EDGAR 10-K Filing

Company CIK: 73088
Filing Year: 2021
Filename: 73088_10-K_2021_0000073088-21-000026.json

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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 743,000 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 utility operations include the generation, purchase, transmission, and distribution of electricity. Our natural gas utility operations include the production, purchase, transmission, storage, and distribution of natural gas. 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 http://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. We 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 2020, approximately 65 percent of our retail needs originated from carbon-free resources, more than two times better than the total U.S. electric power industry (29 percent carbon-free).
Montana - Commitment to Reduction in Carbon Intensity
Nearly 70% of the 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. Over the last decade, 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 2020, we delivered electricity to approximately 384,700 customers in 208 communities and their surrounding rural areas, 11 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2020, 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 956
Miles of 161 kV 1,192
Miles of 115 kV and lower voltage 4,164
Total Miles of Electric Transmission Lines 6,809
Electric Distribution Lines
Miles of overhead line
13,071
Miles of underground line
4,997
Total Miles of Electric Distribution Lines 18,068
Total Transmission and Distribution Substations 398
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 1,799 MWs on January 14, 2020. Our control area average demand for 2020 was approximately 1,305 MWs per hour, with total energy delivered of more than 12.0 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. 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 2020. We expect that approximately 65 percent of our retail obligations will be met by owned generation resources in 2021. In addition, QFs provide a total of 388 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 2021, including both owned and contracted resources, we have resources to provide over 90 percent of the energy 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 18
Holter 1918 Missouri 2040 48
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 71.5
Thompson Falls 1915/1995 Clark Fork 2025 94
Total 447.5
(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 and Portfolio Standards
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. We have significant projected generation capacity deficits and negative reserve margins. In Montana, approximately 46 percent of our peak electric requirements are served by market purchases, exposing our customers to greater market exposure (price and availability) than our regional peers. Based on current estimates, we forecast that our portfolio will be 725 MW short by 2025 (including reserve margins), considering expiring contracts and a modest increase in customer demand.
We issued an all-source competitive solicitation request in February 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 reliability standards effective July 2016 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.
Renewable portfolio standards (RPS) enacted in Montana currently require that 15 percent of our annual electric supply portfolio be derived from eligible sources, including resources such as wind, biomass, solar, and small hydroelectric. Eligible
resources used to serve our load generate RECs. Any RECs in excess of the annual requirements for a given year are carried forward for up to two years to meet future RPS needs. While our hydro generation assets are not eligible resources under the RPS, any qualifying additions would be eligible. Given contracts under negotiation and our portfolio resources, we expect to meet the Montana RPS requirements through the 2040s. The penalty for not meeting the RPS is up to $10 per MWH for each REC short of the requirement.
Western Energy Imbalance Market
We expect to enter the Western Energy Imbalance Market (EIM), operated by the California Independent System Operator (California ISO), in the second quarter of 2021. We studied the value and costs of the 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. 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. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States.
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 63,900 customers in 110 communities in South Dakota. In 2020, by category, residential, commercial and other sales accounted for approximately 39%, 59%, and 2%, respectively, of our South Dakota retail electric utility revenue.
Transmission and Distribution
Our electric system includes high voltage transmission and low voltage distribution lines as follows:
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
1,631
Miles of underground line
Total Miles of Electric Distribution Lines 2,314
Total Transmission and Distribution Substations 119
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 328 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
Coyote I Electric Generating Station, located near Beulah, North Dakota Lignite coal 10.0% 43
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa Sub-bituminous coal 8.7% 56
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
Miscellaneous combustion turbine units and small diesel units (used only during peak periods) Combination of fuel oil and natural gas 100.0% 41
Total 411
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 60 MW of flexible reciprocating internal combustion engines at a brownfield site near Huron, South Dakota expected to be in service by late 2021, with construction costs of approximately $80 million, and a new 30-40 MW flexible generation facility in Aberdeen, South Dakota planned to be in service in early 2024, with a cost of approximately $60 million.
NATURAL GAS OPERATIONS
Montana
Our regulated natural gas utility business in Montana includes production, storage, transmission and distribution. During 2020, we distributed natural gas to approximately 203,700 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 42 Bcf during the year ended December 31, 2020.
Miles of Natural Gas Transmission 2,165
Miles of Natural Gas Distribution 4,892
City Gate Stations 150
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 336,000 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, 2020, were approximately 21.0 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2020, were approximately 2.8 Bcf. We have contracted with several major producers and marketers with varying contract durations to provide the anticipated supply to meet ongoing requirements. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, short-term market purchases and owned production. Our portfolio approach to natural gas supply is intended to enable us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in significant natural gas producing regions in the United States, primarily the Rocky Mountains (Colorado), Montana, and Alberta, Canada.
Owned Production and Storage - Since 2010, we have acquired gas production and gathering system assets as a part of an overall strategy to provide rate stability and customer value: as we own these assets, which are regulated, our customers are protected from potential price spikes in the market. As of December 31, 2020, these owned reserves totaled approximately 43.1 Bcf and are estimated to provide approximately 3.5 Bcf in 2021, or about 16 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 48,000 customers in 62 South Dakota communities and approximately 42,700 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 end-user account. We delivered approximately 27.5 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 2020.
Miles of Natural Gas Transmission 55
Miles of Natural Gas Distribution 2,524
Our South Dakota natural gas supply requirements for the year ended December 31, 2020, were approximately 6.0 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, 2020, were approximately 4.3 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, fifteen of our Montana franchises are scheduled to reach the end of their fixed term, which account for approximately 83,000 or 41 percent of our Montana natural gas customers. Five of our South Dakota franchises and one franchise in Nebraska, which account for approximately 30,500 or 34 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.
REGULATION
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, 2020:
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 $2,500.9 6.92% 9.65% 49.38%
Montana - Colstrip Unit 4 April 2019 304.0 272.4 8.25% 10.00% 50%
Montana natural gas delivery and production (2) September 2017 430.2 516.1 6.96% 9.55% 46.79%
Total Montana $2,764.3 $3,289.4
South Dakota electric (3) December 2015 $557.3 $626.8 7.24% n/a n/a
South Dakota natural gas (3) December 2011 65.9 77.4 7.80% n/a n/a
Total South Dakota $623.2 $704.2
Nebraska natural gas (3) December 2007 $24.3 $37.8 8.49% 10.40% n/a
$3,411.8 $4,031.4
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(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) incorporates sharing of a portion of the business risk or benefit associated with the cost of power purchased and fuel used to generate electricity. Customer prices may be adjusted annually to absorb a portion of the difference between base revenues and actual costs 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, 2021. 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 new Biden Administration has 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 Administration in its first few weeks include initiatives and directives intended to reduce greenhouse gas (GHG) emissions, address climate change issues and decarbonize the energy sector. In particular, these Executive Orders, among other things, establish climate considerations as key components of United States foreign policy and national security, establish a White House Office of Domestic Climate policy as well as a National Climate Task Force, call 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 direct 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. President Biden also announced the United States’ intent to rejoin the Paris Agreement.
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.
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 http://www.northwesternenergy.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments, 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
Our ability to achieve the objectives of our business strategy and serve our customers within our service territory depends on employing skilled professionals. 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, 2020, we had 1,530 employees. Of these, 1,225 employees were in Montana and 305 were in South Dakota or Nebraska. Of our Montana employees, 470, or 38 percent, were covered by seven collective bargaining agreements involving five unions. Due to COVID-19, the Company negotiated a one-year contract extension with a wage proposal for each of the seven Montana agreements. Six of the contract extensions will expire in 2021 with one extending to 2022. Of our South Dakota and Nebraska employees, 172, or 56 percent, are covered by a collective bargaining agreement renegotiated in 2019 that expires at the end of 2021. We consider our relations with employees to be good.
Talent Management
Attraction and retention of skilled professionals is key to our ongoing success. We invest significant resources in maintaining a culture that supports the ongoing development of our workforce. This includes an integrated learning and performance management system that 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 are a founding partner of the Highlands College of Montana Technological University Pre-apprentice Lineman Program. 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 2020 and 2019, the compensation for our CEO was approximately 25 and 27 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 2020, approximately 78 percent of the
targeted compensation of our CEO and about 60 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’s 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
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 may 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 24 percent of our employees in management positions are female, including three of our eight executive officers. Additionally, 2020 Women on Boards has recognized our gender diversity, with four females among our ten 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 year ended December 31, 2020, we realized our best safety year on record and reduced our recordable incident rate from 1.86 to 1.36 and lost time incident rate from 0.58 to 0.39 on a company wide basis as compared to the year ended December 31, 2019. Our five-year average safety record for the year ended December 31, 2020 was better than our industry peer group's five-year average.
COVID-19
In response to the COVID-19 pandemic we have implemented a number of protocols to help slow the spread of the virus to protect both our employees and our communities, and to continue to provide our customers with reliable, safe energy service. We have restricted access to all our critical facilities to essential employees only, and employees in these facilities have been split into segregated work groups to avoid physical contact. We have implemented a responsible re-entry plan that determines when employees can return to company facilities in a phased approach based on internal and external triggers to provide for the safety and health of our employees. Masks and social distancing are required at all times when entering company facilities and in common spaces. Field personnel are still performing operations and maintenance work, but extra social distancing protocols have been implemented. Field personnel will not enter a customer home or business except in very limited circumstances. In an instance where an employee does need to enter a home or business, extra precautions have been implemented.
We have continuously executed upon our commitment to provide safe reliable energy service, while also managing the spread of the virus and promoting health and safety. During this time we did not lay off or furlough any employees. We implemented and continue to provide paid leave programs supplemental to our paid-time off and leave benefits, which compensate employees when unable to work due to quarantine and illness.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Executive Officer Current Title and Prior Employment Age on Feb. 5, 2021
Robert C. Rowe President, Chief Executive Officer and Director since August 2008. Previously, Mr. Rowe was a co-founder and senior partner at Balhoff, Rowe & Williams, LLC, a specialized national professional services firm providing financial and regulatory advice to clients in the telecommunications and energy industries (January 2005-August, 2008); and served as Chairman and Commissioner of the Montana Public Service Commission (1993-2004). 65
Brian B. Bird (1) Chief Financial Officer since December 2003. Prior to joining NorthWestern, Mr. Bird was Chief Financial Officer and Principal of Insight Energy, Inc., a Chicago-based independent power generation development company (2002-2003). Previously, Mr. Bird was Vice President and Treasurer of NRG Energy, Inc., in Minneapolis, MN (1997-2002). Mr. Bird serves on the board of directors of a NorthWestern subsidiary. 58
Michael R. Cashell Vice President - Transmission since May 2011; formerly Chief Transmission Officer since November 2007; formerly Director - Transmission Marketing and Business Planning since 2003. Mr. Cashell serves on the board of directors of a NorthWestern subsidiary. 58
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. Previously, Ms. Grahame was a partner in the law firm of Dorsey & Whitney, LLP, where she co-chaired its Telecommunications practice (1999-2010). 65
John D. Hines Vice President - Supply and Montana Government Affairs since January 2018; formerly Vice President - Supply since May 2011; formerly Chief Energy Supply Officer since January 2008; formerly Director - Energy Supply Planning since 2006. Previously, Mr. Hines served as the Montana representative to the Northwest Power and Conservation Council (2003-2006). 62
Crystal D. Lail (1) Vice President and Chief Accounting Officer since April 2020, formerly Vice President and Controller since October 2015; and prior to that successive finance roles since joining NorthWestern in January 2003. 42
Curtis T. Pohl Vice President - Distribution since May 2011; formerly Vice President-Retail Operations since September 2005; Vice President-Distribution Operations since August 2003; formerly Vice President-South Dakota/Nebraska Operations since June 2002; formerly Vice President-Engineering and Construction since June 1999. Mr. Pohl serves on the board of directors of a NorthWestern subsidiary. 56
Bobbi L. Schroeppel Vice President, Customer Care, Communications and Human Resources since May 2009, formerly Vice President-Customer Care and Communications since September 2005; formerly Vice President-Customer Care since June 2002; formerly Director-Staff Activities and Corporate Strategy since August 2001; formerly Director-Corporate Strategy since June 2000. 52
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(1) Effective February 15, 2021, Brian B. Bird will no longer serve as Chief Financial Officer and will become President and Chief Operating Officer. At the same time, Crystal Lail will no longer serve as Vice President and Chief Accounting Officer and will become Vice President and Chief Financial Officer.
Officers are elected annually by, and hold office at the pleasure of the Board of Directors (Board), and do not serve a “term of office” as such.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities.
COVID-19 Risks
The COVID-19 pandemic and resulting adverse economic conditions have had, and we expect are likely to continue to have, a negative impact on our business, financial condition and results of operations.
The COVID-19 pandemic has had widespread impacts on people, economies, businesses and financial markets. Since March 2020, the pandemic has negatively impacted our operations, liquidity, financial condition and results of operations. The continuing 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. In addition, we cannot predict the ongoing and ultimate impact that the COVID-19 pandemic will have on our customers, suppliers, vendors, and other business partners, and each of their financial conditions; however, any material effect on these parties could adversely impact us.
Economic - The COVID-19 pandemic continues to be an evolving situation with an extended disruption of economic activity. While we cannot predict the ultimate impact of the COVID-19 pandemic, our financial results in 2020 were impacted by lower sales volumes, an increase in reserves for uncollectible accounts and an increase in interest expense. There can be no assurance that any decrease in revenues resulting from the COVID-19 pandemic will return to previous levels in the future. Decreases in per capita income and level of disposable income, increased unemployment or a decline in consumer confidence have had and could continue to have an adverse effect on our business. Certain of our customers have been, and may in the future be, required to close down or operate at a lower capacity, which has adversely impacted our business in the short term and may in the future materially adversely affect our business, financial condition and results of operations. In addition, we continue to monitor the capital markets. If conditions deteriorate and disrupt the capital markets and we need to access capital, there can be no assurance that we will be able to obtain such financing on commercially reasonable terms or at all.
Operational - While the COVID-19 pandemic has not caused material disruptions to our operations, it 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. In addition, remote work arrangements introduce operational risk, including but not limited to cybersecurity risks.
For similar reasons, the COVID-19 pandemic may similarly adversely impact our suppliers and their manufacturers. Depending on the extent and duration of COVID-19 pandemic's effects on our business and operations and the business and operations of our suppliers, our costs could increase, including our costs to address the health and safety of personnel, and our ability to obtain certain supplies or services.
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. 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.
Any such workforce implications, supply chain disruptions, and / or limitations or closures may 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.
The impacts of the COVID-19 pandemic may also have the effect of heightening risks discussed below, any of which could have a material effect on us.
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, 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 regulatory commission will approve our request to recover costs. We have recently received, and may in the future receive, unfavorable rulings from the MPSC. During the fourth quarter of 2020, the MPSC disallowed approximately $9.4 million of power costs for the July 1, 2018 to June 30, 2019 time period related to an intermittent outage at Colstrip Units 3 and 4 and application of a change in state laws addressing cost sharing of power costs. 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. In a continued low interest rate environment there has been pressure pushing down return on equity. There also 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 always result in rates that will produce 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 and issues such as cost allocation methodologies. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Adverse regulatory rulings could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on our common stock.
We are subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.
We are subject to regulations under a wide variety of U.S. federal and state regulations and policies. Regulation affects almost every aspect of our business. Changes to federal and state laws and regulations are continuous and ongoing and the new Biden Administration, the new U.S. Congress, and new 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 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 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 new Biden Administration’s agenda represents a significant shift in environmental and energy policy, focusing on reducing GHG emissions and climate change issues. This new direction is reflected in several Executive Orders that President Biden issued in January 2021. Together, these orders reflect climate change issues and GHG reductions as central areas of focus for domestic and international regulations, orders and policies.
These initiatives will likely lead to new and revised environmental laws and regulations. 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.
In addition, 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 will develop an alternative plan for reducing GHG emissions from coal-fired plants. As GHG 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 our Company-wide electric supply portfolio is over 65 percent carbon-free, it does include coal-fired 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 an operating agreement among them, the Ownership and Operation Agreement. Costs of facilities in common with all four units historically were 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 expect to 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 shut-down 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. On July 20, 2020, one of those owners filed a Settlement Stipulation with the Washington Utilities and Transportation Commission, agreeing to a depreciable life of Unit 4 through 2023. As a result of the Washington legislation, four of the six joint owners of Units 3 and 4 have requested the operator prepare a 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. While operations continue, differing viewpoints on closure dates has delayed approval of the 2021 operating budget. This impasse may lead to an arbitration among the joint owners, under the terms of the Ownership and Operation Agreement. The request to prepare budgets reflecting closure of the units also implicates the issue of whether Units 3 and 4 can be closed without each co-owner’s consent. While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the Ownership and Operation Agreement.
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 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 negative and material effect on our 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 identified needs set forth in our supply plans for resource procurement. The requirement to purchase supply 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 could 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 through our PCCAM or otherwise, those increased costs may negatively affect our liquidity, results of operations and financial condition.
In addition, requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs that are inconsistent with resource plans developed based on a lowest cost and least risk basis while placing upward pressure on overall customer bills. This may impact our investment plans and financial condition. Finally, the requirement to procure power from these QF sources may impact our transmission system and require additional transmission facilities to be developed in order to integrate these resources, which also can impact overall customer bills.
Operational Risks
Our electric and natural gas operations involve numerous activities that may result in accidents, fires, system outages and other operating risks and costs that are unique to our industry.
Inherent in our electric transmission and distribution and natural gas transportation 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. 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. 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.
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 and intentional acts that may cause our lines to fail. In addition, tree mortality rates have increased resulting in hazard trees located inside or outside our lines’ rights of way. Hazard trees are those trees that are structurally unsound and could fall into our lines if the trees failed. We are facing challenges to address these trees. The risk of fires is exacerbated in forested areas where there has been a significant increase in the quantity of standing dead and dying timber, primarily as a result of beetle infestation, increasing the risk that such trees may fall from either inside or outside our right-of-way into a power line igniting a fire. Fires alleged to have been caused by our system could expose us to significant penalties and / or damage claims on theories such as strict liability, negligence, gross negligence, trespass, inverse condemnation, and others.
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.
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. 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. One such third party vendor is SolarWinds Corporation (SolarWinds), a provider of IT monitoring and management products and services, including its Orion Platform products, which are used by over 300,000 businesses including ours. SolarWinds experienced a cyberattack that appears likely to be the result of a supply chain attack by an outside nation state. Since being made aware of the breach 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. To date there are no signs we have been victimized by this attack. 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 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 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 creating high energy demand on our own and/or other systems 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. In Montana, we have significant projected generation
capacity deficits and negative reserve margins. Based on current estimates, we forecast that our portfolio will be 725 MW short by 2025, considering expiring contracts and a modest increase in customer demand. Approximately 46 percent of our peak electric requirements are 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 partiesthe transmission systems owned by us or ies. This could result in an inability to physically deliver electricity to our customers. In addition, the suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us.
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.
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 development of the Western Energy Imbalance Market and our expected participation, 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.
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.
Our business strategy also 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.
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. 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, mortality rates, 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.

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

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

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

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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, which is traded under the ticker symbol NWE, is listed on the NASDAQ Stock Market. As of February 5, 2021, there were approximately 1,166 common stockholders of record.

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2020 compared to the year ended December 31, 2019, 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, 2019 compared with the year ended December 31, 2018, 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, 2019.
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, Gross 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 Gross Margin as Revenues less Cost of sales as presented in our Consolidated Statements of Income. The following discussion includes a reconciliation of Gross Margin to Operating Revenues, the most directly comparable GAAP measure.
Management believes that Gross 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, Gross 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 Gross 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 743,000 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 2020, 2019 and 2018. 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. 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 distribution and substations that enables the use of changing technology.
•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 2020, approximately 65 percent of our customers' retail electric needs originated from carbon-free resources, which is more than two times better than the total U.S electric power industry. As part of our continued efforts in environmental stewardship, we recently established our Carbon Reduction Vision for Montana, committing to reduce the carbon intensity of our Montana electric energy portfolio 90 percent by 2045, as compared with our 2010 carbon intensity baseline. Over the last decade, we have already reduced the carbon intensity of our energy generation in Montana by more than 50 percent. Our vision for the future builds on the progress we have already made. Already, the foundation of our energy generation is our hydroelectric system, 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 is not a significant portion of our energy mix today, we expect it to 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 2020 COMPARED TO OUR 2019 RESULTS
Year Ended December 31, 2020 vs. 2019
Income Before Income Taxes Income Tax Benefit (Expense) Net Income
(in millions)
Year ended December 31, 2019 $ 182.2 $ 19.9 $ 202.1
Items increasing (decreasing) net income:
Lower electric retail volumes and demand (11.0) 2.8 (8.2)
Lower Montana natural gas volumes (10.6) 2.7 (7.9)
Disallowance of prior period supply costs (9.4) 2.4 (7.0)
Higher depreciation and depletion (6.7) 1.7 (5.0)
Higher Electric QF liability adjustment (3.3) 0.8 (2.5)
Lower Montana electric supply cost recovery (2.7) 0.7 (2.0)
Lower Montana electric transmission revenue (2.7) 0.7 (2.0)
Prior year recognition of unrecognized tax benefit - (22.8) (22.8)
Lower operating, general, and administrative expenses 22.7 (5.7) 17.0
Other (14.3) 7.8 (6.5)
Year ended December 31, 2020 $ 144.2 $ 11.0 $ 155.2
Change in Net Income $ (46.9)
Consolidated net income in 2020 was $155.2 million as compared with $202.1 million in 2019. This decrease was primarily due to an income tax benefit in 2019, lower gross margin in 2020 due primarily to warmer winter weather and impacts of the COVID-19 pandemic, a disallowance of prior period supply costs, lower supply cost recovery, and higher depreciation and depletion expense, offset in part by a decrease in operating, general and administrative expenses.
SIGNIFICANT TRENDS AND REGULATION
COVID-19 Pandemic
We are one of many companies providing essential services during the national emergency related to the COVID-19 pandemic. Our level of service to our 743,000 customers remains uninterrupted. We implemented a comprehensive set of actions to help our customers, communities, and employees, while maintaining our commitments to provide reliable service and to continue to monitor and adapt our financial business plan for the evolving COVID-19 pandemic challenges. In March, we voluntarily informed both our retail customers and state regulators that disconnections for non-payment would be temporarily suspended, and we have provided an incremental $400,000 in charitable contributions and aid to assist the communities we serve. Our CEO made an official declaration of emergency in accordance with our continuity of operations plan and emergency standard operating procedures, implementing an incident command structure that remains in effect. We have taken extra
precautions for our employees who work in the field and for employees who continue to work in our facilities. This includes implementation of work from home policies, social-distancing protocols, face-covering directives, and travel restrictions where appropriate. Currently, we do not anticipate any employee layoffs and are continuing to hire for critical positions to maintain our high level of reliability and customer service. We continue to implement strong physical and cyber-security measures to enable our systems to continue to serve our operational needs with a remote workforce and to keep our company running to provide high quality service to our customers. In August, we advised customers that we would resume the disconnection process for customers whose accounts are in arrears. However, beginning in November our normal winter disconnection procedures were in effect.
2020 Impact - The COVID-19 pandemic has impacted our financial results with a reduction in our commercial and industrial sales volumes, offset in part by an increase in usage by residential customers. We also experienced an increase in certain operating expenses including an increase in uncollectible accounts and interest expense offset in part by lower operating expenses as detailed below. COVID-19 continues to be an evolving situation and we expect to continue to experience impacts to our financial results in 2021.
Estimate of COVID-19 Impacts
Twelve Months Ended December 31, 2020
Low High
(in millions)
Gross Margin (1)
$ (8.0) $ (11.0)
Operating expenses
Medical, labor, and travel & training (5.5) (5.5)
Uncollectible Accounts 3.0 3.0
Total Operating Expense (2.5) (2.5)
Operating Loss (5.5) (8.5)
Interest expense (0.7) (0.7)
Pretax Loss (6.2) (9.2)
Income tax benefit (2)
1.6 2.3
Net Loss $ (4.6) $ (6.9)
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
(2) Income tax benefit calculated using a 25.3% effective tax rate
We submitted accounting order requests in Montana and South Dakota to allow for the deferral of uncollectible accounts expense in excess of amounts currently recovered from customers and to determine ratemaking treatment in a future proceeding.
•The SDPUC issued an order in August 2020, authorizing deferral of costs for possible recovery through future rates. As of December 31, 2020 we have deferred $0.2 million of uncollectible accounts expense into a regulatory asset in South Dakota.
•The MPSC issued an order in November 2020, declining to authorize establishment of a regulatory asset for the deferral of the incremental bad debt expense.
We are working with customers who have been unable to pay during the COVID-19 pandemic, including offering extended payment arrangements. In each of our jurisdictions, we resumed disconnection procedures for non-payment during the third quarter of 2020, supporting our efforts to reduce past due customer balances. We are subject to certain annual winter disconnection procedures, which went into effect on November 1st and will remain in effect through March 31st.
The continued progression of and global response to the COVID-19 pandemic increases the risk of delays in construction activities and equipment deliveries related to our capital projects, including potential delays in obtaining permits from government agencies, resulting in a potential deferral of capital expenditures. While we have not experienced significant supply
chain challenges to date and were able to execute on over $400 million in planned capital investment projects during 2020, we continue to closely manage and monitor developments in our supply chain.
The ongoing impacts of the COVID-19 pandemic remain uncertain. Continued slowdown in the United States’ economic growth, demand for commodities and/or material changes in governmental policy may continue to result in lower economic growth with lower demand for electricity and natural gas, as well as negatively affect the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations. These impacts could have a material adverse effect on our results of operations, financial condition and prospects.
During the second quarter of 2020, as precautionary measures to increase our cash position and preserve financial flexibility in light of uncertainty in the markets, we accessed the capital markets in two transactions. For further discussion of these transactions, see the Liquidity and Capital Resources discussion.
2021 Impact - We expect to continue to experience a reduction in our commercial and industrial sales volumes, offset in part by an increase in usage by residential customers through the second quarter of 2021.
Electric Resource Planning - Montana
We are currently 630 MW short of our peak needs and we cover the shortfall through market purchases. Absent resource additions, we forecast that our portfolio will be 725 MW short by 2025, considering expiring contracts and a modest increase in customer demand. We issued an all-source competitive solicitation request in February 2020 for up to 280 MWs of peaking and flexible capacity to be available for commercial operation in early 2023 (the February 2020 request for proposal (RFP)). Further, we expect additional all-source competitive solicitation requests will be forthcoming, beginning in late 2021 or 2022.
Initial bids for the February 2020 RFP were received in July 2020. Bid submissions were evaluated by an independent party. We are reviewing analyses from the independent administrator and expect to announce the selection of multiple projects during the first quarter of 2021. Bids were submitted on our behalf for generating facilities providing long-duration flexible capacity in excess of 200 MWs. We anticipate that at least one of our projects will be among those selected resulting in owned capacity generation investment in excess of $200 million over the next 3 years, assuming we receive approval from the MPSC.
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 discussed above identify portfolio resource requirements including investments resulting from a completed competitive solicitation process in South Dakota. The capital projections above include approximately $40 million related to completion of the 60 MW flexible natural gas plant near Huron, South Dakota expected to be in service by late 2021 and approximately $60 million for a 30-40 MW flexible natural gas plant near Aberdeen, South Dakota, which is expected to be in service in early 2024.
See discussion of the "February 2020 RFP" under Significant Trends and Regulation above for details on our current Montana all-source competitive solicitation process. Potential generation capital related to this need is not included in the projections above.
Natural Gas Production Assets - We own natural gas production and gathering system assets in Montana as a part of an overall strategy to provide rate stability and customer value through the addition of regulated assets that are not subject to market forces. Our estimated capital expenditure requirements above do not include estimates for incremental natural gas reserve acquisitions, or other investment opportunities that may arise.
Distribution and Transmission Modernization and Maintenance - The primary goals of our infrastructure investment 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. In 2021 through 2024, we expect to install automated metering infrastructure in Montana at a cost ranging from approximately $100 million to $110 million, which is reflected in the five year capital forecast above.
Financing - We anticipate financing our ongoing maintenance and capital programs with a combination of cash flows from operations, first mortgage bonds and equity issuances. We anticipate initiating a 3-year $200 million At-the-Market (ATM) offering during 2021 and begin issuing equity under that program. The ATM issuances will be sized to maintain and protect our current credit ratings. Capital investment in response to our Montana electric supply resource planning would be incremental to these amounts. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
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 gross 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.
OVERALL CONSOLIDATED RESULTS
Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
Consolidated net income in 2020 was $155.2 million as compared with $202.1 million in 2019, a decrease of $46.9 million. As described in more detail below, this decrease was primarily due to an income tax benefit in 2019, lower gross margin in 2020 due to warmer winter weather, impacts of the COVID-19 pandemic, disallowed electric supply costs and higher depreciation expense, offset in part by a decrease in operating, general and administrative expenses.
Consolidated operating revenues in 2020 were $1,198.7 million as compared with $1,257.9 million, a decrease of $59.2 million. This decrease was primarily due to lower volumes from warmer winter weather and impacts of the COVID-19 pandemic, partly offset by customer growth. Consolidated gross margin in 2020 was $892.5 million as compared with $939.9 million in 2019, a decrease of $47.4 million, or 5.0 percent.
Electric Natural Gas Total
2020 2019 2020 2019 2020 2019
(in millions)
Reconciliation of gross margin to operating revenue:
Operating Revenues $ 940.8 $ 981.2 $ 257.9 $ 276.7 $ 1,198.7 $ 1,257.9
Cost of Sales 236.6 239.6 69.6 78.4 306.2 318.0
Gross Margin(1)
$ 704.2 $ 741.6 $ 188.3 $ 198.3 $ 892.5 $ 939.9
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Year Ended December 31,
2020 2019 Change % Change
(in millions)
Gross Margin
Electric $ 704.2 $ 741.6 $ (37.4) (5.0) %
Natural Gas 188.3 198.3 (10.0) (5.0)
Total Gross Margin(1)
$ 892.5 $ 939.9 $ (47.4) (5.0) %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Primary components of the change in gross margin include the following (in millions):
Gross Margin
2020 vs. 2019
Gross Margin Items Impacting Net Income
Electric retail volumes and demand $ (11.0)
Natural gas retail volumes (10.6)
Disallowance of prior period supply costs (9.4)
Lower electric QF liability adjustment (3.3)
Montana electric supply cost recovery (2.7)
Electric transmission (2.7)
Montana natural gas production rates (1.2)
Montana electric retail rates 1.6
Other (9.2)
Change in Gross Margin Impacting Net Income (48.5)
Gross Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense 6.3
Production tax credits reducing revenue, offset in income tax benefit (5.0)
Operating expenses recovered in revenue, offset in operating expense (0.1)
Gas production taxes recovered in revenue, offset in property and other taxes (0.1)
Change in Items Offset Within Net Income 1.1
Decrease in Consolidated Gross Margin(1)
$ (47.4)
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated gross margin decreased $47.4 million, including a $48.5 million decrease from items impacting net income and a $1.1 million increase from items offset within net income.
The change in consolidated gross margin for items impacting net income includes the following:
•A decrease in electric retail volumes due to warmer winter weather in Montana and South Dakota and lower industrial demand unrelated to the COVID-19 pandemic, partly offset by customer growth and warmer summer weather. In addition, impacts of the COVID-19 pandemic drove a decline of approximately $7 - $9 million, as a result of lower commercial and industrial demand, partly offset by higher residential usage;
•A decrease in gas volumes due to warmer winter weather, offset in part by customer growth. In addition, impacts of the COVID-19 pandemic drove a decline of approximately of $1-$2 million, as a result of lower customer usage;
•A MPSC disallowance of $5.6 million of replacement power costs incurred during a 2018 intermittent outage at our Colstrip coal-fired generating facility and $3.8 million of costs related to the prorated application of a change in state law that eliminated the deadband and QF cost sharing component of our PCCAM;
•A less favorable adjustment of our electric QF liability (unrecoverable costs associated with PURPA contracts as a part of a 2002 stipulation with the MPSC and other parties) as compared with the same period in 2019 due to the combination of:
•A net $1.1 million lower favorable adjustment due to actual price escalation, which was less than estimated ($2.2 million in the current period compared with $3.3 million in the prior period); and
•Higher costs of approximately $2.2 million, due to a $0.9 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $3.1 million reduction in costs in the prior period.
•The inclusion in the prior period of lower Montana electric supply costs as a result of changes in the associated statute, offset in part by lower supply costs in 2020;
•Lower demand to transmit energy across our transmission lines due to market conditions and pricing, including the closure of Colstrip Units 1 and 2;
•A reduction of rates due to the step down of our Montana gas production assets; and
•An increase in Montana electric rates.
Year Ended December 31,
2020 2019 Change % Change
(in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 297.1 $ 318.2 $ (21.1) (6.6) %
Property and other taxes 179.5 171.9 7.6 4.4
Depreciation and depletion 179.6 172.9 6.7 3.9
$ 656.2 $ 663.0 $ (6.8) (1.0) %
Consolidated operating, general and administrative expenses were $297.1 million in 2020, as compared with $318.2 million in 2019. Primary components of the change include the following (in millions):
Operating, General & Administrative Expenses
2020 vs. 2019
Operating, General & Administrative Expenses Impacting Net Income
Employee benefits $ (10.1)
Labor (4.1)
Hazard trees (3.2)
Travel and training (3.0)
Environmental costs (1.2)
Generation maintenance (0.9)
Uncollectible Accounts 3.0
Other (3.2)
Change in Items Impacting Net Income (22.7)
Operating, General & Administrative Expenses Offset Within Net Income
Pension and other postretirement benefits, offset in other income 7.0
Operating expenses recovered in trackers, offset in revenue (0.1)
Non-employee directors deferred compensation, offset in other income (5.3)
Change in Items Offset Within Net Income 1.6
Decrease in Operating, General & Administrative Expenses $ (21.1)
Consolidated operating, general and administrative expense decreased $21.1 million, including a $22.7 million decrease from items impacting net income and a $1.6 million increase from items offset within net income.
The change in consolidated operating, general and administrative expenses for items impacting net income includes the following:
•Lower employee benefit costs primarily due to a decrease in employee incentive compensation expense and a slight decrease in medical costs due to the COVID-19 pandemic;
•Decreased labor costs including approximately $1.3 million of in-home customer work limited due to the COVID-19 pandemic and more time being spent by employees on capital projects than maintenance projects (which are expensed);
•Lower hazard tree line clearance costs consistent with the plan discussed above. Costs in 2020 reflect a more normal level, which is lower than 2019. We expect to continue the program over the next several years with anticipated 2021 costs ranging from approximately $3 million to $4 million, with cumulative operating expense for the program exceeding $20 million;
•A reduction in employee travel and training costs due to the impacts of the COVID-19 pandemic;
•Lower environmental costs, primarily at our manufactured gas plant sites;
•Lower maintenance at our electric generation facilities; and
•Increased uncollectible accounts. In March 2020, we voluntarily suspended service disconnections for non-payment, to help customers who may be financially impacted by the COVID-19 pandemic. We resumed standard disconnection processes in all of our operating jurisdictions in the third quarter. As a result of the South Dakota accounting order, we deferred approximately $0.2 million of uncollectible accounts expense during 2020.
Property and other taxes were $179.5 million in 2020, as compared with $171.9 million in 2019. This increase was primarily due to plant additions and higher estimated property valuations in Montana.
Depreciation and depletion expense was $179.6 million in 2020, as compared with $172.9 million in 2019. This increase was primarily due to plant additions.
Consolidated operating income in 2020 was $236.2 million as compared with $276.9 million in 2019. This decrease was primarily due to lower gross margin, higher property and other taxes, and higher depreciation expense, partly offset by lower operating expenses.
Consolidated interest expense in 2020 was $96.8 million, as compared with $95.1 million in 2019, reflecting borrowings issued as a precautionary measure in order to increase our cash position and preserve financial flexibility in light of the uncertainty in the markets, partially offset by lower interest on our revolving credit facilities. See "Liquidity and Capital Resources" for additional information regarding our financing activities.
Consolidated other income in 2020 was $4.9 million, as compared with $0.4 million in 2019. This increase was primarily due to a $7.0 million decrease in other pension expense that was partially offset by a $5.3 million decrease in the value of deferred shares held in trust for non-employee directors deferred compensation (both of which are offset in operating, general, and administrative expense with no impact to net income), and higher capitalization of AFUDC.
Consolidated income tax benefit in 2020 was $11.0 million, as compared with $19.9 million in 2019. The income tax benefit for 2019 reflects the recognition of approximately $22.8 million of unrecognized tax benefits, including approximately $2.7 million of accrued interest and penalties, due to the lapse of statutes of limitation in the second quarter of 2019. Our effective tax rate for the twelve months ended December 31, 2020 was (7.6) percent as compared with (10.9) percent for the same period of 2019. We currently estimate our effective tax rate will range between (2.5) percent to 2.5 percent in 2021. The effective tax rate is expected to gradually increase and approach 10 percent to 12 percent by 2025.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
Year Ended December 31,
2020 2019
Income Before Income Taxes $ 144.2 $ 182.2
Income tax calculated at federal statutory rate 30.3 21.0 % 38.3 21.0 %
Permanent or flow through adjustments:
State income, net of federal provisions (1.5) (1.1) 1.2 0.7
Flow-through repairs deductions (23.8) (16.5) (19.7) (10.8)
Production tax credits (13.1) (9.1) (11.5) (6.3)
Amortization of excess deferred income taxes (DIT) (1.0) (0.7) (1.7) (0.9)
Recognition of unrecognized tax benefit - - (22.8) (12.5)
Impact of Tax Cuts and Jobs Act - - (0.2) (0.1)
Plant and depreciation of flow through items 0.1 0.1 (4.0) (2.2)
Prior year permanent return to accrual adjustments (1.7) (1.2) 0.6 0.3
Other, net (0.3) (0.1) (0.1) (0.1)
(41.3) (28.6) (58.2) (31.9)
Income Tax Benefit $ (11.0) (7.6) % $ (19.9) (10.9) %
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 cost of sales and therefore has minimal impact on gross margin. The amortization of these amounts are offset in retail revenue.
•Transmission: Reflects transmission revenues regulated by the FERC.
•Wholesale and other are largely gross margin neutral as they are offset by changes in cost of sales.
Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
Results
2020 2019 Change % Change
(in millions)
Retail revenue $ 895.4 $ 890.7 $ 4.7 0.5 %
Regulatory amortization (11.5) 30.2 (41.7) (138.1)
Total retail revenues 883.9 920.9 (37.0) (4.0)
Transmission 51.5 54.2 (2.7) (5.0)
Wholesale and Other 5.4 6.1 (0.7) (11.5)
Total Revenues 940.8 981.2 (40.4) (4.1)
Total Cost of Sales 236.6 239.6 (3.0) (1.3)
Gross Margin(1)
$ 704.2 $ 741.6 $ (37.4) (5.0) %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Revenues Megawatt Hours (MWH) Avg. Customer Counts
2020 2019 2020 2019 2020 2019
(in thousands)
Montana $ 320,792 $ 308,840 2,635 2,581 307,390 303,222
South Dakota 66,603 62,457 583 589 50,646 50,615
Residential 387,395 371,297 3,218 3,170 358,036 353,837
Montana 338,269 348,143 3,036 3,186 70,145 68,896
South Dakota 101,095 97,082 1,073 1,110 12,802 12,814
Commercial 439,364 445,225 4,109 4,296 82,947 81,710
Industrial 36,819 43,595 2,615 2,949 78 78
Other 31,833 30,595 173 165 6,333 6,219
Total Retail Electric $ 895,411 $ 890,712 10,115 10,580 447,394 441,844
Cooling Degree Days 2020 as compared with:
2020 2019 Historic Average 2019 Historic Average
Montana 398 370 405 8% warmer 2% colder
South Dakota 879 715 734 23% warmer 20% warmer
Heating Degree Days 2020 as compared with:
2020 2019 Historic Average 2019 Historic Average
Montana 7,304 8,515 7,605 14% warmer 4% warmer
South Dakota 7,445 8,478 7,702 12% warmer 3% warmer
The following summarizes the components of the changes in electric gross margin for the years ended December 31, 2020 and 2019 (in millions):
Gross Margin
2020 vs. 2019
Gross Margin Items Impacting Net Income
Retail volumes and demand $ (11.0)
Disallowance of prior period supply costs (9.4)
QF liability adjustment (3.3)
Montana supply cost recovery (2.7)
Transmission (2.7)
Montana retail rates 1.6
Other (10.5)
Change in Gross Margin Impacting Net Income (38.0)
Gross Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense 5.8
Production tax credits reducing revenue, offset in income tax benefit (5.0)
Operating expenses recovered in revenue, offset in operating expense (0.2)
Change in Items Offset Within Net Income 0.6
Decrease in Gross Margin(1) $ (37.4)
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin decreased $37.4 million, including a $38.0 million decrease from items impacting net income and a $0.6 million increase from items offset within net income.
The change in gross margin for items impacting net income includes the following:
•A decrease in electric retail volumes due to warmer winter weather in Montana and South Dakota and lower industrial demand unrelated to the COVID-19 pandemic, partly offset by customer growth and warmer summer weather. In addition, impacts of the COVID-19 pandemic drove a decline of approximately $7 - $9 million, as a result of lower commercial and industrial demand, partly offset by higher residential usage;
•A MPSC disallowance of $5.6 million of replacement power costs incurred during a 2018 intermittent outage at our Colstrip coal-fired generating facility and $3.8 million of costs related to the prorated application of a change in state law that eliminated the deadband and QF cost sharing component of our PCCAM;
•A less favorable adjustment of our electric QF liability (unrecoverable costs associated with PURPA contracts as a part of a 2002 stipulation with the MPSC and other parties) as compared with the same period in 2019 due to the combination of:
•A net $1.1 million lower favorable adjustment due to actual price escalation, which was less than estimated ($2.2 million in the current period compared with $3.3 million in the prior period); and
•Higher costs of approximately $2.2 million, due to a $0.9 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $3.1 million reduction in costs in the prior period.
•The inclusion in the prior period of lower Montana electric supply costs as a result of changes in the associated statute, offset in part by lower supply costs in 2020;
•Lower demand to transmit energy across our transmission lines due to market conditions and pricing, including the closure of Colstrip Units 1 and 2; and
•An increase in Montana electric rates.
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 gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
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 cost of sales and therefore has minimal impact on gross margin. The amortization of these amounts are offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
Results
2020 2019 Change % Change
(in millions)
Retail revenues $ 217.4 $ 242.9 $ (25.5) (10.5) %
Regulatory amortization 5.0 (2.1) 7.1 338.1
Total retail revenues 222.4 240.8 (18.4) (7.6)
Wholesale and other 35.5 35.9 (0.4) (1.1)
Total Revenues 257.9 276.7 (18.8) (6.8)
Total Cost of Sales 69.6 78.4 (8.8) (11.2)
Gross Margin(1)
$ 188.3 $ 198.3 $ (10.0) (5.0) %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Revenues Dekatherms Customer Counts
2020 2019 2020 2019 2020 2019
(in thousands)
Montana $ 103,457 $ 109,395 13,893 15,262 177,335 174,862
South Dakota 21,547 25,763 2,993 3,322 40,612 40,129
Nebraska 16,861 20,194 2,561 2,826 37,576 37,424
Residential 141,865 155,352 19,447 21,410 255,523 252,415
Montana 51,349 55,669 7,166 8,115 24,497 24,205
South Dakota 14,316 19,305 3,003 3,590 6,895 6,812
Nebraska 8,066 10,572 1,784 2,085 4,974 4,914
Commercial 73,731 85,546 11,953 13,790 36,366 35,931
Industrial 840 996 122 151 231 239
Other 923 1,012 152 168 153 164
Total Retail Gas $ 217,359 $ 242,906 31,674 35,519 292,273 288,749
Heating Degree Days 2020 as compared with:
2020 2019 Historic Average 2019 Historic Average
Montana 7,505 8,647 7,819 13% warmer 4% warmer
South Dakota 7,445 8,478 7,702 12% warmer 3% warmer
Nebraska 5,676 6,571 6,359 14% warmer 11% warmer
The following summarizes the components of the changes in natural gas gross margin for the years ended December 31, 2020 and 2019 (in millions):
Gross Margin
2020 vs. 2019
Gross Margin Items Impacting Net Income
Retail volumes $ (10.6)
Montana rates (1.2)
Other 1.3
Change in Gross Margin Impacting Net Income (10.5)
Gross Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense 0.5
Operating expenses recovered in revenue, offset in operating expense 0.1
Gas production taxes recovered in revenue, offset in property and other taxes (0.1)
Change in Items Offset Within Net Income 0.5
Decrease in Gross Margin(1) $ (10.0)
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin decreased $10.0 million, including a $10.5 million decrease from items impacting net income and a $0.5 million increase from items offset within net income.
The change in gross margin for items impacting net income includes the following:
•A decrease in gas volumes due to warmer winter weather, offset in part by customer growth. In addition, impacts of the COVID-19 pandemic drove a decline of approximately of $1-$2 million, as a result of lower customer usage; and
•A reduction of rates due to the step down of our Montana gas production assets.
Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
LIQUIDITY AND CAPITAL RESOURCES
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 and existing borrowing capacity should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). The amount of capital expenditures and dividends are subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. In addition, a material change in operations or available financing could impact our current liquidity and ability to fund capital resource requirements, and we may defer a portion of our planned capital expenditures as necessary.
We issue debt securities to refinance retiring maturities, reduce revolver debt, fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities we utilize available cash flow, debt capacity and equity issuances that allows us to maintain investment grade ratings. 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. Based upon our current capital expenditure expectations, we anticipate initiating a 3-year $200 million At-the-Market (ATM) offering during 2021 and begin issuing equity under that program to help fund such capital expenditures. Equity issuances will be sized to help maintain and protect current credit ratings. Capital investment in response to Montana electric supply resource planning would be incremental to these amounts. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
In response to the COVID-19 pandemic and as a precautionary measure in order to increase our cash position and preserve financial flexibility in light of uncertainty in the markets, in April 2020, we entered into a $100 million 364-Day Term Loan Credit Agreement (Term Loan) and borrowed the full amount under the Term Loan. We used the proceeds to pay down a portion of our outstanding revolving credit facility borrowings and for general corporate purposes. The Term Loan bears interest at variable rates tied to the Eurodollar rate plus a credit spread of 1.50 percent. All principal and unpaid interest under the Term Loan is due and payable on April 2, 2021. The Term Loan provides for prepayment of the principal and interest; however, amounts prepaid may not be reborrowed. The Term Loan requires us to maintain a consolidated indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding under the Term Loan.
In May 2020, we issued $100 million principal amount of Montana First Mortgage Bonds and $50 million principal amount of South Dakota First Mortgage Bonds, each at a fixed interest rate of 3.21 percent maturing on May 15, 2030. We issued these bonds in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota.
In September 2020, we entered into a new $425 million Credit Facility to replace our current facility. The Credit Facility increased the capacity from that of the prior facility by $25 million to $425 million and extended the maturity date to September 2, 2023 (from December 12, 2021), with 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 16 percent of the total availability.
Liquidity is 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 utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings.
As of December 31, 2020, our total net liquidity was approximately $233.8 million, including $5.8 million of cash and $228.0 million of revolving credit facility availability, and there were no letters of credit outstanding. The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2020 (in millions):
Amount outstanding at year end $ 222.0
Daily average amount outstanding $ 136.2
Maximum amount outstanding $ 305.0
Minimum amount outstanding $ -
As of February 5, 2021, our availability under our revolving credit facilities was approximately $231.0 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 5, 2021, 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 Stable
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.
Capital Requirements
Our capital expenditures program is subject to continuing review and modification. Actual utility construction expenditures may vary from estimates due to changes in electric and natural gas projected load growth, changing business operating conditions and other business factors. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt and equity issuances and future rate increases. Our estimated capital expenditures are discussed above in the "Significant Infrastructure Investments and Initiatives" section.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of December 31, 2020. See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements.
Total 2021 2022 2023 2024 2025 Thereafter
(in thousands)
Long-term debt (1) $ 2,328,637 $ - $ - $ 366,660 $ - $ 300,000 $ 1,661,977
Finance leases 17,439 2,668 2,875 3,098 3,337 3,596 1,865
Short-term borrowings 100,000 100,000 - - - - -
Estimated pension and other postretirement obligations (2) 63,705 12,912 12,905 12,905 12,492 12,491 N/A
Qualifying facilities liability (3) 551,957 77,722 79,572 81,646 79,384 65,041 168,592
Supply and capacity contracts (4) 2,282,132 211,455 190,873 195,085 173,225 170,069 1,341,425
Contractual interest payments on debt (5) 1,463,935 85,777 85,502 81,212 79,524 78,358 1,053,562
Total Commitments (6) $ 6,807,805 $ 490,534 $ 371,727 $ 740,606 $ 347,962 $ 629,555 $ 4,227,421
___________________________
(1)Represents cash payments for long-term debt and excludes $13.4 million of debt discounts and debt issuance costs, net.
(2)We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.
(3)Certain QFs require us to purchase minimum amounts of energy at prices ranging from $63 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $552.0 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $448.5 million.
(4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC, as further described in Footnote 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 1.39 percent on the outstanding balance through maturity of the facilities.
(6)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.
Other Obligations - As a co-owner of Colstrip, we have provided our proportionate share of surety bonds of approximately $22.8 million and $13.2 million as of December 31, 2020 and 2019, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out under the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality (MDEQ). As work is completed and costs are incurred under the AOC, the surety bonds will be reduced.
Factors Impacting our Liquidity
Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas and electric sales typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements. In addition, due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we typically under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult.
We recover the cost of our electric and natural gas supply through tracking mechanisms. The natural gas supply tracking mechanism in each of our jurisdictions, and electric supply tracking mechanism in South Dakota, are designed to provide stable recovery of supply costs, with a monthly adjustment to correct for any under or over collection. The Montana electric supply tracking mechanism implemented in 2018, the PCCAM, is designed for us to absorb risk through a sharing mechanism, with 90 percent of the variance above or below the established base revenues and actual costs collected from or refunded to customers. PCCAM electric supply rates are adjusted annually. In periods of significant fluctuation of loads and / or market prices, our cash flows are not adjusted until the following period, requiring us to absorb certain power cost increases before we are allowed to recover increases from customers.
As of December 31, 2020, we have under collected our supply costs recovered through tracking mechanisms by approximately $5.7 million. We under collected our supply costs by approximately $32.5 million as of December 31, 2019.
Cash Flows
The following table summarizes our consolidated cash flows for 2020 and 2019 (in millions):
Year Ended December 31,
2020 2019
Operating Activities
Net income $ 155.2 $ 202.1
Non-cash adjustments to net income 174.3 165.8
Changes in working capital 48.1 (53.0)
Other noncurrent assets and liabilities (25.5) (18.2)
Cash Provided by Operating Activities 352.1 296.7
Investing Activities
Property, plant and equipment additions (405.8) (316.0)
Investment in equity securities - (0.1)
Cash Used in Investing Activities (405.8) (316.1)
Financing Activities
Issuances of long-term debt 150.0 150.0
Issuances of short-term borrowings 100.0 -
Dividends on common stock (120.4) (115.1)
Line of credit repayments, net (67.0) (19.0)
Financing costs (2.6) (1.1)
Other (1.3) 1.4
Cash Provided by Financing Activities 58.7 16.2
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash $ 5.0 $ (3.2)
Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 12.1 $ 15.3
Cash, Cash Equivalents, and Restricted Cash, end of period $ 17.1 $ 12.1
Cash Flows Provided By Operating Activities
As of December 31, 2020, our cash, cash equivalents, and restricted cash were $17.1 million as compared with $12.1 million at December 31, 2019. Cash provided by operating activities totaled $352.1 million for the year ended December 31, 2020 as compared with $296.7 million during 2019. This increase in in operating cash flows is primarily due to improved collections of energy supply costs in the current period, as compared with higher procured supply costs and payments reducing cash flows in 2019, including credits to Montana customers of approximately $20.5 million and transmission generation interconnection refunds. These improvements were offset in part by reduced net income.
Cash Flows Used In Investing Activities
Cash used in investing activities totaled $405.8 million during the year ended December 31, 2020, as compared with $316.1 million during 2019. Plant additions during 2020 include maintenance additions of approximately $269.5 million, and capacity related capital expenditures of approximately $136.3 million. Plant additions during 2019 included maintenance additions of approximately $225.6 million, and capacity related capital expenditures of approximately $90.4 million.
Cash Flows Provided by Financing Activities
Cash provided by financing activities totaled $58.7 million during 2020 as compared with $16.2 million during 2019. During 2020, net cash provided by financing activities reflects the proceeds from the issuance of debt of $150.0 million and short-term borrowings of $100.0 million, offset in part by payments of dividends of $120.4 million and net repayments under our revolving lines of credit of $67.0 million. During 2019, net cash provided by financing activities reflects the proceeds from the issuance of debt of $150.0 million, offset in part by the payment of dividends of $115.1 million and net repayments under our revolving lines of credit of $19.0 million.
CRITICAL ACCOUNTING POLICIES AND 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 as critical to understanding our historical and future performance, as these polices affect the reported amounts of revenue and require the use of estimates, assumptions, and judgment to determine matters that are inherently uncertain.
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, 2020, our discount rate on the NorthWestern Corporation pension plan is 2.20 percent and on the NorthWestern Energy pension plan is 2.30 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 2021.
Cost Sensitivity
The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):
Actuarial Assumption Change in Assumption Impact on Pension Cost Impact on Projected
Benefit Obligation
Discount rate increase 0.25 % $ (2,033) $ (27,449)
Discount rate decrease (0.25) % 2,135 29,043
Rate of return on plan assets increase 0.25 % (1,492) N/A
Rate of return on plan assets decrease (0.25) % 1,492 N/A
Accounting Treatment
We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees.
Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. As of December 31, 2020, we had approximately $78.6 million of consolidated NOLs prior to consideration of unrecognized tax benefits to offset federal taxable income in future years. 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 $33.5 million as of December 31, 2020. 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.
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 $63 to $136 per MWH through June 2029. Our estimated gross contractual obligation is approximately $552.0 million through June 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $448.5 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.
NEW ACCOUNTING STANDARDS
See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.
Interest Rate Risk
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. We manage our interest rate risk by issuing primarily 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 and Term Loan. 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, 2020, we had approximately $222 million in borrowings under our revolving credit facilities. A 1.0 percent increase in interest rates would increase our annual interest expense by approximately $2.2 million.
In addition, in April 2020, we entered into the Term Loan and borrowed the full amount of $100 million, which bears interest at variable rates tied to the Eurodollar rate plus a credit spread of 1.50 percent. A 1.0 percent increase in interest rates under the Term Loan would increase interest expense by approximately $1.0 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.

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

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

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of December 31, 2020, 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, 2020. 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, 2020, our internal control over financial reporting was effective based on those criteria.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. Their report appears on page.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
Not applicable.
Part III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item with respect to directors and corporate governance will be set forth in NorthWestern Corporation's Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to our Executive Officers is included under "Information about our Executive Officers" in Item 1 of this report.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Information required by this Item will be set forth in NorthWestern Corporation's Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item will be set forth in NorthWestern Corporation's Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information concerning relationships and related transactions of the directors and officers of NorthWestern Corporation and director independence will be set forth in NorthWestern Corporation's Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning fees paid to the principal accountant for each of the last two years will be set forth in NorthWestern Corporation's Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.
Part IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
(1)Consolidated Financial Statements.
The following items are included in Part II, Item 8 of this annual report on Form 10-K:
CONSOLIDATED FINANCIAL STATEMENTS:
Page
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018
Consolidated Balance Sheets as of December 31, 2020 and 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
Fourth Quarter Unaudited Financial Data for the Years Ended December 31, 2020 and 2019
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).
4.5*
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) †
NorthWestern Energy 2019 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 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 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(o) †
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(p) †
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(q) †
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(r) †
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(s) †
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).
10.2(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).
10.2(d )
Term Loan Agreement, dated as of April 3, 2020, among NorthWestern Corporation, as Borrower, the several lenders from time to time parties thereto and U.S. BankNational Association, as administrative agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated April 6, 2020, 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 Brian B. Bird 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.