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. This
measure differs from the GAAP definition of Gross Margin due to the exclusion of
Depreciation and depletion expenses, which are presented separate from Cost of
Sales 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, 2020 .
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 and nine months endedSeptember 30, 2021 and 2020. 27 -------------------------------------------------------------------------------- HOW WE PERFORMED AGAINST OUR THIRD QUARTER 2020 RESULTS Three Months Ended September 30, 2021 vs. 2020 Income Tax Income Before (Expense) Income Taxes Benefit Net Income (in millions) Third Quarter 2020$ 26.8 $ 2.7$ 29.5 Items increasing (decreasing) net income: Higher Montana electric transmission revenue 10.1 (2.6) 7.5 Higher electric retail volumes 8.4 (2.1) 6.3 Higher income tax expense - (2.1) (2.1) Higher operating, general, and administrative expenses impacting net income (5.0) 1.3 (3.7) Higher depreciation and depletion (2.8) 0.7 (2.1) Lower Montana electric supply cost recovery (2.1) 0.5 (1.6) Electric QF liability adjustment (1.3) 0.3 (1.0) Lower Montana natural gas volumes (0.6) 0.2 (0.4) Other 4.2 (1.4) 2.8 Third Quarter 2021$ 37.7 $ (2.5) $ 35.2 Change in Net Income$ 5.7 Consolidated net income for the three months endedSeptember 30, 2021 was$35.2 million as compared with$29.5 million for the same period in 2020. This increase was primarily driven by higherMontana transmission loads and rates and warmer summer weather, partly offset by higher operating costs, lower supply cost recovery, an unfavorable QF liability adjustment compared with the prior period, and higher income tax expense. SIGNIFICANT TRENDS AND REGULATION
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 inJanuary 2020 for up to 280 MWs of peaking and flexible capacity to be available for commercial operation in late 2023 or early 2024 (theJanuary 2020 request for proposal (RFP)). Further, we expect to issue additional all-source competitive solicitation requests during 2022. Initial bids for theJanuary 2020 RFP were received inJuly 2020 . A third-party RFP Administrator evaluated the bids with the following portfolio of projects selected: •Laurel Generating Station - the construction of a 175 MW natural gas-fired generation plant nearLaurel, Montana , at a cost of approximately$275 million , including Allowance forFunds Used During Construction (AFUDC), which we will own; •Beartooth Battery - A 20-year agreement to purchase capacity and ancillary services produced from a 50 MW battery energy storage facility that will be constructed inYellowstone County, Montana ; and •Powerex Transaction - a 5-year power purchase agreement for 100 MWs of capacity and energy products originating predominately from hydroelectric resources. OnMay 19, 2021 , we filed an application with the MPSC for advanced approval to acquire theLaurel Generating Station and Beartooth Battery agreement as new capacity resources. These resources, together with the Powerex Transaction, will help address our identified capacity shortage. The Powerex Transaction, was not included in the application for advanced approval filed with the MPSC. Recent upheaval in the construction market and, specifically, timely availability of critical components and escalating labor and construction costs, has necessitated the flexibility to expend capital and make commercial decisions in 28 -------------------------------------------------------------------------------- advance of the timeline established by the MPSC advanced approval docket. Accordingly, we withdrew our application onSeptember 23, 2021 and intend to seek approval from the MPSC to place theLaurel Generating Station in rate base through a future filing. We currently intend to file a separate application for advanced approval of the Beartooth Battery agreement. OnOctober 21, 2021 theMontana Environmental Information Center and theSierra Club filed a lawsuit in Montana State Court, against theMontana Department of Environmental Quality (MTDEQ) and us, alleging the environmental review of ourLaurel Generating Station project was unlawful. This lawsuit could delay theLaurel project if the Court were to require a full Environmental Impact Study regarding the project, set aside the air quality permit granted for theLaurel Generating Station , or determine that the underlying environmental statute violates the Montana Constitutional guarantee of a "clean and healthful environment."
Electric Resource Supply -
Our energy resource plans identify portfolio requirements including potential investments resulting from a completed competitive solicitation process inSouth Dakota . Our estimated capital expenditures 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 section includes approximately$60 million for a 30-40 MW flexible natural gas plant nearAberdeen, South Dakota , which was expected to be in service in early 2024. During the third quarter of 2021, we decided to discontinue our plans to build this project as a result of significant increases in estimated construction cost as a result of global supply chain challenges. As a result of the project discontinuance, we recorded a$1.2 million pre-tax charge in the three months endedSeptember 30, 2021 , for the write-off of preliminary construction costs. Construction continues for a 60 MW reciprocating internal combustion engine project inHuron, South Dakota . The project is expect to be online in early 2022 with total construction costs of approximately$80 million (approximately$40 million invested in 2020). Regulatory Update
We will not make a general rate case filing in any of our regulatory
jurisdictions during 2021. We have recently filed several other regulatory
filings, primarily in our
•AnApril 15, 2021 filing of a motion requesting 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. OnJune 29, 2021 , the MPSC granted our motion and issued a final order denying reconsideration onSeptember 15, 2021 ; and •AnApril 21, 2021 filing requesting approval to increase the PCCAM Base forecasted costs used to develop rates for the recovery of electric power costs through our PCCAM by approximately$17 million , or potentially a greater increase to reflect current market prices and new capacity contracts. OnJune 29, 2021 , the MPSC approved implementing our request for interim rates reflecting the$17 million increase, subject to refund. The MCC filed a motion arguing that the PCCAM Base cannot be updated except in a general rate case and asked the MPSC to dismiss the application. OnOctober 5, 2021 , the MPSC voted to grant the MCC's motion to dismiss, and we await the final written order. We are subject toFERC's jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things.The Division of Audits and Accounting in theOffice of Enforcement of FERC has initiated a routine audit ofNorthWestern Corporation for the period ofJanuary 1, 2018 to the present to evaluate our compliance withFERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received fromFERC , but is expected within the next six months. Management is unable to predict the outcome or timing of the final resolution of the audit.
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 , 29 -------------------------------------------------------------------------------- 2021 over a two-year period, which was subsequently approved by the NPSC onMay 11, 2021 , and a regulatory asset of approximately$26.0 million was recorded for these costs, with a remaining balance of$25.2 million as ofSeptember 30, 2021 .The South Dakota Public Utilities Commission issued an order allowing recovery of natural gas costs for the same time period over a one-year period, effectiveMarch 2, 2021 . A regulatory asset of approximately$22.0 million was recorded for these costs, with a remaining balance of$17.7 million as ofSeptember 30, 2021 .
COVID-19 Pandemic and Global Economic Recovery
The COVID-19 pandemic has had widespread impacts on people, economies, businesses and financial markets. Beginning inMarch 2020 , the pandemic and resulting economic conditions began impacting our business operations and financial results. Our 2020 financial results were impacted by lower sales volumes, an increase in reserves for uncollectible accounts and an increase in interest expense, partly offset by lower operating, general and administrative expenses. We have experienced improving conditions in our service territories during 2021, that have positively impacted our business as compared to 2020. The ultimate impact of the pandemic on our financial results for 2021 and beyond depends on the evolving landscape of the pandemic and the public health responses to contain it, as well as the substance and pace of the macroeconomic recovery. If health conditions deteriorate or the economic recovery stalls, it could have the result of 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 or provide the services we seek to support our business operations. These impacts could have a material adverse effect on our results of operations, financial condition and prospects. In addition, the Biden administration is seeking to require large companies like us to have all of our employees vaccinated or undergo weekly COVID testing. Complying with either a vaccine mandate or weekly testing requirements (if there are even enough testing kits available) could be difficult and costly and it is possible that some employees may choose to leave employment over a vaccine or testing requirement. We place significant reliance on our third-party business partners to supply materials, equipment and labor necessary for us to operate our utility and reliably serve current customers and future customers. As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases. Should these economic conditions and issues continue, we could have difficulty completing the operations activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations.
Financing Activities
We anticipate financing our ongoing maintenance and capital programs with a combination of cash flows from operations, first mortgage bonds and equity issuances.
InMarch 2021 , we issued and sold$100.0 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$100.0 million one-year term loan that was dueApril 2, 2021 . InApril 2021 , we entered into an Equity Distribution Agreement pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to$200.0 million , through an ATM program, including an equity forward sales component. During the three months endedSeptember 30, 2021 , we issued 1,040,085 shares of our common stock at an average price of$63.13 , for net proceeds of$64.8 million . During the nine months endedSeptember 30, 2021 , we issued 1,919,394 shares of our common stock at an average price of$63.94 , for net proceeds of$121.1 million . We expect a total of approximately$200.0 million of equity proceeds during 2021 to support our current capital program and maintain and protect our credit ratings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors. RESULTS OF OPERATIONS Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment. 30 --------------------------------------------------------------------------------
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 endedSeptember 30, 2021 was$35.2 million as compared with$29.5 million for the same period in 2020. This increase was primarily driven by higherMontana transmission loads and rates and warmer summer weather, partly offset by higher operating costs, higherMontana electric supply costs, an unfavorable QF liability adjustment compared with the prior period, and higher income tax expense. Consolidated operating revenues for the three months endedSeptember 30, 2021 were$326.0 million as compared with$280.7 million for the same period in 2020. Consolidated gross margin for the three months endedSeptember 30, 2021 was$227.3 million as compared with$212.6 million for the same period in 2020, an increase of$14.7 million . Electric Natural Gas Total 2021 2020 2021 2020 2021 2020 (dollars in millions) Reconciliation of operating revenue to gross margin: Operating Revenues$ 287.5 $ 244.2 $ 38.5 $ 36.5 $ 326.0 $ 280.7 Cost of Sales 89.4 61.2 9.3 6.9 98.7 68.1 Gross Margin(1)$ 198.1 $ 183.0 $ 29.2 $ 29.6 $ 227.3 $ 212.6
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Three Months Ended September 30,
2021 2020 Change % Change
(dollars in millions)
Gross Margin
Electric $ 198.1 $ 183.0 $ 15.1 8.3 %
Natural Gas 29.2 29.6 (0.4) (1.4)
Total Gross Margin(1) $ 227.3 $ 212.6 $ 14.7 6.9 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Primary components of the change in gross margin include the following (in millions):
31
--------------------------------------------------------------------------------
Gross Margin 2021 vs. 2020
Gross Margin Items Impacting Net Income
Montana electric transmission revenue $ 10.1
Electric retail volumes 8.4
Montana electric supply cost recovery (2.1)
Electric QF liability adjustment (1.3)
Natural gas retail volumes (0.6)
Other 0.4
Change in Gross Margin Impacting Net Income 14.9
Gross Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense (1.3)
Gas production taxes recovered in revenue, offset in property and other taxes
0.2
Operating expenses recovered in revenue, offset in operating expense
0.3
Production tax credits reducing revenue, offset in income tax expense
0.6
Change in Gross Margin Items Offset Within Net Income (0.2)
Increase in Consolidated Gross Margin(1) $ 14.7
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated gross margin increased$14.7 million , including a$14.9 million increase from items impacting net income and a$0.2 million decrease from items offset within net income.
The change in consolidated gross margin for items impacting net income includes the following:
•Higher Montana transmission rates and higher demand to transmit energy across
our transmission lines due to market conditions and pricing;
•An increase in electric retail revenue due to warmer summer weather, overall
customer growth, and increased commercial volume as compared to the prior year
due to the COVID-19 pandemic related shutdowns;
•Higher Montana electric supply costs as compared with the prior period;
•An unfavorable adjustment to our electric QF liability (unrecoverable costs
associated with Public Utility Regulatory Policies Act of 1978 (PURPA) contracts
as part of a 2002 stipulation with the MPSC and other parties) associated with a
one-time clarification in contract term; and
•A decrease in gas volumes due to warmer summer weather, partly offset by
customer growth.
Three Months Ended
2021 2020 Change % Change
(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 80.9 $ 73.3 $ 7.6 10.4 %
Property and other taxes 43.6 45.3 (1.7) (3.8)
Depreciation and depletion 47.1 44.3 2.8 6.3
$ 171.6 $ 162.9 $ 8.7 5.3 %
32-------------------------------------------------------------------------------- Consolidated operating, general and administrative expenses were$80.9 million for the three months endedSeptember 30, 2021 , as compared with$73.3 million for the three months endedSeptember 30, 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 Employee benefits
$ 3.3
Technology implementation and maintenance 1.8
Generation maintenance 1.3
Write-off of preliminary construction costs 1.2
Travel and training 0.4
Uncollectible accounts (2.7)
Other (0.3)
Change in Items Impacting Net Income 5.0
Operating, General & Administrative Expenses Offset Within Net Income Pension and other postretirement benefits, offset in other income
1.2
Non-employee directors deferred compensation, offset in other income
1.1
Operating expenses recovered in trackers, offset in revenue 0.3
Change in Operating, General & Administrative Expense Items Offset Within Net Income
2.6
Increase in Operating, General & Administrative Expenses $ 7.6
Consolidated operating, general and administrative expenses increased
The change in consolidated operating, general and administrative expenses for items impacting net income includes the following: •Higher employee benefit costs primarily due to higher compensation and medical costs; •Higher technology implementation and maintenance costs; •Higher maintenance costs at our electric generation facilities; •Higher costs due to the write-off of preliminary construction costs associated with the 30-40MW flexible natural gas plant nearAberdeen, South Dakota ; •Higher travel and training costs; and •Decreased uncollectible accounts due to collections of previously written off amounts in the current period. In the second quarter of 2020, we voluntarily suspended service disconnections for non-payment, to help customers who may be financially impacted by the COVID-19 pandemic. We subsequently resumed standard disconnection processes in all of our operating jurisdictions in the third quarter of 2020. Property and other taxes were$43.6 million for the three months endedSeptember 30, 2021 , as compared with$45.3 million in the same period of 2020. This decrease was due primarily to a decrease in estimatedMontana 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$47.1 million for the three months endedSeptember 30, 2021 , as compared with$44.3 million in the same period of 2020. This increase was primarily due to plant additions. Consolidated operating income for the three months endedSeptember 30, 2021 was$55.7 million as compared with$49.7 million in the same period of 2020. This increase was primarily driven by higherMontana transmission loads and rates and 33 -------------------------------------------------------------------------------- warmer summer weather, partly offset by higher operating costs, higherMontana electric supply costs, and an unfavorable QF liability adjustment compared with the prior period. Consolidated interest expense was$23.3 million for the three months endedSeptember 30, 2021 as compared with$23.7 million for the same period of 2020. This decrease was primarily due to higher capitalization of AFUDC, partly offset by higher borrowings. Consolidated other income was$5.3 million for the three months endedSeptember 30, 2021 as compared to$0.8 million during the same period of 2020. This increase includes approximately$2.3 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 an approximately$1.1 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$1.2 million . Consolidated income tax expense for the three months endedSeptember 30, 2021 was$2.5 million as compared to an income tax benefit of$2.7 million in the same period of 2020. Our effective tax rate for the three months endedSeptember 30, 2021 was 6.6% as compared with (10.1)% 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
2021 2020
Income Before Income Taxes $ 37.7 $ 26.8
Income tax calculated at federal statutory rate 7.9 21.0 % 5.6 21.0 %
Permanent or flow-through adjustments:
State income tax, net of federal provisions 0.4 1.1 0.0 0.2
Flow-through repairs deductions (3.5) (9.2) (4.2) (15.7)
Production tax credits (1.9) (5.0) (2.2) (8.2)
Plant and depreciation of flow-through items (0.3) (0.8) 0.1 0.4
Amortization of excess deferred income tax (0.1) (0.3) (0.2) (0.8)
Share-based compensation (0.1) (0.2) - -
Income tax return to accrual adjustment 0.4 1.0 (1.7) (6.5)
Other, net (0.3) (1.0) (0.1) (0.5)
(5.4) (14.4) (8.3) (31.1)
Income tax expense (benefit) $ 2.5 6.6 % $ (2.7) (10.1) %
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.
Nine Months Ended
Consolidated net income for the nine months endedSeptember 30, 2021 was$135.5 million as compared with$101.7 million for the same period in 2020. This increase was primarily driven by higherMontana transmission loads and rates, a favorable electric QF liability adjustment as compared with the prior period, favorable weather, and higher commercial demand as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by higherMontana electric supply costs, higher operating costs, depreciation expense, and income tax expense. Consolidated operating revenues for the nine months endedSeptember 30, 2021 were$1,025.0 million as compared with$885.2 million for the same period in 2020. Consolidated gross margin for the nine months endedSeptember 30, 2021 was$713.8 million as compared with$664.8 million for the same period in 2020, an increase of$49.0 million . 34 --------------------------------------------------------------------------------
Electric Natural Gas Total
2021 2020 2021 2020 2021 2020
(dollars in millions)
Reconciliation of operating revenue to gross
margin:
Operating Revenues $ 799.0 $ 706.7 $ 226.0 $ 178.5 $ 1,025.0 $ 885.2
Cost of Sales 218.8 173.3 92.4 47.1 311.2 220.4
Gross Margin(1) $ 580.2 $ 533.4 $ 133.6 $ 131.4 $ 713.8 $ 664.8 (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Nine Months Ended September 30,
2021 2020 Change % Change
(dollars in millions)
Gross Margin
Electric $ 580.2 $ 533.4 $ 46.8 8.8 %
Natural Gas 133.6 131.4 2.2 1.7
Total Gross Margin(1) $ 713.8 $ 664.8 $ 49.0 7.4 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Primary components of the change in gross margin include the following (in millions):
Gross Margin 2021 vs. 2020
Gross Margin Items Impacting Net Income
Montana electric transmission revenue $ 21.3
Electric retail volumes 18.1
Electric QF liability adjustment 4.8
Natural gas retail volumes 1.7
Montana electric supply cost recovery (4.3)
Montana natural gas production rates (0.8)
Other 4.3
Change in Gross Margin Impacting Net Income 45.1
Gross Margin Items Offset Within Net Income
Production tax credits reducing revenue, offset in income tax expense 2.2
Property taxes recovered in revenue, offset in property tax expense
1.0
Gas production taxes recovered in revenue, offset in property and other taxes
0.4
Operating expenses recovered in revenue, offset in operating expense
0.3
Change in Gross Margin Items Offset Within Net Income 3.9
Increase in Consolidated Gross Margin(1) $ 49.0
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Consolidated gross margin increased$49.0 million , including a$45.1 million increase from items impacting net income and a$3.9 million increase from items offset within net income.
The change in consolidated gross margin for items impacting net income includes the following:
•Higher Montana transmission rates, the recognition of approximately$4.7 million of deferred interim revenues, and higher demand to transmit energy across our transmission lines due to market conditions and pricing; •An increase in electric retail revenue driven by colder winter weather inMontana , warmer summer weather in bothMontana andSouth Dakota , customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer winter weather inSouth Dakota ; 35 -------------------------------------------------------------------------------- •A more favorable adjustment of our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflecting a$7.9 million gain in 2021, as compared with a$3.1 million gain for the same period in 2020, due to the combination of: •A$2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a$0.9 million favorable reduction in costs in the prior period; •A negative adjustment, increasing the QF liability by$2.1 million , reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of$2.2 million in the prior year due to lower actual price escalation; and •A favorable adjustment of approximately$7.4 million decreasing the QF liability associated with a one-time clarification in contract term. •An increase in natural 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 warmer summer weather in all jurisdictions; •Higher Montana electric supply costs as compared with the prior period; and •A reduction of rates from the step down of ourMontana gas production assets.
Nine Months Ended
2021 2020 Change % Change
(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 238.9 $ 224.0 $ 14.9 6.7 %
Property and other taxes 138.3 136.8 1.5 1.1
Depreciation and depletion 140.9 134.3 6.6 4.9
$ 518.1 $ 495.1 $ 23.0 4.6 %
Consolidated operating, general and administrative expenses were $238.9 million
for the nine months ended September 30, 2021 , as compared with $224.0 million
for the nine months ended September 30, 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 Employee benefits
$ 4.7
Generation maintenance 3.0
Technology implementation and maintenance 2.4
Write-off of preliminary construction costs 1.2
Uncollectible accounts (7.1)
Other 0.4
Change in Items Impacting Net Income 4.6
Operating, General & Administrative Expenses Offset Within Net Income Non-employee directors deferred compensation, offset in other income
6.4
Pension and other postretirement benefits, offset in other income
3.6
Operating expenses recovered in trackers, offset in revenue 0.3
Change in Operating, General & Administrative Expense Items Offset Within Net Income
10.3
Increase in Operating, General & Administrative Expenses $ 14.9
Consolidated operating, general and administrative expenses increased
36
--------------------------------------------------------------------------------The change in consolidated operating, general and administrative expenses for items impacting net income includes the following:
•Higher employee benefit costs primarily due to higher compensation and medical costs; •Higher maintenance costs at our electric generation facilities; •Higher technology implementation and maintenance costs; •Higher costs due to the write-off of preliminary construction costs associated with the 30-40MW flexible natural gas plant nearAberdeen, South Dakota ; and •Decreased uncollectible accounts due to collections of previously written off amounts in the current period. In the second quarter of 2020, we voluntarily suspended service disconnections for non-payment, to help customers who may be financially impacted by the COVID-19 pandemic. Property and other taxes were$138.3 million for the nine months endedSeptember 30, 2021 , as compared with$136.8 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$140.9 million for the nine months endedSeptember 30, 2021 , as compared with$134.3 million in the same period of 2020. This increase was primarily due to plant additions. Consolidated operating income for the nine months endedSeptember 30, 2021 was$195.7 million as compared with$169.7 million in the same period of 2020. This increase was primarily driven by higherMontana transmission loads and rates, a favorable electric QF liability adjustment as compared with the prior period, favorable weather, and higher commercial demand as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by higherMontana electric supply costs, higher operating costs, and depreciation expense. Consolidated interest expense was$70.3 million for the nine months endedSeptember 30, 2021 as compared with$72.3 million for the same period of 2020. This decrease was primarily due to higher capitalization of AFUDC, partly offset by higher borrowings. Consolidated other income was$13.9 million for the nine months endedSeptember 30, 2021 as compared to consolidated other expense of$1.0 million during the same period of 2020. This increase includes approximately$10.0 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 include a$6.4 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$3.6 million . Consolidated income tax expense for the nine months endedSeptember 30, 2021 was$3.9 million as compared to an income tax benefit of$5.2 million in the same period of 2020. Our effective tax rate for the nine months endedSeptember 30, 2021 was 2.8% as compared with (5.4)% 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):
37
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Nine Months Ended
2021 2020
Income Before Income Taxes $ 139.4 $ 96.4
Income tax calculated at federal statutory rate 29.3 21.0 % 20.3 21.0 %
Permanent or flow-through adjustments:
State income tax, net of federal provisions 0.7 0.5 0.1 0.1
Flow-through repairs deductions (15.6) (11.2) (14.9) (15.4)
Production tax credits (8.4) (6.1) (7.6) (7.8)
Plant and depreciation of flow-through items (0.8) (0.6) 0.3 0.3
Amortization of excess deferred income tax (0.6) (0.4) (0.7) (0.8)
Share-based compensation (0.3) (0.2) (0.6) (0.6)
Income tax return to accrual adjustment 0.4 0.3 (1.7) (1.8)
Other, net (0.8) (0.5) (0.4) (0.4)
(25.4) (18.2) (25.5) (26.4)
Income tax expense (benefit) $ 3.9 2.8 % $ (5.2) (5.4) %
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.
38
--------------------------------------------------------------------------------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 Ended
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 85,539 $ 78,549 $ 6,990 8.9 % 692 633 312,265 307,892
South Dakota 18,882 18,912 (30) (0.2) 158 160 50,756 50,584
Residential 104,421 97,461 6,960 7.1 850 793 363,021 358,476
Montana 95,248 89,082 6,166 6.9 847 794 71,766 70,320
South Dakota 28,798 27,373 1,425 5.2 296 284 12,835 12,870
Commercial 124,046 116,455 7,591 6.5 1,143 1,078 84,601 83,190
Industrial 9,147 9,212 (65) (0.7) 611 621 76 78 Other 13,089 11,910 1,179 9.9 89 86 8,226 8,193
6.7 % 2,693 2,578 455,924 449,937
Regulatory amortization 9,922 (5,526) 15,448 (279.6)
Transmission 25,172 12,906 12,266 95.0
Wholesale and Other 1,676 1,737 (61) (3.5)
Total Revenues $ 287,473 $ 244,155 $ 43,318 17.7 %
Total Cost of Sales 89,375 61,154 28,221 46.1
Gross Margin(1) $ 198,098 $ 183,001 $ 15,097 8.2 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Cooling Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 493 340 361 45% warmer 37% warmer
South Dakota 818 755 638 8% warmer 28% warmer
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 251 255 278 2% warmer 10% warmer
South Dakota 23 71 87 68% warmer 74% warmer
39--------------------------------------------------------------------------------
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
Transmission $ 10.1
Retail volumes 8.4
Montana electric supply cost recovery (2.1)
Electric QF liability adjustment (1.3)
Change in Gross Margin Impacting Net Income 15.1
Gross Margin Items Offset Within Net Income
Production tax credits reducing revenue, offset in income tax expense 0.6
Operating expenses recovered in revenue, offset in operating expense
0.4
Property taxes recovered in revenue, offset in property tax expense
(1.0)
Change in Gross Margin Items Offset Within Net Income 0.0
Increase in Gross Margin(1) $ 15.1
(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:
•Higher Montana transmission rates and higher demand to transmit energy across
our transmission lines due to market conditions and pricing;
•An increase in retail revenue due to warmer summer weather, overall customer
growth, and increased commercial volume as compared to the prior year due to the
COVID-19 pandemic related shutdowns;
•Higher Montana electric supply costs as compared with the prior period; and
•An unfavorable adjustment to our electric QF liability (unrecoverable costs
associated with PURPA contracts as part of a 2002 stipulation with the MPSC and
other parties) associated with a one-time clarification in contract term.
The change in regulatory amortization revenue is due to timing differences
between when we incur electric supply costs and when we recover these costs in
rates from our customers, which has a minimal impact on gross margin. Our
wholesale and other revenues are largely gross margin neutral as they are offset
by changes in cost of sales. Our wholesale and other revenues are largely gross
margin neutral as they are offset by changes in cost of sales.
40
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Nine Months Ended
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 251,443 $ 237,777 $ 13,666 5.7 % 2,067 1,944 311,256 306,886
South Dakota 51,031 52,427 (1,396) (2.7) 453 463 50,765 50,629
Residential 302,474 290,204 12,270 4.2 2,520 2,407 362,021 357,515
Montana 266,644 252,514 14,130 5.6 2,398 2,269 71,437 69,949
South Dakota 76,969 77,057 (88) (0.1) 826 818 12,787 12,812
Commercial 343,613 329,571 14,042 4.3 3,224 3,087 84,224 82,761
Industrial 28,086 27,162 924 3.4 1,842 2,026 77 78
Other 26,798 26,400 398 1.5 155 157 6,449 6,467
Total Retail Electric $ 700,971 $ 673,337 $ 27,634 4.1 % 7,741 7,677 452,771 446,821
Regulatory amortization 29,913 (9,274) 39,187 (422.5)
Transmission 63,762 38,409 25,353 66.0
Wholesale and Other 4,338 4,246 92 2.2
Total Revenues $ 798,984 $ 706,718 $ 92,266 13.1 %
Total Cost of Sales 218,802 173,294 45,508 26.3
Gross Margin(1) $ 580,182 $ 533,424 $ 46,758 8.8 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Cooling Degree Days 2020 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 632 395 416 60% warmer 52% warmer
South Dakota 966 844 699 14% warmer 38% warmer
Heating Degree Days 2021 as compared with:
2021 2020 Historic Average 2020 Historic Average
Montana 4,680 4,610 4,725 2% cooler 1% warmer
South Dakota 5,188 5,564 5,648 7% warmer 8% warmer
41--------------------------------------------------------------------------------
The following summarizes the components of the changes in electric gross margin
for the nine months ended
Gross Margin 2021 vs. 2020
Gross Margin Items Impacting Net Income
Transmission $ 21.3
Retail volumes 18.1
Electric QF liability adjustment 4.8
Montana electric supply cost recovery (4.3)
Other 3.2
Change in Gross Margin Impacting Net Income 43.1
Gross Margin Items Offset Within Net Income
Production tax credits reducing revenue, offset in income tax expense 2.2
Property taxes recovered in revenue, offset in property tax expense
0.8
Operating expenses recovered in revenue, offset in operating expense
0.7
Change in Gross Margin Items Offset Within Net Income 3.7
Increase in Gross Margin(1) $ 46.8
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin increased$46.8 million , including a$43.1 million increase from items impacting net income and a$3.7 million increase from items offset within net income.
The change in gross margin for items impacting net income includes the following:
•Higher Montana transmission rates, the recognition of approximately$4.7 million of deferred interim revenues, and higher demand to transmit energy across our transmission lines due to market conditions and pricing; •An increase in retail revenue driven by colder winter weather inMontana , warmer summer weather in bothMontana andSouth Dakota , customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer winter weather inSouth Dakota ; •A more favorable adjustment of our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflecting a$7.9 million gain in 2021, as compared with a$3.1 million gain for the same period in 2020, due to the combination of: •A$2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a$0.9 million favorable reduction in costs in the prior period; •A negative adjustment, increasing the QF liability by$2.1 million , reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of$2.2 million in the prior year due to lower actual price escalation; and •A favorable adjustment of approximately$7.4 million decreasing the QF liability associated with a one-time clarification in contract term. •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. 42 --------------------------------------------------------------------------------
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 EndedSeptember 30, 2021 Compared with the Three Months EndedSeptember 30, 2020 Revenues Change Dekatherms (Dkt) Avg. Customer Counts 2021 2020 $ % 2021 2020 2021 2020 (in thousands) Montana$ 9,910 $ 9,896 14 0.1 % 845 956 179,571 177,410 South Dakota 2,179 1,702 477 28.0 106 114 40,826 40,437 Nebraska 2,443 1,698 745 43.9 144 156 37,406 37,467 Residential 14,532 13,296 1,236 9.3 1,095 1,226 257,803 255,314 Montana 6,110 5,598 512 9.1 603 611 24,872 24,412 South Dakota 1,781 1,030 751 72.9 179 170 6,846 6,864 Nebraska 1,461 684 777 113.6 144 143 4,920 4,945 Commercial 9,352 7,312 2,040 27.9 926 924 36,638 36,221 Industrial 76 51 25 49.0 8 6 227 231 Other 163 92 71 77.2 18 12 168 153Total Retail Gas $ 24,123 $ 20,751 $ 3,372 16.2 % 2,047 2,168 294,836 291,919
Regulatory amortization 5,415 7,265 (1,850) (25.5) Wholesale and other 8,944 8,439 505 6.0 Total Revenues$ 38,482 $ 36,455 $ 2,027 5.6 % Total Cost of Sales 9,284 6,882 2,402 34.9 Gross Margin(1)$ 29,198 $ 29,573 $ (375) (1.3) %
(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 300 306 319 2% warmer 6% warmer
South Dakota 23 71 87 68% warmer 74% warmer
Nebraska 9 40 47 78% warmer 81% warmer
43--------------------------------------------------------------------------------
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 $ (0.6)
Other 0.4
Change in Gross Margin Impacting Net Income (0.2)
Gross Margin Items Offset Within Net Income
Property tax revenue, offset in property tax expense (0.3)
Operating expenses recovered in trackers (0.1)
Gas production taxes recovered in revenue, offset in property and other taxes
0.2
Change in Gross Margin Items Offset Within Net Income (0.2)
Decrease in Gross Margin(1) $ (0.4)
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin decreased$0.4 million , including a$0.2 million decrease for items impacting net income and a$0.2 million decrease from items offset within net income.
The change in gross margin for items impacting net income includes a decrease in gas volumes due to warmer summer weather, partly offset by customer growth.
Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
44
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Nine Months Ended September 30, 2021 Compared with the Nine Months Ended
September 30, 2020
Revenues Change Dekatherms (Dkt) Avg. Customer Counts
2021 2020 $ % 2021 2020 2021 2020
(in thousands)
Montana $ 82,424 $ 65,674 16,750 25.5 % 9,119 8,937 179,340 177,036
South Dakota 18,654 16,697 1,957 11.7 2,248 2,310 40,975 40,509
Nebraska 14,599 12,908 1,691 13.1 1,987 1,984 37,560 37,542
Residential 115,677 95,279 20,398 21.4 13,354 13,231 257,875 255,087
Montana 42,890 32,988 9,902 30.0 4,977 4,674 24,876 24,455
South Dakota 12,562 11,213 1,349 12.0 2,060 2,360 6,873 6,889
Nebraska 7,740 6,284 1,456 23.2 1,397 1,394 4,953 4,973
Commercial 63,192 50,485 12,707 25.2 8,434 8,428 36,702 36,317
Industrial 726 503 223 44.3 88 75 229 231
Other 1,007 612 395 64.5 136 104 164 152
Total Retail Gas $ 180,602 $ 146,879 $ 33,723 23.0 % 22,012 21,838 294,970 291,787
Regulatory amortization 17,951 4,966 12,985 261.5
Wholesale and other 27,438 26,662 776 2.9
Total Revenues $ 225,991 $ 178,507 $ 47,484 26.6 %
Total Cost of Sales 92,335 47,058 45,277 96.2
Gross Margin(1) $ 133,656 $ 131,449 $ 2,207 1.7 %
(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 4,767 4,707 4,857 1% cooler 2% warmer
South Dakota 5,188 5,564 5,648 7% warmer 8% warmer
Nebraska 4,432 4,250 4,646 4% cooler 5% warmer
45--------------------------------------------------------------------------------
The following summarizes the components of the changes in natural gas gross
margin for the nine months ended
Gross Margin 2021 vs. 2020
(in millions)
Gross Margin Items Impacting Net Income
Retail volumes $ 1.7
Montana gas production rates (0.8)
Other 1.1
Change in Gross Margin Impacting Net Income 2.0
0.4
Property tax revenue, offset in property tax expense 0.2
Operating expenses recovered in trackers (0.4)
Change in Gross Margin Items Offset Within Net Income 0.2
Increase in Gross Margin(1) $ 2.2
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.
Gross margin increased$2.2 million , including a$2.0 million increase for items impacting net income and a$0.2 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 warmer summer weather in all jurisdictions; 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.
46
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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 September 30, 2021 , our total net liquidity was approximately $163.6
million , including $8.6 million of cash and $155.0 million of revolving credit
facility availability. As of September 30, 2021 , there were no letters of credit
outstanding and $295.0 million in outstanding borrowings under our credit
facilities. Availability under our credit facilities was $186.0 million as of
October 22, 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 .
In April 2021 , we entered into an Equity Distribution Agreement pursuant to
which we may offer and sell shares of our common stock from time to time, having
an aggregate gross sales price of up to $200.0 million , through an ATM program,
including an equity forward sales component. During the three months ended
September 30, 2021 , we issued 1,040,085 shares of our common stock at an average
price of $63.13 , for net proceeds of $64.8 million , which is net of sales
commissions and other fees paid of approximately $0.9 million . During the nine
months ended September 30, 2021 , we issued 1,919,394 shares of our common stock
at an average price of $63.94 , for net proceeds of $121.1 million , which is net
of sales commissions and other fees paid of approximately $1.7 million . We
expect a total of approximately $200.0 million of equity proceeds during 2021 to
support our current capital program and maintain and protect our credit ratings.
Financing plans are subject to change, depending on capital expenditures,
regulatory outcomes, internal cash generation, market conditions and other
factors.
47
--------------------------------------------------------------------------------Factors Impacting our Liquidity
Energy 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 purchased natural gas rate tracker adjustment and a quarterly electric fuel cost rate tracker 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 ofSeptember 30, 2021 , we have under collected our costs recovered through tracking mechanisms by approximately$84.5 million . We under collected our costs by approximately$5.7 million as ofDecember 31, 2020 and under collected our costs by approximately$20.5 million as ofSeptember 30, 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 ofOctober 22, 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.
48
--------------------------------------------------------------------------------Cash Flows
The following table summarizes our consolidated cash flows (in millions):
Nine Months Ended
2021 2020
Operating Activities
Net income $ 135.5 $ 101.7
Non-cash adjustments to net income 148.7 135.0
Changes in working capital (31.0) 99.1
Other noncurrent assets and liabilities (31.6) (13.3)
Cash Provided by Operating Activities 221.6 322.5
Investing Activities
Property, plant and equipment additions (311.2) (283.0)
Investment in equity securities (0.6) -
Cash Used in Investing Activities (311.8) (283.0)
Financing Activities
Proceeds from issuance of common stock, net 121.1 - Issuance of long-term debt, net 99.9 150.0 (Repayments) issuance of short-term borrowings (100.0) 100.0 Repayments of long-term debt (1.0) - Line of credit borrowings (repayments), net 73.0 (193.0) Dividends on common stock (95.1) (90.3) Financing costs (0.9) (2.6) Other 0.3 (1.7) Cash Provided by (Used in) Financing Activities 97.3 (37.6) Increase in Cash, Cash Equivalents, and Restricted Cash 7.1 1.9 Cash, Cash Equivalents, and Restricted Cash, beginning of period 17.1 12.1 Cash, Cash Equivalents, and Restricted Cash, end of period $
24.2
Cash Provided by Operating Activities
As ofSeptember 30, 2021 , cash, cash equivalents, and restricted cash were$24.2 million as compared with$17.1 million as ofDecember 31, 2020 and$14.0 million as ofSeptember 30, 2020 . Cash provided by operating activities totaled$221.6 million for the nine months endedSeptember 30, 2021 as compared with$322.5 million during the nine months endedSeptember 30, 2020 . This decrease in operating cash flows is primarily due to a$106.7 million ($65.1 million from electric operations and$41.6 million from natural gas operations) net increase in under collection of energy supply costs from customers in the current period, and a refund of approximately$20.5 million to ourFERC regulated customers. These reductions were offset in part by an improvement in net income.
Cash Used in Investing Activities
Cash used in investing activities increased by approximately$28.8 million as compared with the first nine months of 2020. Plant additions during the first nine months of 2021 include maintenance additions of approximately$230.7 million and capacity related capital expenditures of$80.5 million . Plant additions during the first nine months of 2020 included maintenance additions of approximately$192.4 million and capacity related capital expenditures of approximately$90.6 million .
Cash Provided by (Used in) Financing Activities
Cash provided by financing activities totaled
49
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months ended September 30, 2021 , cash provided by financing activities reflects
proceeds received from the issuance of common stock pursuant to our ATM program
of $121.1 million , net proceeds from the issuance of debt of $99.9 million , and
net issuances under our revolving lines of credit of $73.0 million , offset in
part by repayments of our short-term borrowings of $100.0 million and payment of
dividends of $95.1 million . During the nine months ended September 30, 2020 , net
cash used in financing activities reflects net repayments under our revolving
lines of credit of $193.0 million and dividends of $90.3 million , offset in part
by proceeds from the issuance of debt of $150.0 million and short-term
borrowings of $100.0 million .
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 ofSeptember 30, 2021 , there have been two significant revisions made to our estimated capital expenditures discussed in our Annual Report on Form 10-K for the year endedDecember 31, 2020 . We have decided not to proceed with the construction of an approximately$60 million 30-40 MW flexible natural gas plant nearAberdeen, South Dakota that was previously included in our estimated Electric segment capital expenditures with an expected in service date in early 2024. Additionally, we are moving forward with construction of the 175MW Laurel Generating Station natural gas plant, which is estimated to cost approximately$275 million , including capitalized AFUDC, which was not included in our estimated electric segment capital expenditures. This project is expected to be in service byJanuary 2024 .
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as ofSeptember 30, 2021 . See our Annual Report on Form 10-K for the year endedDecember 31, 2020 for additional discussion. Total 2021 2022 2023 2024 2025 Thereafter (in thousands) Long-term debt (1)$ 2,474,660 $ - $ -$ 439,660 $ 100,000 $ 300,000 $ 1,635,000 Finance leases 15,463 692 2,875 3,097 3,338 3,596 1,865 Estimated pension and other postretirement obligations (2) 52,221 1,428 12,905 12,905 12,492 12,491 N/A Qualifying facilities liability (3) 485,786 19,527 80,355 82,452 74,806 60,054 168,592 Supply and capacity contracts (4) 2,639,374 80,300 241,819 264,729 221,282 216,071
1,615,173
Contractual interest payments on debt (5) 1,501,841 21,838 87,352 85,386 79,760 70,791
1,156,714
Total Commitments (6)
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(1)Represents cash payments for long-term debt and excludes$11.6 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$48 to$136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately$485.8 million . A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately$403.4 million . (4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years and exclude contract payments associated with the Beartooth Battery agreement, which is subject to approval by the MPSC. 50 -------------------------------------------------------------------------------- (5)Contractual interest payments include 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 as ofSeptember 30, 2021 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. 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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