NORTHWESTERN ENERGY GROUP, INC. The following includes a discussion of our results of operations and cash flows for the year endedDecember 31, 2021 compared to the year endedDecember 31, 2020 , on both a consolidated basis and on a segment basis. For a discussion of our financial results and cash flows for the year endedDecember 31, 2020 compared with the year endedDecember 31, 2019 , see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year endedDecember 31, 2020 . This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 20 - Segment and Related Information, to the Consolidated Financial Statements.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a "non-GAAP financial measure." Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure. Management believes that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
OVERVIEW
NorthWestern Corporation , doing business asNorthWestern Energy , provides electricity and/or natural gas to approximately 753,600 customers inMontana , South Dakota Nebraska, andYellowstone National Park . As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2021, 2020 and 2019. Following is a discussion of our strategy and significant trends. We are working to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees. We seek to deliver value to our customers by providing high reliability and customer service, and an environmentally sustainable generation mix at an affordable price. The energy landscape is changing and we are committed to meeting the changing demands of our customers through continued investment to enhance reliability, security and safety, grid modernization, and integrate even more renewables, while meeting our growing demand for capacity. We are focused on delivering long-term shareholder value through: •Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
•Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
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--------------------------------------------------------------------------------•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.
We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
In 2021, approximately 56 percent of our retail needs originated from carbon-free resources, compared to approximately 40 percent for the totalU.S. electric power industry. InDecember 2019 , we announced a commitment to reduce the carbon intensity of our electric energy portfolio forMontana by 90 percent by 2045 as compared with our 2010 carbon intensity as a baseline. Since 2010, we have already reduced the carbon intensity of our energy generation inMontana by more than 50 percent. Further, as part of our continued efforts in environmental stewardship, we are developing a comprehensive company-wide carbon reduction plan we intend to announce during 2022. Our vision for the future builds on the progress we have made, including our hydroelectric system inMontana , which is 100 percent carbon free and is readily available capacity. For us, wind generation is a close second and continues to grow. While utility-scale solar energy has not been a significant portion of our energy mix today, we recently entered into two 80-megawatt solar power purchase agreements with two projects that are expected to begin delivering energy to ourMontana customers in 2022. We expect solar to further evolve along with advances in energy storage. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system. HOW WE PERFORMED IN 2021 COMPARED TO OUR 2020 RESULTS Consolidated net income in 2021 was$186.8 million as compared with$155.2 million in 2020. This increase was primarily due to higherMontana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period which was impacted by COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, and a favorable electric QF liability adjustment as compared with the prior period, partly offset by higher operating costs, non-recoverableMontana electric supply costs, and income tax expense. Year Ended December 31, 2021 vs. 2020 Income Before Income Tax Income Taxes Benefit (Expense) Net Income (in millions) Year ended December 31, 2020$ 144.2 $ 11.0$ 155.2 Items increasing (decreasing) net income: Higher Montana electric transmission revenue 25.1 (6.4) 18.7 Higher electric retail volumes 17.1 (4.3) 12.8 Prior period disallowance of supply costs 9.4 (2.4) 7.0 Electric QF liability adjustment 4.4 (1.1) 3.3 Higher Montana natural gas volumes 1.3 (0.3) 1.0 Higher income tax expense - (2.1) (2.1) Higher operating costs impacting net income (15.0) 3.8 (11.2) Higher depreciation and depletion (7.8) 2.0 (5.8) Higher non-recoverable Montana electric supply costs (5.3) 1.3 (4.0) Other 16.8 (4.9) 11.9 Year ended December 31, 2021$ 190.2 $ (3.4)$ 186.8 Change in Net Income$ 31.6 38
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SIGNIFICANT TRENDS AND REGULATION
Electric Resource Planning -
A shortage of critical 24/7 power capacity resources is jeopardizing reliability in theWestern United States . The accredited capacity of ourMontana portfolio of owned and long-term contracted electric generation resources covered approximately 70 percent of our 2021 peak electric requirements, with the remaining capacity shortfall, including reserve margin, covered through market purchases. A significant number of base-load generation facilities in the state and region have been retired or are scheduled to be retired in the next several years, which may impair grid and customer service reliability and increase volatility in market prices. Accordingly, our continued exposure to market purchases is an increasing risk to the availability and affordability of service for ourMontana customers. Future Integrated Resource Planning - We expect to submit an updated integrated resource plan by the end of 2022 or early 2023, followed by an all-source competitive solicitation request for capacity available in 2026. Due to the significant impact of our ownership in Colstrip Unit 4 to the capacity available in our portfolio, the outcome in the arbitration amongst the co-owners (See Note 18 - Commitments and Contingencies) may affect the timing of the submission of this plan. We remain concerned regarding an overall lack of capacity in the region and our resource adequacy deficit in the near term based on our projections of load by 2025, as a risk to customer reliability and affordability. As such, in addition to the 300 MWs (325 MWs nameplate) of accredited capacity additions resulting from the prior integrated resource plan as discussed below, we have reduced our exposure to our projected 725 MW shortfall of accredited capacity by 2025 through a combination of executing short and medium term cost-competitive agreements for 225 MWs of existing capacity in the region. We also expect to have an incremental 200 MWs of capacity resource additions in this period through a combination of new and renewed QF contracts and increases to the forecasted capacity accreditation of existing intermittent resources. This reduction of risk in the near term allows for clarity on theColstrip arbitration, further development in the western markets, and ongoing technological changes.
•A 5-year power purchase agreement for 100 MWs of firm capacity and energy products originating predominately from the British Columbia Hydro system starting inJanuary 2023 (Powerex Transaction); •A 20-year agreement to purchase capacity and ancillary services produced from the 50 MW Beartooth Battery project nearBillings, Montana , expected to be online by late 2023 or early 2024; and •Contracts for the construction of a nameplate capacity 175 MW natural gas-fired generation plant inMontana , at a cost of approximately$275 million , including AFUDC, which we will own. We initially filed an application with the MPSC for advanced approval to construct the 175 MW generation plant inMontana . We subsequently made the difficult decision to withdraw our application in order to meet the targeted commercial operation date of the plant. The upheaval in the construction market and, specifically, timely availability of critical components and escalating labor and construction costs due to the COVID-19 pandemic, necessitates the flexibility to expend capital and make commercial decisions in advance of the timeline established by the MPSC approval docket. The schedule is expected to allow the plant to serve ourMontana customers during the 2023-2024 winter season. OnOctober 21, 2021 , theMontana Environmental Information Center and theSierra Club filed a lawsuit in Montana State Court, against theMontana Department of Environmental Quality (MTDEQ) and us, alleging the environmental review of ourYellowstone County plant site project was unlawful. This lawsuit could delay the project if the Montana State Court were to require a full Environmental Impact Study regarding the project, set aside the air quality permit granted for theYellowstone County project, or determine that the underlying environmental statute violates the Montana Constitutional guarantee of a "clean and healthful environment." OnDecember 21, 2021 , we filed an application with the MPSC for preapproval of the Beartooth Battery agreement as a new capacity resource. This agreement is contingent upon MPSC approval of our application. The MPSC has not yet established a procedural schedule in this docket but we anticipate an MPSC decision in the fourth quarter of 2022. Our application is subject to the risk of the District Court agreeing with the plaintiffs in the litigation challenging the constitutionality of the preapproval statute. 39 --------------------------------------------------------------------------------
Electric Resource Supply -
Construction on our new
During the third quarter of 2021, we discontinued our plans to build a 30-40 MW natural gas plant nearAberdeen, South Dakota . Originally expected to be a$60 million project to be in service early in 2024, we were experiencing significant increases in estimated construction cost as a result of global supply chain challenges. As a result of the project discontinuance, we recorded a$1.6 million pre-tax charge for the write-off of preliminary construction costs. Our energy resource plans continue to identify portfolio requirements including potential investments resulting from a completed competitive solicitation process inSouth Dakota . We expect to file an updated integrated resource plan in late 2022.
Impact of Fuel and Purchase Power Costs
Montana PCCAM - InApril 2021 , we submitted a filing with the MPSC requesting approval to increase the PCCAM Base forecasted costs used to develop rates for the recovery of electric power costs by approximately$17 million , or potentially a greater increase to reflect current market prices and new capacity contracts. OnJune 29, 2021 , the MPSC approved our request for interim rates reflecting the$17 million increase, subject to refund. The Montana Consumer Counsel (MCC) filed a motion arguing that the PCCAM Base cannot be updated except in a general rate case and asked the MPSC to dismiss the application. OnOctober 5, 2021 , the MPSC voted to grant the MCC's motion to dismiss and onDecember 2, 2021 , the MPSC issued a final order dismissing our application. In 2021, PCCAM costs exceeded base revenues by approximately$54.1 million , which are allocated 90% toMontana customers and 10% to shareholders. As a result, we deferred$48.7 million of costs during 2021 to be collected from customers (90% of the costs above base) and recorded a reduction in pre-tax earnings of$5.4 million (10% of the variance). These increased costs are not reflected in customer bills and recovered until the subsequent power cost adjustment year, adversely affecting our cash flows and liquidity. We expect to address an adjustment to the PCCAM base in our upcomingMontana electric general rate filing. Regulatory Update General Rate Filing - Rate cases are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We regularly review the need for electric and natural gas rate relief in each state in which we provide service. We anticipate making aMontana electric general rate filing (2021 test year) in mid-2022. FERC Financial Audit - We are subject toFERC's jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things.The Division of Audits and Accounting in theOffice of Enforcement of FERC has initiated a routine audit ofNorthWestern Corporation for the period ofJanuary 1, 2018 to the present to evaluate our compliance withFERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received fromFERC , but is expected during the first quarter of 2022. Management is unable to predict the outcome or timing of the final resolution of the audit.
Supply Chain Challenges
We place significant reliance on our third-party business partners to supply materials, equipment and labor necessary for us to operate our utility and reliably serve current customers and future customers. As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases. Should these conditions continue, we could have difficulty completing the operations activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations. See "Electric Resource Supply -South Dakota " section above for discussion of supply chain challenges that have already impacted our business activities. Also, as we developed our forecast of capital expenditures, we estimate that these supply chain challenges have, thus far, increased our 2022 capital spend by approximately 2 percent, and it may go higher. 40 --------------------------------------------------------------------------------
Financing Activities
We anticipate financing our ongoing maintenance and capital programs with a combination of cash flows from operations, first mortgage bonds and equity issuances. See "Liquidity and Capital Resources" for additional information regarding our debt and equity financing activities. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
Fire Mitigation
With changing weather conditions which include more significant wind events, drought conditions, and warmer air temperatures, we do not consider the fire season specific to a time of year, but rather a condition that may exist at any time of year. Each year's weather conditions impact these situations differently: early season rains encourage plant growth which fuels fires later in the growing season, and winters with little snow leave dry plant material available for late season fires. The threat is not only in forested areas, where insect infestations and resulting tree death has been severe, but across the entire system including rural areas where grassland fires could be ignited, along with urban areas where extreme weather conditions pose a great risk to heavily populated areas. Recognizing the risk of significant wildfires inMontana , we are proactively seeking to mitigate wildfire risk through development of a comprehensive Fire Mitigation Plan addressing four key areas: situational awareness, operational practices, system assessment repair and hardening programs, and public safety and communications. This plan builds upon several key initiatives that were initiated and executed over the past several years including our transmission and distribution system infrastructure programs and our hazard tree removal program. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. We expect to include a request for costs associated with the plan in our 2022Montana electric rate filing. 41 --------------------------------------------------------------------------------
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):
[[Image Removed: nwe-20211231_g7.jpg]]
Electric Supply Resource Plans - Our energy resource plans identify portfolio
resource requirements including potential investments. As a result of a
competitive solicitation process in Montana , we have included approximately $275
million of capital in our projections above to construct a 175 MW natural gas
plant to be on line during the 2023 or 2024 winter season.
Distribution and Transmission Modernization and Maintenance - The primary goals
of our infrastructure investments are to reverse the trend in aging
infrastructure, maintain reliability, proactively manage safety, build capacity
into the system, and prepare our network for the adoption of new technologies.
We are taking a proactive and pragmatic approach to replacing these assets while
also evaluating the implementation of additional technologies to prepare the
overall system for smart grid applications. Beginning in 2021, and continuing
through 2025, we expect to install automated metering infrastructure in Montana
at a total cost of approximately $125 million , of which, $100 million remains
and is reflected in the five year capital forecast above.
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RESULTS OF OPERATIONS
Our consolidated results include the results of our divisions and subsidiaries
constituting each of our business segments. The overall consolidated discussion
is followed by a detailed discussion of utility margin by segment.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are
generally collected in rates from customers. In addition, various regulatory
agencies approve the prices for electric and natural gas utility service within
their respective jurisdictions and regulate our ability to recover costs from
customers.
Revenues are also impacted by customer growth and usage, the latter of which is
primarily affected by weather. Very cold winters increase demand for natural gas
and to a lesser extent, electricity, while warmer than normal summers increase
demand for electricity, especially among our residential and commercial
customers. We measure this effect using degree-days, which is the difference
between the average daily actual temperature and a baseline temperature of 65
degrees. Heating degree-days result when the average daily temperature is less
than the baseline. Cooling degree-days result when the average daily temperature
is greater than the baseline. The statistical weather information in our
regulated segments represents a comparison of this data.
Fuel, purchased supply and direct transmission expenses are costs directly
associated with the generation and procurement of electricity and natural gas.
Among the most significant of these costs are those associated with fuel,
purchased power, natural gas supply, and transmission expense. These costs are
generally collected in rates from customers and may fluctuate substantially with
market prices and customer usage.
Operating and maintenance expenses are costs associated with the ongoing
operation of our vertically-integrated utility facilities which provide electric
and natural gas utility products and services to our customers. Among the most
significant of these costs are those associated with direct labor and
supervision, repair and maintenance expenses, and contract services. These costs
are normally fairly stable across broad volume ranges and therefore do not
normally increase or decrease significantly in the short term with increases or
decreases in volumes.
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OVERALL CONSOLIDATED RESULTS
Year Ended
Consolidated net income in 2021 was$186.8 million as compared with$155.2 million in 2020, an increase of$31.6 million . As described in more detail below, this increase was primarily due to higherMontana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period due to the COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, and a favorable electric QF liability adjustment as compared with the prior period, partly offset by higher operating costs, non-recoverableMontana electric supply costs, and income tax expense. Consolidated gross margin in 2021 was$377.7 million as compared with$330.3 million in 2020, an increase of$47.4 million , or 14.4 percent. This increase was primarily due to higherMontana transmission loads and rates, favorable weather, higher commercial demand as compared to the prior period due to the COVID-19 pandemic related shutdowns, the prior period disallowance of supply costs, a favorable electric QF liability adjustment as compared with the prior period, and lower property and other taxes, partly offset by higher operating and maintenance expense, depreciation and depletion, andMontana non-recoverable electric supply costs. Electric Natural Gas Total 2021 2020 2021 2020 2021 2020 (in millions) Reconciliation of gross margin to utility margin: Operating Revenues$ 1,052.2 $ 940.8 $ 320.1 $ 257.9 $ 1,372.3 $ 1,198.7 Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 294.8 236.6 130.7 69.6 425.5 306.2 Less: Operating and maintenance 156.4 149.2 51.9 53.8 208.3 203.0 Less: Property and other taxes 134.9 140.6 38.5 38.9 173.4 179.5 Less: Depreciation and depletion 154.6 148.0 32.8 31.7 187.4 179.7 Gross Margin 311.5 266.4 66.2 63.9 377.7 330.3 Operating and maintenance 156.4 149.2 51.9 53.8 208.3 203.0 Property and other taxes 134.9 140.6 38.5 38.9 173.4 179.5 Depreciation and depletion 154.6 148.0 32.8 31.7 187.4 179.7 Utility Margin(1)$ 757.4 $ 704.2 $ 189.4 $ 188.3 $ 946.8 $ 892.5
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Year Ended December 31,
2021 2020 Change % Change
(in millions)
Utility Margin
Electric $ 757.4 $ 704.2 $ 53.2 7.6 %
Natural Gas 189.4 188.3 1.1 0.6
Total Utility Margin(1) $ 946.8 $ 892.5 $ 54.3 6.1 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated utility margin in 2021 was
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Primary components of the change in utility margin include the following (in
millions):
Utility Margin
2021 vs. 2020
Utility Margin Items Impacting Net Income
Higher transmission rates and demand due to market conditions and
pricing and the recognition of approximately $4.7 million of
deferred interim revenues $ 25.1
Higher electric retail volumes 17.1
Prior period MPSC disallowance of supply costs 9.4
Electric QF liability adjustment 4.4
Higher natural gas retail volumes 1.3
Higher non-recoverable
(5.3)
Reduction of rates from the step down of our Montana gas production
assets (1.2)
Other 5.1
Change in Utility Margin Impacting Net Income 55.9
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (4.8)
Higher revenue from lower production tax credits, offset in income tax expense
2.5
Gas production taxes recovered in revenue, offset in property and other taxes
0.5
Operating expenses recovered in revenue, offset in operating and maintenance expense
0.2
Change in Items Offset Within Net Income (1.6)
Increase in Consolidated Utility Margin(1) $ 54.3
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Higher electric retail volumes were driven by warmer summer weather in bothMontana andSouth Dakota , customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer overall winter weather inMontana andSouth Dakota . The higher natural gas retail volumes were due to improvedMontana commercial volumes as compared to the prior year due to the COVID-19 pandemic related shutdowns and customer growth, partly offset by overall warmer weather in all jurisdictions. In addition, the favorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a$7.5 million gain in 2021, as compared with a$3.1 million gain for the same period in 2020, due to the combination of: •A$2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a$0.9 million favorable reduction in costs in the prior period; •A negative adjustment, increasing the QF liability by$2.1 million , reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of$2.2 million in the prior year due to lower actual price escalation; and •A favorable adjustment of approximately$7.0 million decreasing the QF liability associated with a one-time clarification in contract term.
Year Ended
2021 2020 Change % Change
(in millions)
Operating Expenses (excluding fuel, purchased
supply and direct transmission expense)
Operating and maintenance $ 208.3 $ 203.0 $ 5.3 2.6 %
Administrative and general 101.9 94.1 7.8 8.3
Property and other taxes 173.4 179.5 (6.1) (3.4)
Depreciation and depletion 187.5 179.6 7.9 4.4
$ 671.1 $ 656.2 $ 14.9 2.3 %
45-------------------------------------------------------------------------------- Consolidated operating and maintenance expenses were$208.3 million in 2021, as compared with$203.0 million in 2020. Primary components of the change include the following (in millions): Operating & Maintenance Expenses
2021 vs. 2020 Operating & Maintenance Expenses Impacting Net Income Higher maintenance at our electric generation facilities
$ 4.6
Higher labor and benefits expenses due to increased compensation and medical costs
4.7
Write off of preliminary construction costs 1.6
Other 0.5
Change in Items Impacting Net Income 11.4
Operating & Maintenance Expenses Offset Within Net Income Pension and other postretirement benefits, offset in other income
(6.3)
Operating expenses recovered in trackers, offset in revenue 0.2
Change in Items Offset Within Net Income (6.1)
Increase in Operating and Maintenance Expenses $ 5.3
The write off of preliminary construction costs is associated with the 30-40MW
flexible natural gas plant near
Consolidated administrative and general expense was$101.9 million in 2021, as compared with$94.1 million in 2020. Primary components of the change include the following (in millions): Administrative & General Expenses
2021 vs. 2020 Administrative & General Expenses Impacting Net Income Higher technology implementation and maintenance expenses
$ 2.4 Higher litigation expenses 2.0 Higher insurance expenses 1.5
Higher labor and benefits expenses due to increased compensation and medical costs
1.0
Decrease in uncollectible accounts expense (4.5)
Other 1.2
Change in Items Impacting Net Income 3.6
Administrative & General Expenses Offset Within Net Income Non-employee directors deferred compensation, offset in other income
4.2
Change in Items Offset Within Net Income 4.2
Increase in Administrative & General Expenses $ 7.8
Uncollectible accounts expense decreased due to collections of previously
written off amounts in the current period. In the second quarter of 2020, we
voluntarily suspended service disconnections for non-payment, to help customers
who may be financially impacted by the COVID-19 pandemic.
Property and other taxes were $173.4 million in 2021, as compared with $179.5
million in 2020. This decrease was primarily due to lower estimated property
valuations in Montana partly offset by plant additions.
Depreciation and depletion expense was
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Consolidated operating income in 2021 was $275.7 million as compared with $236.2
million in 2020. This increase was primarily driven by higher Montana
transmission loads and rates, favorable weather, higher commercial demand as
compared to the prior period due to the COVID-19 pandemic related shutdowns, the
prior period disallowance of supply costs, a favorable electric QF liability
adjustment as compared with the prior period, and lower property and other
taxes, partly offset by higher operation and maintenance expense, depreciation
expense, and administrative and general expense.
Consolidated interest expense in 2021 was $93.7 million , as compared with $96.8
million in 2020. This decrease was primarily due to higher capitalization of
AFUDC and lower FERC deferrals, partly offset by higher borrowings.
Consolidated other income in 2021 was $8.3 million , as compared with $4.9
million in 2020. This increase was primarily due to higher capitalization of
AFUDC and higher interest income, partly offset by $2.1 million in items offset
in operating expenses. Items offset in operating expenses include a $6.3 million
increase in pension expenses and a $4.2 million increase in the value of
deferred shares held in trust for non-employee directors deferred compensation.
Consolidated income tax expense in 2021 was $3.4 million , as compared to an
income tax benefit of $11.0 million in 2020. Our effective tax rate for the
twelve months ended December 31, 2021 was 1.8 percent as compared with (7.6)
percent for the same period of 2020. We currently estimate our effective tax
rate will range between 0.0 percent to 3.0 percent in 2022. The effective tax
rate is expected to gradually increase to approximately 15 percent by 2026.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
Year Ended December 31,
2021 2020
Income Before Income Taxes $ 190.3 $ 144.2
Income tax calculated at federal statutory rate 40.0 21.0 % 30.3 21.0 %
Permanent or flow through adjustments:
State income, net of federal provisions 0.4 0.1 (1.5) (1.1)
Flow-through repairs deductions (21.9) (11.5) (23.8) (16.5)
Production tax credits (11.5) (6.1) (13.1) (9.1)
Plant and depreciation of flow through items (0.9) (0.6) 0.1 0.1
Amortization of excess deferred income taxes (DIT) (0.6) (0.3) (1.0) (0.7)
Prior year permanent return to accrual adjustments 0.0 0.0 (1.7) (1.2)
Other, net (2.1) (0.8) (0.3) (0.1)
(36.6) (19.2) (41.3) (28.6)
Income Tax Expense (Benefit) $ 3.4 1.8 % $ (11.0) (7.6) %
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ELECTRIC OPERATIONS
We have various classifications of electric revenues, defined as follows:
•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms. •Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue. •Transmission: Reflects transmission revenues regulated by theFERC . •Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.
Year Ended
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 334,581 $ 320,792 $ 13,789 4.3 % 2,729 2,635 311,922 307,390
South Dakota 65,429 66,603 (1,174) (1.8) 571 583 50,805 50,646
Residential 400,010 387,395 12,615 3.3 3,300 3,218 362,727 358,036
Montana 356,669 338,269 18,400 5.4 3,176 3,036 71,605 70,145
South Dakota 102,475 101,095 1,380 1.4 1,092 1,073 12,795 12,802
Commercial 459,144 439,364 19,780 4.5 4,268 4,109 84,400 82,947
Industrial 37,866 36,819 1,047 2.8 2,448 2,615 77 78
Other 32,084 31,833 251 0.8 175 173 6,333 6,333
Total Retail Electric $ 929,104 $ 895,411 $ 33,693 3.8 % 10,191 10,115 453,537 447,394
Regulatory amortization 34,395 (11,455) 45,850 (400.3)
Transmission 82,628 51,539 31,089 60.3
Wholesale and Other 6,055 5,320 735 13.8
Total Revenues $ 1,052,182 $ 940,815 $ 111,367 11.8 %
Fuel, purchased supply and
direct transmission expense(1) 294,820 236,581 58,239 24.6
Utility Margin(2) $ 757,362 $ 704,234 $ 53,128 7.5 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see
"Overall Consolidated Results" above for reconciliation of gross margin to
utility margin.
Cooling Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 635 398 417 60% warmer 52% warmer
South Dakota 1,034 879 733 18% warmer 41% warmer
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 7,217 7,304 7,557 1% warmer 4% warmer
South Dakota 6,758 7,445 7,696 9% warmer 12% warmer
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The following summarizes the components of the changes in electric utility
margin for the years ended
Utility Margin
2021 vs. 2020
Utility Margin Items Impacting Net Income
Higher transmission rates and demand due to market conditions and pricing
and the recognition of approximately $4.7 million of deferred interim
revenues $ 25.1
Higher retail volumes 17.1
Prior period disallowance of supply costs 9.4
QF liability adjustment 4.4
Higher non-recoverable Montana electric supply costs compared to the prior
period (5.3)
Other 3.3
Change in Utility Margin Impacting Net Income 54.0
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (4.0)
Higher revenue from lower production tax credits, offset in income tax expense
2.5
Operating expenses recovered in revenue, offset in operating and maintenance expense
0.6
Change in Items Offset Within Net Income (0.9)
Increase in Utility Margin(1) $ 53.1
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Higher electric retail volumes were driven by warmer summer weather in bothMontana andSouth Dakota , customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer overall winter weather inMontana andSouth Dakota . The favorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a$7.5 million gain in 2021, as compared with a$3.1 million gain for the same period in 2020, due to the combination of: •A$2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a$0.9 million favorable reduction in costs in the prior period; •A negative adjustment, increasing the QF liability by$2.1 million , reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of$2.2 million in the prior year due to lower actual price escalation; and •A favorable adjustment of approximately$7.0 million decreasing the QF liability associated with a one-time clarification in contract term.
The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
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NATURAL GAS OPERATIONS
We have various classifications of natural gas revenues, defined as follows:
•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms. •Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue. •Wholesale: Primarily represents transportation and storage for others.
Year Ended
Revenues Change Dekatherms Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 126,043 $ 103,457 22,586 21.8 % 13,885 13,893 179,637 177,335
South Dakota 26,596 21,547 5,049 23.4 2,834 2,993 41,079 40,612
Nebraska 20,964 16,861 4,103 24.3 2,480 2,561 37,603 37,576
Residential 173,603 141,865 31,738 22.4 19,199 19,447 258,319 255,523
Montana 64,681 51,349 13,332 26.0 7,446 7,166 24,927 24,497
South Dakota 19,131 14,316 4,815 33.6 2,744 3,003 6,896 6,895
Nebraska 11,371 8,066 3,305 41.0 1,755 1,784 4,963 4,974
Commercial 95,183 73,731 21,452 29.1 11,945 11,953 36,786 36,366
Industrial 1,134 840 294 35.0 135 122 229 231
Other 1,417 923 494 53.5 187 152 166 153
Total Retail Gas $ 271,337 $ 217,359 $ 53,978 24.8 % 31,466 31,674 295,500 292,273
Regulatory amortization 12,048 5,043 7,005 138.9
Wholesale and other 36,749 35,453 1,296 3.7
Total Revenues $ 320,134 $ 257,855 $ 62,279 24.2 %
Fuel, purchased supply and
direct transmission
expense(1) 130,728 69,609 61,119 87.8
Utility Margin(2) $ 189,406 $ 188,246 $ 1,160 0.6 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see
"Overall Consolidated Results" above for reconciliation of gross margin to
utility margin.
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 7,390 7,505 7,775 2% warmer 5% warmer
South Dakota 6,758 7,445 7,696 9% warmer 12% warmer
Nebraska 5,632 5,676 6,354 1% warmer 11% warmer
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The following summarizes the components of the changes in natural gas utility
margin for the years ended
Utility Margin
2021 vs. 2020
Utility Margin Items Impacting Net Income
Higher retail volumes $ 1.3
Reduction of rates from the step down of our
(1.2)
Other 1.8
Change in Utility Margin Impacting Net Income 1.9
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (0.8)
Operating expenses recovered in revenue, offset in operating and maintenance expense
(0.4)
Gas production taxes recovered in revenue, offset in property and other taxes
0.5
Change in Items Offset Within Net Income (0.7)
Increase in Utility Margin(1) $ 1.2
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Higher retail volumes were driven by improved
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
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LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets. As ofDecember 31, 2021 , our total net liquidity was approximately$79.8 million , including$2.8 million of cash,$77.0 million of revolving credit facility availability with no letters of credit outstanding. In addition, our liquidity was further enhanced by the forward equity sale agreements noted below, which could have been physically settled with common shares in exchange for cash of$286.1 million . Cash Flows
The primary sources and uses of cash and cash equivalents are summarized in the following condensed statement of cash flows for 2021 and 2020 (in millions):
Year Ended
2021 2020
Operating Activities
Net income $ 186.8 $ 155.2
Non-cash adjustments to net income 187.5 174.3
Changes in working capital (120.6) 48.1
Other noncurrent assets and liabilities (33.7) (25.5)
Cash Provided by Operating Activities 220.0 352.1
Investing Activities
Property, plant and equipment additions (434.3) (405.8)
Investment in equity securities (1.5) -
Cash Used in Investing Activities (435.8) (405.8)
Financing Activities
Proceeds from issuance of common stock, net 196.2 -
Issuance of long-term debt 99.9 150.0
(Repayments) issuances of short-term borrowings (100.0) 100.0
Dividends on common stock (128.5) (120.4)
Line of credit borrowings (repayments), net 151.0 (67.0)
Financing costs (0.9) (2.6)
Other (0.2) (1.3)
Cash Provided by Financing Activities 217.5 58.7
Net Increase in Cash, Cash Equivalents, and Restricted Cash $ 1.7 $ 5.0
Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 17.1 $ 12.1
Cash, Cash Equivalents, and Restricted Cash, end of period $ 18.8 $ 17.1
Operating Activities
Cash provided by operating activities totaled $220.0 million for the year ended
December 31, 2021 as compared with $352.1 million during 2020. This decrease in
operating cash flows is primarily due to a $122.3 million ($80.0 million from
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electric operations and $42.3 million from natural gas operations) net increase
in under collection of energy supply costs from customers in the current period,
which includes costs incurred during a February 2021 prolonged cold weather
event, the under-collected position of Montana's PCCAM, and a refund of
approximately $20.5 million to our FERC regulated customers and approximately
$6.1 to our Montana electric retail customers. These reductions were offset in
part by an improvement in net income.
As of December 31, 2021 , we have under collected our supply costs recovered
through tracking mechanisms by approximately $97.8 million . We have various
regulatory mechanisms that support our recovery of the energy supply costs
incurred by our utilities. Through these mechanisms and the regulatory
agreements for recovery of the costs incurred during the February 2021 cold
weather event, we anticipate recovering a significant portion of these costs
during 2022, improving our cash flows from operations. Conversely, a prolonged
spike in energy market prices in our operating jurisdictions, which could be
caused by further extreme weather events, could create additional costs with
deferred recovery that would offset these anticipated cash flow improvements.
Investing Activities
Cash used in investing activities totaled$435.8 million during the year endedDecember 31, 2021 , as compared with$405.8 million during 2020. Plant additions during 2021 include capital maintenance additions of approximately$314.1 million , and capacity related capital expenditures of approximately$120.2 million . Plant additions during 2020 included capital maintenance additions of approximately$269.5 million , and capacity related capital expenditures of approximately$136.3 million . As discussed above in the "Significant Infrastructure Investments and Initiatives" section, our capital expenditures are forecasted to increase to$582 million in 2022.
Financing Activities
Cash provided by financing activities totaled$217.5 million during 2021 as compared with$58.7 million during 2020. During 2021, the increase in cash provided by financing activities reflected the transactions noted below, which were undertaken primarily to fund capital expenditures in excess of our cash from operations, while maintaining our credit ratings. We issue debt and equity securities from time to time to refinance retiring debt maturities, reduce balances on our revolving credit facilities, fund capital expenditure programs, maintain credit ratings, and for other general corporate purposes. InMarch 2021 , we issued and sold$100 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00% maturing inMarch 26, 2024 . The net proceeds were used to repay in full our outstanding$100 million term loan that was dueApril 2, 2021 . We may redeem some or all of the bonds at any time in whole, or from time to time in part, at our option, on or afterMarch 26, 2022 , at a redemption price equal to 100% of the principal amount of the bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding, the redemption date. The bonds are secured by our electric and natural gas assets inMontana andWyoming . InApril 2021 , we entered into an Equity Distribution Agreement withBofA Securities, Inc. ,CIBC World Markets Corp ,Credit Suisse Securities (USA) LLC , andJ.P. Morgan Securities LLC , collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to$200.0 million , through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring onFebruary 11, 2024 . During the three months endedDecember 31, 2021 , we issued 46,723 shares of our common stock under the ATM program at an average price of$58.49 , for net proceeds of$2.7 million , which is net of sales commissions and other fees paid of less than$0.1 million . During the twelve months endedDecember 31, 2021 , we issued 1,966,117 shares of our common stock under the ATM program at an average price of$63.81 , for net proceeds of$124.2 million , which is net of sales commissions and other fees paid of approximately$1.3 million . We do not expect to utilize the ATM program during 2022. InNovember 2021 , we entered into forward equity agreements in connection with a completed$373.8 million public offering of approximately 7.0 million shares of our common stock. The initial forward agreement was for 6.1 million shares with an additional 0.9 million shares exercised at the option of the banking counterparty. Of the total 7.0 million shares of common stock offered, we initially sold 1.4 million shares, for$75.0 million in gross proceeds, directly to the underwriters in the offering, with cash proceeds received at closing.
At
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been settled at December 31, 2021 , with delivery of approximately $24.4 million
of cash or approximately 0.4 million shares of common stock to the counterparty,
if we unilaterally elected to net cash or net share settlement, respectively.
The forward price used to determine amounts due at settlement is calculated
based on the November 2021 public offering price for our common stock of $53.50 ,
net of underwriting discount, for an initial forward settlement price of
$51.895 , per share. The initial forward settlement price is increased for the
overnight bank funding rate, less a spread of 0.75 percent and less expected
dividends on our common stock during the period the instruments are outstanding.
We may settle the agreements at any time up to the maturity date of February 28,
2023 . Depending on settlement timing, if we elect to physically settle by
delivering shares of common stock, cash proceeds are expected to be
approximately $269.8 million to $286.1 million . Forward equity instruments were
recognized within stockholders' equity at fair value at the execution of the
agreements and will not be subsequently adjusted until settlement.
Cash Requirements and Capital Resources
The Company believes its cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy its material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports timely recovery for many our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the "Contractual Obligations and Other Commitments" section. Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the "Significant Infrastructure Investments and Initiatives" section. Our capital expenditures are forecasted to increase to$582 million in 2022,$563 million in 2023, and$465 million in 2024. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt and equity issuances and future rate increases. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations or available financing could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities we evaluate the additional capital need in balance with, debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
Credit Facilities
Liquidity is generally provided by internal cash flows and the use of our unsecured revolving credit facilities. This includes the$425 million Credit Facility and a$25 million revolving credit facility to provide swingline borrowing capability. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings. Our$425 million Credit Facility was entered into inSeptember 2020 and has a maturity date ofSeptember 2, 2023 . The Credit Facility includes uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size by an additional$75 million with the consent of the lenders. The Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to the Eurodollar rate, plus a margin of 112.5 to 175.0 basis points, or a base rate, plus a margin of 12.5 to 75.0 basis points. A total of ten banks participate in the facility, with no one bank providing more than 13 percent of the total availability.
The following table presents additional information about borrowings under our
revolving credit facilities during the year ended
Amount outstanding at year end$ 373.0 Daily average amount outstanding$ 260.3 Maximum amount outstanding$ 373.0 Minimum amount outstanding$ 171.0 54
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As of
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We do not have any long-term debt maturities in 2022.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
As described above, during 2021 we entered into a three-year ATM equity offering program whereby we can offer to sell up to$200.0 million of common shares. During 2021 we raised nearly$125 million under the program, but do not anticipate needing to issue equity through this program in 2022. We also initiated a public offering of$373.8 million of our common stock inNovember 2021 . We received approximately$75 million of cash proceeds for a portion of this offering and entered into forward equity agreements for the balance of the shares. We may settle the forward sale agreements at any time up to the maturity date ofFebruary 28, 2023 . We anticipate physically settling these agreements to meet our equity capital needs for 2022. Depending on settlement timing, if we physically settle by delivering our shares of common stock, cash proceeds are expected to be approximately$269.8 million to$286.1 million .
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service (Moody's), andS&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest and principal when due on our debt. As ofFebruary 4, 2022 , our current ratings with these agencies are as follows: Senior Secured Rating Senior Unsecured Rating Commercial Paper Outlook Fitch A A- F2 Stable Moody's A3 Baa2 Prime-2 Negative S&P A- BBB A-2 Stable _________________________ A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating. 55 --------------------------------------------------------------------------------
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as ofDecember 31, 2021 . See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements. Total 2022 2023 2024 2025 2026 Thereafter (in thousands)
Long-term debt(1)$ 2,552,660 $ -$ 517,660 $ 100,000 $ 300,000 $ 105,000 $ 1,530,000 Finance leases 14,772 2,875 3,099 3,337 3,596 1,865 - Estimated pension and other postretirement obligations(2) 58,805 12,775 11,658 11,658 11,357 11,357 N/A Qualifying facilities liability(3) 466,872 80,355 82,452 75,113 60,360 55,393 113,199 Supply and capacity contracts(4) 2,640,393 283,212 269,700 221,758 219,443 172,227
1,474,053
Contractual interest payments on debt(5) 1,480,783 88,457 86,270 79,760 70,791 64,701
1,090,804
Commitments for significant capital projects(6) 268,372 192,239 69,533 6,600 - - $ - Total Commitments(7)$ 7,482,657 $ 659,913 $ 1,040,372 $ 498,226 $ 665,547 $ 410,543 $ 4,208,056
___________________________
(1)Represents cash payments for long-term debt and excludes$11.2 million of debt discounts and debt issuance costs, net. (2)We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements. (3)Certain QFs require us to purchase minimum amounts of energy at prices ranging from$64 to$136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately$466.9 million . A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately$388.4 million . (4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts (exclusive of the qualifying facilities liability discussed above). These commitments range from one to 24 years and exclude contract payments associated with the Beartooth Battery agreement, which is subject to approval by the MPSC. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC, as further described in Note 3 - Regulatory Matters. (5)Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 1.35 percent on the outstanding balance through maturity of the facilities. (6)Represents significant firm purchase commitments for construction of planned capital projects. (7)The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 18 - Commitments and Contingencies) and asset retirement obligations (AROs) (see Note 6 - Asset Retirement Obligations) as the amount and timing of cash payments may be uncertain. 56 --------------------------------------------------------------------------------
CRITICAL ACCOUNTING ESTIMATES
Management's discussion and analysis of financial condition and results of
operations is based on our Consolidated Financial Statements, which have been
prepared in accordance with GAAP. The preparation of these Consolidated
Financial Statements requires us to make estimates and assumptions that affect
the reported amounts of assets, liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities. We base our estimates on
historical experience and other assumptions that are believed to be proper and
reasonable under the circumstances. We continually evaluate the appropriateness
of our estimates and assumptions. Actual results could differ from those
estimates.
We have identified the policies and related procedures below that contain
accounting estimates that involve a significant level of estimation uncertainty
and have had or are reasonably likely to have a material impact on our financial
condition or results of operations.
Regulatory Assets and Liabilities
Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets. While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 4 - Regulatory Assets and Liabilities, to the Consolidated Financial Statements for further discussion.
Pension and Postretirement Benefit Plans
We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 14 - Employee Benefit Plans, to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
•Discount rates used in determining the future benefit obligations; •Expected long-term rate of return on plan assets; and •Mortality assumptions.
We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions.
We set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year projected benefit cash flow from our plans. Based on this analysis as ofDecember 31, 2021 , our discount rate on theNorthWestern Corporation pension plan is 2.65 percent and on theNorthWestern Energy pension plan is 2.75 percent. 57 -------------------------------------------------------------------------------- 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 theNorthWestern Corporation andNorthWestern Energy pension plan, respectively, for 2022. Cost Sensitivity
The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):
Impact on Impact on Projected
Actuarial Assumption (1) Change in Assumption Pension Cost Benefit Obligation
Discount rate increase 0.25 % $ (2,232) $ (23,069)
Discount rate decrease (0.25) % 2,415 24,377
Rate of return on plan assets
increase 0.25 % (1,670) N/A
Rate of return on plan assets
decrease (0.25) % 1,670 N/A
(1) Reflects sensitivity to the period pension cost only and excludes the $11.3
million settlement charge during 2021, which was associated with the partial
pension annuitization described in Note 14 - Employee Benefit Plans.
Accounting Treatment
We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees. Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs inMontana and other postretirement benefit costs inSouth Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs inSouth Dakota and other postretirement benefit costs inMontana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service.
Income Taxes
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates. The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately$32.0 million as ofDecember 31, 2021 . The resolution of tax matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows. See Note 12 - Income Taxes to the Consolidated Financial Statements for further discussion. 58 --------------------------------------------------------------------------------
Qualifying Facilities Liability
Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Under the terms of these contracts, we are required to purchase minimum amounts of energy at prices ranging from$64 to$136 per MWH throughJune 2029 . Our estimated gross contractual obligation is approximately$466.9 million throughJune 2029 . A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately$388.4 million throughJune 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 (throughJune 2024 ). The actual escalation rate changes annually, which could significantly impact the liability and our results of operations. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements for further discussion. NEW ACCOUNTING STANDARDS
See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.
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