NORTHWESTERN ENERGY GROUP, INC. 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 Operating Revenues less Cost
of Sales as presented in our Condensed 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 for
recovery of operating costs, as well as to analyze how changes in loads (due to
weather, economic or other conditions), rates and other factors impact our
results of operations. Our 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 . For a discussion of
NorthWestern's business strategy, see Management's Discussion and Analysis of
Financial Condition and Results of Operations in our Annual Report on Form
10-K for the year ended December 31, 20 20 .
We are working to deliver safe, reliable and innovative energy solutions that
create value for customers, communities, employees and investors. This includes
bridging our history as a regulated utility safely providing low-cost and
reliable service with our future as a globally-aware company offering a broader
array of services performed by highly-adaptable and skilled employees. We seek
to deliver value to our customers by providing high reliability and customer
service, and an environmentally sustainable generation mix at an affordable
price. We are focused on delivering long-term shareholder value through:
•Infrastructure investment focused on a stronger and smarter grid to improve the
customer experience, while enhancing grid reliability and safety. This includes
automation in distribution and substations that enables the use of changing
technology.
•Integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.
We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three months endedMarch 31, 2021 and 2020. 20 -------------------------------------------------------------------------------- HOW WE PERFORMED AGAINST OUR FIRST QUARTER 2020 RESULTS Three Months Ended March 31, 2021 vs. 2020 Income Before Income Tax Income Taxes (Expense) Benefit Net Income (in millions) First Quarter 2020$ 48.9 $ 1.8$ 50.7 Items increasing (decreasing) net income: Higher electric retail volumes 4.1 (1.0) 3.1
Lower operating, general, and administrative expenses impacting net income
3.6 (0.9) 2.7
Higher Montana natural gas volumes 2.8 (0.7) 2.1
Higher Montana electric transmission revenue 2.1 (0.5) 1.6
Lower Montana electric supply cost recovery (1.4) 0.4 (1.0)
Higher depreciation and depletion (1.7) 0.4 (1.3)
Other 4.7 0.5 5.2
First Quarter 2021 $ 63.1 $ - $ 63.1
Change in Net Income $ 12.4
Consolidated net income for the three months ended March 31, 2021 was $63.1
million as compared with $50.7 million for the same period in 2020. This
increase was primarily due to improved gross margin from colder winter weather
and lower operating costs, partly offset by higher Montana electric supply costs
and depreciation expense, and lower income tax benefit.
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. We have
taken extra precautions for our employees who work in the field and for
employees who continue to work in our facilities. This
includes implementation of work from home policies, social-distancing protocols,
face-covering directives, and travel
restrictions where appropriate. 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.
We continue to work with customers who have been unable to pay during the
COVID-19 pandemic, including offering extended payment arrangements. In each of
our jurisdictions, we have experienced a significant improvement in our past due
customer account balances that peaked during the third quarter of 2020. We are
subject to certain annual winter disconnection procedures, which were in effect
from November 1, 2020 through March 31, 2021 .
The future impacts of the COVID-19 pandemic remain uncertain. Further extension
of the slowdown of the United States' economic growth, demand for commodities
and/or material changes in governmental policy may continue to result in lower
economic growth with lower demand for electricity and natural gas, as well as
reduced 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.
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
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customer demand. We issued an all-source competitive solicitation request in
January 2020 for up to 280 MWs of peaking and flexible capacity to be available
for commercial operation in late 2023 or early 2024 (the January 2020 request
for proposal (RFP)). Further, we expect additional all-source competitive
solicitation requests will be forthcoming, beginning in late 2021 or 2022.
Initial bids for the
•Laurel Generating Station - the construction of a 175 MW natural gas-fired generation plant nearLaurel, Montana , at a cost of approximately$250 million , which we will own; and •Powerex Transaction - a 5-year power purchase agreement for 100 MWs of capacity and energy products originating predominately from hydroelectric resources. We also anticipate finalizing an agreement for an energy storage contract shortly to fill the 5-hour duration tier identified in theJanuary 2020 RFP. We expect to request MPSC approval of theLaurel Generating Station , and possibly an energy storage contract, inMay 2021 .
February Cold Weather Event
TheFebruary 2021 prolonged cold spell resulted in record winter peak demand for electricity and natural gas. The broad reach of this event acrossthe United States and other market factors resulted in an extreme price excursion for purchased power and natural gas. In ourSouth Dakota andNebraska service territories, natural gas costs for the month ofFebruary 2021 exceeded the total cost for all of 2020. Fuel and purchased power costs in these jurisdictions are recovered through fuel adjustment clauses. We've incorporated the liquidity impacts into our overall 2021 financing plans. TheNebraska Public Service Commission (NPSC) opened a docket onMarch 2, 2021 to investigate the effect of this cold weather event on natural gas supply. In this docket, we proposed recovery of our costs forFebruary 13, 2021 toFebruary 18, 2021 over a two-year period. We expect the NPSC to issue a decision during the second quarter of 2021. We recorded a regulatory asset of approximately$26 million for these costs. The NPSC extended the winter disconnect rules untilMay 31, 2021 as a result of this cold weather event.The South Dakota Public Utilities Commission (SDPUC) issued an order allowing recovery of natural gas costs for the same time period over a one-year period, effectiveMarch 1, 2021 . We recorded a regulatory asset of approximately$17.8 million for these costs. Regulatory Update We do not expect to make general rate case filings in any of our regulatory jurisdictions during 2021. OnApril 15, 2021 , we filed a request to delay the implementation of our fixed cost recovery mechanism pilot in ourMontana jurisdiction for another year untilJuly 2022 or beyond, due to the continued uncertainties created by the COVID-19 pandemic. We anticipate making several other regulatory filings, primarily in ourMontana jurisdiction, including: •AnApril 21, 2021 filing requesting approval to increase the forecasted costs used to develop rates for the recovery of electric power costs through our Power Costs and Credits Adjustment Mechanism (PCCAM) by approximately$17 million ; and •AMay 2021 filing requesting approval to acquire electric capacity resources identified through ourJanuary 2020 RFP discussed above.
Financing Activity
InMarch 2021 , we issued and sold$100 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 1.00% maturing onMarch 26, 2024 . The net proceeds were used to repay in full our outstanding$100 million one-year term loan that was dueApril 2, 2021 . 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$200 million At-the-Market (ATM) offering during the second quarter of 2021 and begin issuing equity under that program. 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. Any equity issuances will be sized to maintain and protect our current credit ratings. 22 --------------------------------------------------------------------------------
RESULTS OF OPERATIONS
Our consolidated results include the results of our divisions and subsidiaries
constituting each of our business segments. The overall consolidated discussion
is followed by a detailed discussion of gross margin by segment.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers. Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.
OVERALL CONSOLIDATED RESULTS
Three Months Ended
Consolidated net income for the three months endedMarch 31, 2021 was$63.1 million as compared with$50.7 million for the same period in 2020. This increase was primarily due to improved gross margin from colder winter weather and lower operating costs, partly offset by higherMontana electric supply costs and depreciation expense, and lower income tax benefit. Consolidated operating revenues for the three months endedMarch 31, 2021 were$400.8 million as compared with$335.2 million for the same period in 2020. Consolidated gross margin for the three months endedMarch 31, 2021 was$256.3 million as compared with$244.0 million for the same period in 2020, an increase of$12.3 million . Electric Natural Gas Total 2021 2020 2021 2020 2021 2020 (dollars in millions) Reconciliation of operating revenue to gross margin: Operating Revenues$ 270.1 $ 244.6 $ 130.7 $ 90.6 $ 400.8 $ 335.2 Cost of Sales 80.2 63.8 64.3 27.4 144.5 91.2 Gross Margin(1)$ 189.9 $ 180.8 $ 66.4 $ 63.2 $ 256.3 $ 244.0
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Three Months Ended March 31,
2021 2020 Change % Change
(dollars in millions)
Gross Margin
Electric $ 189.9 $ 180.8 $ 9.1 5.0 %
Natural Gas 66.4 63.2 3.2 5.1
Total Gross Margin(1) $ 256.3 $ 244.0 $ 12.3 5.0 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Primary components of the change in gross margin include the following (in millions):
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Gross Margin 2021 vs. 2020
Gross Margin Items Impacting Net Income
Electric retail volumes $ 4.1
Natural gas retail volumes 2.8
Electric transmission 2.1
Montana natural gas production rates (0.5)
Montana electric supply cost recovery (1.4)
Other 2.9
Change in Gross Margin Impacting Net Income 10.0
Gross Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense 2.0
Production tax credits reducing revenue, offset in income tax benefit
1.1
Operating expenses recovered in revenue, offset in operating expense
(0.8)
Change in Gross Margin Items Offset Within Net Income 2.3
Increase in Consolidated Gross Margin(1) $ 12.3
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated gross margin increased$12.3 million , including a$10.0 million increase from items impacting net income and a$2.3 million increase from items offset within net income.
The change in consolidated gross margin for items impacting net income includes the following:
•An increase in electric retail revenue driven by residential usage inMontana primarily due to colder winter weather and overall customer growth. After the impacts of regulatory amortizations, commercial and industrial revenues were largely flat; •An increase in gas volumes due to colder winter weather in ourMontana andNebraska jurisdictions and customer growth, partly offset by warmer winter weather in ourSouth Dakota jurisdiction; •Higher Montana transmission rates, partly offset by lower demand to transmit energy across our transmission lines due to market conditions and pricing; •A reduction of rates from the step down of ourMontana gas production assets; and •Higher Montana electric supply costs as compared with the prior period.
Three Months Ended
2021 2020 Change % Change
(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 80.9 $ 79.0 $ 1.9 2.4 %
Property and other taxes 47.5 44.5 3.0 6.7
Depreciation and depletion 47.0 45.3 1.7 3.8
$ 175.4 $ 168.8 $ 6.6 3.9 %
24-------------------------------------------------------------------------------- Consolidated operating, general and administrative expenses were$80.9 million for the three months endedMarch 31, 2021 , as compared with$79.0 million for the three months endedMarch 31, 2020 . Primary components of the change include the following (in millions): Operating, General & Administrative Expenses 2021 vs. 2020 Operating, General & Administrative Expenses Impacting Net Income Uncollectible accounts $ (1.6) Travel and training (0.6) Labor (0.4) Generation maintenance (0.3) Employee benefits 0.4 Other (1.1) Change in Items Impacting Net Income (3.6)
Operating, General & Administrative Expenses Offset Within Net Income Non-employee directors deferred compensation, offset in other income
4.5
Pension and other postretirement benefits, offset in other income
1.8
Operating expenses recovered in trackers, offset in revenue (0.8)
Change in Operating, General & Administrative Expense Items Offset Within Net Income
5.5
Increase in Operating, General & Administrative Expenses $ 1.9
Consolidated operating, general and administrative expenses increased
The change in consolidated operating, general and administrative expenses for items impacting net income includes the following:
•Decreased uncollectible accounts due to collections of previously written off amounts; •A reduction in travel and training costs due to the impacts of the COVID-19 pandemic; •Decreased labor costs due to more time being spent by employees on capital projects than maintenance projects (which are expensed); •Lower maintenance costs at our electric generation facilities; and •Higher employee benefit costs primarily due to an increase in medical benefits. Property and other taxes were$47.5 million for the three months endedMarch 31, 2021 , as compared with$44.5 million in the same period of 2020. This increase was due primarily to an increase inMontana state and local taxes. We estimate property taxes throughout each year, and update those estimates based on valuation reports received from theMontana Department of Revenue . UnderMontana law, we are allowed to track the increases in the actual level of state and local taxes and fees and adjust our rates to recover the increase between rate cases less the amount allocated toFERC -jurisdictional customers and net of the associated income tax benefit. Depreciation and depletion expense was$47.0 million for the three months endedMarch 31, 2021 , as compared with$45.3 million in the same period of 2020. This increase was primarily due to plant additions. Consolidated operating income for the three months endedMarch 31, 2021 was$81.0 million as compared with$75.2 million in the same period of 2020. This increase was primarily due to the increase in gross margin, offset in part by higher operating expenses. Consolidated interest expense was$23.5 million for the three months endedMarch 31, 2021 as compared with$24.3 for the same period of 2020. This decrease was primarily due to lower interest on our revolving credit facilities and higher capitalization of Allowance forFunds Used During Construction (AFUDC), slightly offset by higher borrowings. 25 -------------------------------------------------------------------------------- Consolidated other income was$5.6 million for the three months endedMarch 31, 2021 as compared to consolidated other expense of$2.0 million during the same period of 2020. This increase includes approximately$6.3 million related to items offset in operating, general and administrative expense with no impact to net income and higher capitalization of AFUDC. Items offset in operating, general and administrative expense includes a$4.5 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation and a decrease in other pension expense of$1.8 million . Consolidated income tax benefit for the three months endedMarch 31, 2021 was less than$0.1 million as compared with to$1.8 million in the same period of 2020. Our effective tax rate for the three months endedMarch 31, 2021 was 0.0% as compared with (3.7)% for the same period in 2020. We expect our effective tax rate to range between (2.5)% to 2.5% in 2021.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
Three Months Ended March 31,
2021 2020
Income Before Income Taxes $ 63.1 $ 48.9
Income tax calculated at federal statutory rate 13.2 21.0 % 10.3 21.0 %
Permanent or flow-through adjustments:
State income tax, net of federal provisions 0.1 0.1 0.0 0.0
Flow-through repairs deductions (7.8) (12.5) (7.4) (15.2)
Production tax credits (4.3) (6.8) (3.6) (7.4)
Share-based compensation (0.3) (0.4) (0.6) (1.2)
Amortization of excess deferred income tax (0.3) (0.4) (0.4) (0.7)
Plant and depreciation of flow-through items (0.3) (0.5) 0.1 0.3
Other, net (0.3) (0.5) (0.2) (0.5)
(13.2) (21.0) (12.1) (24.7)
Income tax benefit $ 0.0 0.0 % $ (1.8) (3.7) %
We compute income tax expense for each quarter based on the estimated annual
effective tax rate for the year, adjusted for certain discrete items. Our
effective tax rate typically differs from the federal statutory tax rate
primarily due to the regulatory impact of flowing through federal and state tax
benefits of repairs deductions, state tax benefit of accelerated tax
depreciation deductions (including bonus depreciation when applicable) and
production tax credits.
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--------------------------------------------------------------------------------ELECTRIC SEGMENT
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. Three Months EndedMarch 31, 2021 Compared with the Three Months EndedMarch 31, 2020 Revenues Change Megawatt Hours (MWH) Avg. Customer Counts 2021 2020 $ % 2021 2020 2021 2020 (in thousands) Montana$ 96,020 $ 88,639 $ 7,381 8.3 % 800 734 310,237 305,969 South Dakota 17,749 18,918 (1,169) (6.2) 176 180 50,806 50,642 Residential 113,769 107,557 6,212 5.8 976 914 361,043 356,611 Montana 86,841 86,005 836 1.0 789 791 71,146 69,691 South Dakota 24,117 26,495 (2,378) (9.0) 278 291 12,721 12,735 Commercial 110,958 112,500 (1,542) (1.4) 1,067 1,082 83,867 82,426 Industrial 9,715 8,759 956 10.9 613 675 77 78 Other 4,592 5,249 (657) (12.5) 17 21 4,748 4,805Total Retail Electric $ 239,034 $ 234,065 $ 4,969 2.1 % 2,673 2,692 449,735 443,920 Regulatory amortization 14,789 (3,633) 18,422 (507.1) Transmission 14,728 12,609 2,119 16.8 Wholesale and Other 1,520 1,584 (64) (4.0) Total Revenues$ 270,071 $ 244,625 $ 25,446 10.4 % Total Cost of Sales 80,188 63,834 16,354 25.6 Gross Margin(1)$ 189,883 $ 180,791 $ 9,092 5.0 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 3,262 3,128 3,293 4% cooler 1% warmer
South Dakota 3,800 4,029 4,074 6% warmer 7% warmer
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The following summarizes the components of the changes in electric gross margin
for the three months ended
Gross Margin 2021 vs. 2020
Gross Margin Items Impacting Net Income
Retail volumes $ 4.1
Transmission 2.1
Montana electric supply cost recovery (1.4)
Other 2.4
Change in Gross Margin Impacting Net Income 7.2
Gross Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense 1.6
Production tax credits reducing revenue, offset in income tax benefit
1.1
Operating expenses recovered in revenue, offset in operating expense
(0.8)
Change in Gross Margin Items Offset Within Net Income 1.9
Increase in Gross Margin(1) $ 9.1
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin increased
The change in gross margin for items impacting net income includes the following:
•An increase in electric retail revenue driven by residential usage inMontana primarily due to colder winter weather and overall customer growth. After the impacts of regulatory amortizations, commercial and industrial revenues were largely flat; •Higher Montana transmission rates, partly offset by lower demand to transmit energy across our transmission lines due to market conditions and pricing; and •Higher Montana electric supply costs as compared with the prior period. 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. 28
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NATURAL GAS SEGMENT
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. Three Months EndedMarch 31, 2021 Compared with the Three Months EndedMarch 31, 2020 Revenues Change Dekatherms (Dkt) Avg. Customer Counts 2021 2020 $ % 2021 2020 2021 2020 (in thousands) Montana$ 47,012 $ 38,295 8,717 22.8 % 6,086 5,637 178,996 176,607 South Dakota 10,103 10,271 (168) (1.6) 1,570 1,584 41,138 40,589 Nebraska 8,241 7,687 554 7.2 1,349 1,295 37,735 37,622 Residential 65,356 56,253 9,103 16.2 9,005 8,516 257,869 254,818 Montana 23,781 19,154 4,627 24.2 3,193 2,923 24,851 24,464 South Dakota 6,524 7,294 (770) (10.6) 1,345 1,592 6,900 6,917 Nebraska 4,401 4,061 340 8.4 910 889 4,982 5,000 Commercial 34,706 30,509 4,197 13.8 5,448 5,404 36,733 36,381 Industrial 482 340 142 41.8 66 53 232 233 Other 489 343 146 42.6 76 62 159 152Total Retail Gas $ 101,033 $ 87,445 $ 13,588 15.5 % 14,595 14,035 294,993 291,584 Regulatory amortization 20,368 (6,348) 26,716 (420.9) Wholesale and other 9,331 9,533 (202) (2.1) Total Revenues$ 130,732 $ 90,630 $ 40,102 44.2 % Total Cost of Sales 64,325 27,438 36,887 134.4 Gross Margin(1)$ 66,407 $ 63,192 $ 3,215 5.1 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 3,262 3,136 3,331 4% cooler 2% warmer
South Dakota 3,800 4,029 4,074 6% warmer 7% warmer
Nebraska 3,354 3,074 3,383 9% cooler 1% warmer
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The following summarizes the components of the changes in natural gas gross
margin for the three months ended
Gross Margin 2021 vs. 2020
(in millions)
Gross Margin Items Impacting Net Income
Retail volumes $ 2.8
Montana rates (0.5)
Other 0.5
Change in Gross Margin Impacting Net Income 2.8
Gross Margin Items Offset Within Net Income
Property tax revenue, offset in property tax expense 0.4 Change in Gross Margin Items Offset Within Net Income 0.4 Increase in Gross Margin(1) $ 3.2
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin increased$3.2 million , including a$2.8 million increase for items impacting net income and a$0.4 million increase from items offset within net income.
The change in gross margin for items impacting net income includes the following:
•An increase in gas volumes due to colder winter weather in ourMontana andNebraska jurisdictions and customer growth, partly offset by warmer winter weather in ourSouth Dakota jurisdiction; and •A reduction of rates from 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
Sources and Uses of Funds
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, borrowing
capacity under existing credit facilities, and issuance of debt or equity
securities are 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, the
receipt of cash from operations, and available financing. A material change in
operations, unfavorable credit metrics, 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.
Our liquidity is supported by the use of our credit facilities which includes a
$425 million Credit Facility and a $25 million revolving credit facility to
provide swingline borrowing capability. The $425 million 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 $425 million 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. The $25 million revolving credit facility bears interest
at the lower of prime plus a credit spread of 0.13 percent, or available rates
tied to the Eurodollar rate plus a credit spread of 0.80 percent.
We utilize availability under our 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 March 31, 2021 , our total net liquidity was approximately $187.9 million ,
including $8.9 million of cash and $179.0 million of revolving credit facility
availability. As of March 31, 2021 , there were no letters of credit outstanding
and $271.0 million in outstanding borrowings under our credit facilities.
Availability under our credit facilities was $205.0 million as of April 16,
2021 .
We issue debt securities to refinance retiring maturities, 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 allow us to maintain investment grade ratings. We target a 50 -
55 percent debt to total capital ratio excluding finance leases, and a long-term
dividend payout ratio target of 60 - 70 percent of earnings per share; however,
there can be no assurance that we will be able to maintain our ratios within
these target ranges.
In March 2021 , we issued and sold $100 million aggregate principal amount of
Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00%
maturing in March 26, 2024 . The net proceeds were used to repay in full our
outstanding $100 million term loan that was due April 2, 2021 . We may redeem
some or all of the bonds at any time in whole, or from time
to time in part, at our option, on or after March 26, 2022 , at a redemption
price equal to 100% of the principal amount of the
bonds to be redeemed, plus accrued and unpaid interest on the principal amount
of the bonds being redeemed to, but excluding,
the redemption date. The bonds are secured by our electric and natural gas
assets in Montana and Wyoming .
We anticipate initiating a 3-year $200 million At-the-Market (ATM) offering
during the second quarter of 2021 and begin issuing equity under that program in
balance with our current capital expenditure plans. Capital investment in
response to our Montana electric supply resource planning would be incremental
to these amounts. Financing plans are subject to change, depending on capital
expenditures, regulatory outcomes, internal cash generation, market conditions
and other factors. Any equity issuances will be sized to maintain and protect
our current credit ratings.
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--------------------------------------------------------------------------------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% of the variance above or below the established base revenues and actual costs collected from or refunded to customers. Our electric supply rates were adjusted monthly under the prior tracker, and under the PCCAM design are adjusted annually. In periods of significant fluctuation of loads and / or market prices, this design impacts our cash flows as application of the PCCAM requires that we absorb certain power cost increases before we are allowed to recover increases from customers. As ofMarch 31, 2021 , we have under collected our costs recovered through tracking mechanisms by approximately$32.8 million . We under collected our costs by approximately$5.7 million as ofDecember 31, 2020 and under collected our costs by approximately$21.5 million as ofMarch 31, 2020 .
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 ofApril 16, 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(1) A3 Baa2 Prime-2 Negative S&P A- BBB A-2 Stable _________________________
(1) On
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.
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--------------------------------------------------------------------------------Cash Flows
The following table summarizes our consolidated cash flows (in millions):
Three Months Ended
March 31,
2021 2020
Operating Activities
Net income $ 63.1 $ 50.7
Non-cash adjustments to net income 46.8 48.7
Changes in working capital (21.9) 62.2
Other noncurrent assets and liabilities (22.3) (3.5)
Cash Provided by Operating Activities 65.7 158.1
Investing Activities
Property, plant and equipment additions (77.9) (78.4)
Cash Used in Investing Activities (77.9) (78.4)
Financing Activities
Issuance of long-term debt, net 99.9 - Repayments of short-term borrowings (100.0) - Line of credit borrowings, net 49.0 6.0 Dividends on common stock (31.1) (30.1) Financing costs (0.4) (0.1) Other (0.3) (2.5) Cash Provided by (Used in) Financing Activities 17.1 (26.7) Increase in Cash, Cash Equivalents, and Restricted Cash 4.9 53.0 Cash, Cash Equivalents, and Restricted Cash, beginning of period 17.1 12.1 Cash, Cash Equivalents, and Restricted Cash, end of period$ 22.0 $ 65.1
Cash Provided by Operating Activities
As ofMarch 31, 2021 , cash, cash equivalents, and restricted cash were$22.0 million as compared with$17.1 million atDecember 31, 2020 and$65.1 million atMarch 31, 2020 . Cash provided by operating activities totaled$65.7 million for the three months endedMarch 31, 2021 as compared with$158.1 million during the three months endedMarch 31, 2020 . This decrease in operating cash flows is primarily due to an$80.9 million increase in market purchases of supply during the February cold weather event resulting in an undercollection of supply costs from customers in the current period, and a refund of approximately$20.5 million to ourFERC regulated wholesale customers.
Cash Used in Investing Activities
Cash used in investing activities decreased by approximately$0.5 million as compared with the first three months of 2020. Plant additions during the first three months of 2021 include maintenance additions of approximately$53.8 million and capacity related capital expenditures of$24.1 million . Plant additions during the first three months of 2020 included maintenance additions of approximately$54.5 million and capacity related capital expenditures of approximately$23.9 million .
Cash Provided by (Used in) Financing Activities
Cash provided by financing activities totaled$17.1 million during the three months endedMarch 31, 2021 as compared with cash used in financing activities of$26.7 million during the three months endedMarch 31, 2020 . During the three months endedMarch 31, 2021 , cash provided by financing activities reflects net proceeds from the issuance of debt of$99.9 million and net issuances under our revolving lines of credit of$49.0 million , offset in part by repayments of our short-term borrowings of$100.0 million and payment of dividends of$31.1 million . During the three months endedMarch 31, 2020 , net cash used in financing activities reflects payment of dividends of$30.1 million , offset in part by net issuances under our revolving lines of credit of$6.0 million . 33 --------------------------------------------------------------------------------
Capital Requirements
Our capital expenditures program is subject to continuing review and modification. Actual utility construction expenditures may vary from estimates due to changes in electric and natural gas projected load growth, changing business operating conditions and other business factors. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt and equity issuances. Our estimated capital expenditures are discussed in our Annual Report on Form 10-K for the year endedDecember 31, 2020 within the Management's Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As ofMarch 31, 2021 , there have been no material changes in our estimated capital expenditures.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as ofMarch 31, 2021 . See our Annual Report on Form 10-K for the year endedDecember 31, 2020 for additional discussion. Total 2021 2022 2023 2024 2025 Thereafter (in thousands) Long-term debt (1)$ 2,477,637 $ - $ -$ 415,660 $ 100,000 $ 300,000 $ 1,661,977 Finance leases 16,797 2,026 2,875 3,097 3,338 3,596 1,865 Estimated pension and other postretirement obligations (2) 61,877 11,084 12,905 12,905 12,492 12,491 NA Qualifying facilities liability (3) 532,527 58,292 79,572 81,646 79,384 65,041 168,592 Supply and capacity contracts (4) 2,289,036 182,716 191,130 192,205 169,743 166,443
1,386,799
Contractual interest payments on debt (5) 1,556,224 65,328 87,104 85,177 79,760 78,358
1,160,497
Total Commitments (6)
_________________________
(1)Represents cash payments for long-term debt and excludes$13.5 million of debt discounts and debt issuance costs, net. (2)We estimate cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. Pension and 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$532.5 million . A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately$433.5 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. (5)Contractual interest payments includes our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 1.36% 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 10 - Commitments and Contingencies) and asset retirement obligations as the amount and timing of cash payments may be uncertain. Other Obligations - As a co-owner ofColstrip , we provided surety bonds of approximately$19.9 million and$22.8 million as ofMarch 31, 2021 andDecember 31, 2020 , respectively, on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to 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 the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced. 34 --------------------------------------------------------------------------------
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management's discussion and analysis of financial condition and results of
operations is based on our Financial Statements, which have been prepared in
accordance with GAAP. The preparation of these 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 consider an estimate to be
critical if it is material to the Financial Statements and it requires
assumptions to be made that were uncertain at the time the estimate was made and
changes in the estimate are reasonably likely to occur from period to period.
This includes the accounting for the following: regulatory assets and
liabilities, pension and postretirement benefit plans, income taxes and
qualifying facilities liability. These policies were disclosed in Management's
Discussion and Analysis of Financial Condition and Results of Operations in our
Annual Report on Form 10-K for the year ended
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