499).
10.4(a)
Engineering, Procurement, and Construction Contract, dated April 19, 2021, between Northwestern Energy and Burns & McDonnell Engineering Company, Inc (incorporated by reference to Exhibit 10.3 of NorthWestern Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, Commission File No. 1-10499).
10.4(b)
Procurement Contract, dated April 19, 2021, between Northwestern Energy and Caterpillar Power Generation Systems, LLC (incorporated by reference to Exhibit 10.4 of NorthWestern Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, Commission File No. 1-10499).
21*
Subsidiaries of NorthWestern Corporation.
23*
Consent of Independent Registered Public Accounting Firm
24* Power of Attorney (included on the signature page of this Annual Report on Form 10-K)
31.1*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1*
Certification of Robert C. Rowe pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification of Crystal Lail pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS* Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH* Inline XBRL Taxonomy Extension Schema Document
101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* Inline XBRL Taxonomy Label Linkbase Document
101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
† Management contract or compensatory plan or arrangement.
* Filed herewith.
All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are not applicable, and, therefore, have been omitted.