NORTHWESTERN ENERGY GROUP, INC. The following includes a discussion of our results of operations and cash flows for the year endedDecember 31, 2020 compared to the year endedDecember 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 endedDecember 31, 2019 compared with the year endedDecember 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 endedDecember 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.
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--------------------------------------------------------------------------------We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
In 2020, approximately 65 percent of our customers' retail electric needs originated from carbon-free resources, which is more than two times better than the totalU.S electric power industry. As part of our continued efforts in environmental stewardship, we recently established our Carbon Reduction Vision forMontana , committing to reduce the carbon intensity of ourMontana 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 inMontana 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
Income Before Income Tax
Income Taxes 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 34 -------------------------------------------------------------------------------- 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 inMontana andSouth 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 inAugust 2020 , authorizing deferral of costs for possible recovery through future rates. As ofDecember 31, 2020 we have deferred$0.2 million of uncollectible accounts expense into a regulatory asset inSouth Dakota .
•The MPSC issued an order in
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 onNovember 1st and will remain in effect throughMarch 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 35 --------------------------------------------------------------------------------
chain challenges to date and were able to execute on over
The ongoing impacts of the COVID-19 pandemic remain uncertain. Continued slowdown inthe 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 -
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 inFebruary 2020 for up to 280 MWs of peaking and flexible capacity to be available for commercial operation in early 2023 (theFebruary 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 theFebruary 2020 RFP were received inJuly 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. 36 --------------------------------------------------------------------------------
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-20201231_g8.jpg]]
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 "
Natural Gas Production Assets - We own natural gas production and gathering system assets inMontana 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 inMontana 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 ourMontana 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. 37 --------------------------------------------------------------------------------
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.
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--------------------------------------------------------------------------------OVERALL CONSOLIDATED RESULTS
Year Ended
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.
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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 inMontana andSouth 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 ourColstrip 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 lowerMontana 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 ourMontana gas production assets; and •An increase inMontana electric rates. 40 --------------------------------------------------------------------------------
Year Ended December 31,
2020 2019 Change % Change
(in millions)Operating Expenses (excluding cost of sales)
Operating, general and administrative
$ (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
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
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; 41 -------------------------------------------------------------------------------- •Lower maintenance at our electric generation facilities; and •Increased uncollectible accounts. InMarch 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 theSouth 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 inMontana .
Depreciation and depletion expense was
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 endedDecember 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) %
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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 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 theFERC . •Wholesale and other are largely gross margin neutral as they are offset by changes in cost of sales.
Year Ended
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
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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
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 inMontana andSouth 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 ourColstrip 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 lowerMontana 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 inMontana electric rates. 44 -------------------------------------------------------------------------------- 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. 45
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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 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
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
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The following summarizes the components of the changes in natural gas gross
margin for the years ended
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 ourMontana gas production assets.
Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
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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 toMontana 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, inApril 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 onApril 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. InMay 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 onMay 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 inMontana andSouth Dakota . InSeptember 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 toSeptember 2, 2023 (fromDecember 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
48
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Amount outstanding at year end $ 222.0
Daily average amount outstanding $ 136.2
Maximum amount outstanding $ 305.0
Minimum amount outstanding $ -
As of
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 5, 2021 , 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 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.
49
--------------------------------------------------------------------------------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 ofDecember 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 ofColstrip , we have provided our proportionate share of surety bonds of approximately$22.8 million and$13.2 million as ofDecember 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 atColstrip Steam Electric Stations,Colstrip Montana (the AOC) as required by theMontana Department of Environmental Quality (MDEQ). As work is completed and costs are incurred under the AOC, the surety bonds will be reduced. 50 --------------------------------------------------------------------------------
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 inSouth Dakota , are designed to provide stable recovery of supply costs, with a monthly adjustment to correct for any under or over collection. TheMontana 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
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 51
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Cash Flows Provided By Operating Activities
As ofDecember 31, 2020 , our cash, cash equivalents, and restricted cash were$17.1 million as compared with$12.1 million atDecember 31, 2019 . Cash provided by operating activities totaled$352.1 million for the year endedDecember 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 toMontana 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 endedDecember 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 . 52 --------------------------------------------------------------------------------
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 ofDecember 31, 2020 , our discount rate on theNorthWestern Corporation pension plan is 2.20 percent and on theNorthWestern Energy pension plan is 2.30 percent. 53 -------------------------------------------------------------------------------- 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 2021. 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 Change in Assumption Pension Cost 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 ofDecember 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 ofDecember 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. 54 --------------------------------------------------------------------------------
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 throughJune 2029 . Our estimated gross contractual obligation is approximately$552.0 million throughJune 2029 . A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately$448.5 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. 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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