Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.
We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow 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 Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
OVERVIEW
NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 775,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.
We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:
• Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
• Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.
• 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 to continue to attract cost-effective capital for future investment.
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.
We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050.
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 ended March 31, 2024 and 2023.
19
HOW WE PERFORMED AGAINST OUR FIRST QUARTER 2023 RESULTS
Three Months Ended
March 31, 2024 vs. 2023
Income Before Income Taxes Income Tax Expense (3)
Net Income
(in millions)
First Quarter, 2023 $ 72.7 $ (10.2) $ 62.5
Variance in revenue and fuel, purchased supply, and direct transmission expense (1) items impacting net income:
New base rates 19.8 (5.0) 14.8
Higher electric transmission revenue 3.5 (0.9) 2.6
Montana property tax tracker collections 0.9 (0.2) 0.7
Higher non-recoverable Montana electric supply costs due to higher electric supply costs (3.5) 0.9 (2.6)
Lower natural gas retail volumes (3.5) 0.9 (2.6)
Lower electric retail volumes (3.2) 0.8 (2.4)
Lower revenue from higher production tax credits, offset within income tax benefit (0.5) 0.5 —
Other 0.1 0.0 0.1
Variance in expense items (2) impacting net income:
Higher operating, maintenance, and administrative expenses
(4.3) 1.1 (3.2)
Higher depreciation expense (3.5) 0.9 (2.6)
Higher interest expense (3.0) 0.8 (2.2)
Higher property and other taxes not recoverable within trackers (0.4) 0.1 (0.3)
Other 0.3 0.0 0.3
First Quarter, 2024 $ 75.4 $ (10.3) $ 65.1
Change in Net Income $ 2.6
(1) Exclusive of depreciation and depletion shown separately below
(2) Excluding fuel, purchased supply, and direct transmission expense
(3) Income tax expense calculation on reconciling items assumes a blended federal plus state effective tax rate of 25.3 percent.
Consolidated net income for the three months ended March 31, 2024 was $65.1 million as compared with $62.5 million for the same period in 2023. This increase was primarily due to new base rates resulting from the Montana and South Dakota rate reviews, higher transmission revenues, and higher Montana property tax tracker collection, partly offset by lower electric and natural gas retail volumes, higher non-recoverable Montana electric supply costs, higher depreciation and depletion expense, higher operating, maintenance, and administrative expenses, and higher interest expense.
SIGNIFICANT TRENDS AND REGULATION
Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2023 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows:
Yellowstone County 175 MW plant
Construction of the new generation facility continues to progress and we expect the plant to be operational by the end of the third quarter 2024. The lawsuit challenging the Yellowstone County Generating Station (YCGS) air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and have increased costs. As of March 31, 2024, total costs of approximately $267.5 million have been incurred, with expected total costs of approximately $310.0 million to $320.0 million. See Note 10 - Commitments and Contingencies to the Condensed Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.
20
Montana Rate Review
We anticipate filing a Montana electric and natural gas rate review with the MPSC in the third quarter of 2024 based on a 2023 test year. Within this rate review filing we also anticipate a prudence review of the Yellowstone County Generating Station.
Power Costs and Credits Adjustment Mechanism (PCCAM)
As of March 31, 2024, we have under-collected our total Montana electric supply costs for the July 2023 through June 2024 PCCAM year by approximately $24.0 million. The significant increase to our under-collected costs during the three months ended March 31, 2024 was driven by a January cold weather event in our service territory. We also remained under-collected for the July 2022 through June 2023 PCCAM year by approximately $8.5 million, which we expect to recover within rates by June 2024. We submit quarterly and annual PCCAM filings with the MPSC to recover, or refund, under- or over-collected Montana electric supply costs. PCCAM rates are being adjusted through the quarterly filings to provide a more timely recovery of deferred balances instead of annual recovery.
Under the PCCAM, net costs higher or lower than the PCCAM Base (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the three months ended March 31, 2024, we under-collected supply costs of $27.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $3.0 million (10 percent of the PCCAM Base cost variance). For the three months ended March 31, 2023, we over-collected costs of $4.3 million resulting in a decrease to the under collection of costs, and recorded an increase in pre-tax earnings of $0.5 million.
Our electric supply from owned and long-term contracted resources is not adequate to meet our peak-demand needs. Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows. The construction of the Yellowstone County Generating Station and acquisition of Avista's Colstrip Units 3 and 4 interests are expected to reduce our exposure to market purchases.
EPA Rules
Draft GHG emission standards for existing coal-fired facilities and new coal and natural gas-fired facilities, including enhanced MATS rules, were released by the EPA in the second quarter of 2023. Our review of these draft rules indicated they would require potentially expensive upgrades at Colstrip Units 3 and 4 to comply, with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. On April 25, 2024, the EPA released final rules related to GHG emission standards for existing coal-fired facilities and new coal and natural gas-fired facilities as well as final rules strengthening the MATS requirements. The final MATS and GHG Rules will require compliance as early as 2028 and 2032, respectively. We are evaluating how the final MATS and GHG Rules may impact our coal-fired generation facilities and operations.
21
RESULTS OF OPERATIONS
Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.
Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.
Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.
Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.
OVERALL CONSOLIDATED RESULTS
Three Months Ended March 31, 2024 Compared with the Three Months Ended March 31, 2023
Consolidated net income for the three months ended March 31, 2024 was $65.1 million as compared with $62.5 million for the same period in 2023. This increase was primarily due to new base rates resulting from the Montana and South Dakota rate reviews, higher transmission revenues, and higher Montana property tax tracker collection, partly offset by lower electric and natural gas retail volumes, higher non-recoverable Montana electric supply costs, higher depreciation and depletion expense, higher operating, maintenance, and administrative expenses, and higher interest expense.
Consolidated gross margin for the three months ended March 31, 2024 was $142.5 million as compared with $130.7 million in 2023, an increase of $11.8 million, or 9.0 percent. This increase was primarily due to new base rates resulting from the Montana and South Dakota rate reviews, higher transmission revenues, and higher Montana property tax tracker collections, partly offset by lower electric and natural gas retail volumes, higher non-recoverable Montana electric supply costs, and higher depreciation and depletion expense.
22
Electric Natural Gas Total
2024 2023 2024 2023 2024 2023
(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues $ 343.2 $ 295.3 $ 132.1 $ 159.2 $ 475.3 $ 454.5
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 115.3 78.1 59.4 87.4 174.7 165.5
Less: Operating and maintenance 40.3 42.4 13.9 13.5 54.2 55.9
Less: Property and other taxes 36.3 38.3 10.9 10.9 47.2 49.2
Less: Depreciation and depletion 47.3 43.9 9.4 9.3 56.7 53.2
Gross Margin 104.0 92.6 38.5 38.1 142.5 130.7
Operating and maintenance 40.3 42.4 13.9 13.5 54.2 55.9
Property and other taxes 36.3 38.3 10.9 10.9 47.2 49.2
Depreciation and depletion 47.3 43.9 9.4 9.3 56.7 53.2
Utility Margin (1)
$ 227.9 $ 217.2 $ 72.7 $ 71.8 $ 300.6 $ 289.0
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Three Months Ended March 31,
2024 2023 Change % Change
(dollars in millions)
Utility Margin
Electric $ 227.9 $ 217.2 $ 10.7 4.9 %
Natural Gas 72.7 71.8 0.9 1.3
Total Utility Margin (1)
$ 300.6 $ 289.0 $ 11.6 4.0 %
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated utility margin for the three months ended March 31, 2024 was $300.6 million as compared with $289.0 million for the same period in 2023, an increase of $11.6 million, or 4.0 percent.
23
Primary components of the change in utility margin include the following (in millions):
Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
New base rates $ 19.8
Higher transmission revenue due to market conditions 3.5
Montana property tax tracker collections 0.9
Higher Montana natural gas transportation 0.2
Higher non-recoverable Montana electric supply costs due to higher electric supply costs (3.5)
Lower natural gas retail volumes (3.5)
Lower electric retail volumes (3.2)
Other (0.1)
Change in Utility Margin Items Impacting Net Income 14.1
Utility Margin Items Offset Within Net Income
Lower property and other taxes recovered in revenue, offset in property and other taxes
(2.4)
Lower revenue from higher production tax credits, offset in income tax expense (0.5)
Higher operating expenses recovered in revenue, offset in operating and maintenance expense 0.4
Change in Utility Margin Items Offset Within Net Income (2.5)
Increase in Consolidated Utility Margin (1)
$ 11.6
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Lower electric retail volumes were driven by unfavorable weather in Montana and South Dakota impacting residential demand and lower commercial demand, partly offset by customer growth. Lower natural gas retail volumes were driven by unfavorable weather in Montana and South Dakota impacting residential and commercial demand.
Three Months Ended March 31,
2024 2023 Change % Change
(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance $ 54.2 $ 55.9 $ (1.7) (3.0) %
Administrative and general 40.4 34.7 5.7 16.4
Property and other taxes 47.2 49.2 (2.0) (4.1)
Depreciation and depletion 56.7 53.2 3.5 6.6
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 198.5 $ 193.0 $ 5.5 2.8 %
24
Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $198.5 million for the three months ended March 31, 2024, as compared with $193.0 million for the three months ended March 31, 2023. Primary components of the change include the following (in millions):
Operating Expenses
2024 vs. 2023
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Higher depreciation expense due to plant additions and higher depreciation rates $ 3.5
Litigation outcome (Pacific Northwest Solar)
2.4
Non-cash impairment of alternative energy storage investment
2.2
Higher labor and benefits (1)
1.6
Higher insurance expense 0.5
Higher property and other taxes not recoverable within trackers 0.4
Lower expenses at our electric generation facilities (2.6)
Other 0.2
Change in Items Impacting Net Income 8.2
Operating Expenses Offset Within Net Income
Lower property and other taxes recovered in trackers, offset in revenue
(2.4)
Pension and other postretirement benefits, offset in other income (1)
(0.9)
Higher operating and maintenance expenses recovered in trackers, offset in revenue 0.4
Higher deferred compensation, offset in other income 0.2
Change in Items Offset Within Net Income (2.7)
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 5.5
(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.
We estimate property taxes throughout each year, and update those estimates based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases and decreases in the actual level of state and local taxes and fees and adjust our rates to recover the increase or decrease between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
Consolidated operating income for the three months ended March 31, 2024 was $102.1 million as compared with $96.0 million in the same period of 2023. This increase was primarily driven by new base rates resulting from the Montana and South Dakota rate reviews, higher transmission revenues, and higher Montana property tax tracker collections, partly offset by lower electric and natural gas retail volumes, higher non-recoverable Montana electric supply costs, higher depreciation and depletion expense, and higher operating, administrative and general expenses.
Consolidated interest expense was $31.0 million for the three months ended March 31, 2024 as compared with $28.0 million for the same period of 2023. This increase was due to higher interest on long term debt partly offset by lower interest on our revolving credit facilities and higher capitalization of Allowance for Funds Used During Construction (AFUDC).
Consolidated other income was $4.3 million for the three months ended March 31, 2024 as compared with $4.7 million for the same period of 2023. This decrease was primarily due to a $2.5 million non-cash impairment of an alternative energy storage equity investment and an increase in the non-service component of pension expense, partly offset by a $2.3 million reversal of a previously expensed Community Renewable Energy Project penalty due to a favorable legal ruling and higher capitalization of AFUDC.
Consolidated income tax expense was $10.3 million for the three months ended March 31, 2024 as compared to $10.2 million for the same period of 2023. Our effective tax rate for the three months ended March 31, 2024 was 13.7% as compared with 14.1% for the same period in 2023.
25
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
Three Months Ended March 31,
2024 2023
Income Before Income Taxes $ 75.4 $ 72.7
Income tax calculated at federal statutory rate 15.8 21.0 % 15.3 21.0 %
Permanent or flow-through adjustments:
State income tax, net of federal provisions 0.6 0.9 1.0 1.3
Flow-through repairs deductions (6.1) (8.2) (5.8) (8.0)
Production tax credits (3.0) (4.0) (3.2) (4.4)
Amortization of excess deferred income tax (0.4) (0.5) (0.8) (1.1)
Plant and depreciation flow-through items 3.1 4.1 0.7 0.9
Share-based compensation 0.3 0.4 0.4 0.5
Reduction to previously claimed alternative minimum tax credit — — 3.2 4.4
Other, net 0.0 0.0 (0.6) (0.5)
(5.5) (7.3) (5.1) (6.9)
Income tax expense $ 10.3 13.7 % $ 10.2 14.1 %
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.
26
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 fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
• Transmission: Reflects transmission revenues regulated by the FERC.
• Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.
Three Months Ended March 31, 2024 Compared with the Three Months Ended March 31, 2023
Revenues Change Megawatt Hours (MWH) Avg. Customer Counts
2024 2023 $ % 2024 2023 2024 2023
(in thousands)
Montana $ 117,363 $ 125,462 $ (8,099) (6.5) % 847 871 326,317 320,739
South Dakota 19,310 19,771 (461) (2.3) 173 195 51,451 51,276
Residential 136,673 145,233 (8,560) (5.9) 1,020 1,066 377,768 372,015
Montana 101,503 112,613 (11,110) (9.9) 824 851 75,676 74,262
South Dakota 27,773 25,128 2,645 10.5 287 279 13,011 12,942
Commercial 129,276 137,741 (8,465) (6.1) 1,111 1,130 88,687 87,204
Industrial 11,669 11,841 (172) (1.5) 725 626 79 78
Other 4,816 5,254 (438) (8.3) 13 15 4,920 4,859
Total Retail Electric $ 282,434 $ 300,069 $ (17,635) (5.9) % 2,869 2,837 471,454 464,156
Regulatory amortization 36,346 (25,297) 61,643 (243.7)
Transmission 22,387 18,893 3,494 18.5
Wholesale and Other 2,019 1,643 376 22.9
Total Revenues $ 343,186 $ 295,308 $ 47,878 16.2 %
Fuel, purchased supply and direct transmission expense (1)
115,341 78,134 37,207 47.6
Utility Margin (2)
$ 227,845 $ 217,174 $ 10,671 4.9 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Heating Degree Days 2024 as compared with:
2024 2023 Historic Average 2023 Historic Average
Montana (1)
3,338 3,539 3,336 6% warmer remained flat
South Dakota 3,475 4,344 4,188 20% warmer 17% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
27
The following summarizes the components of the changes in electric utility margin for the three months ended March 31, 2024 and 2023 (in millions):
Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
New base rates $ 14.9
Higher transmission revenue due to market conditions 3.5
Montana property tax tracker collections 2.0
Lower retail volumes (3.2)
Higher non-recoverable Montana electric supply costs due to higher electric supply costs (3.5)
Other (0.3)
Change in Utility Margin Items Impacting Net Income 13.4
Utility Margin Items Offset Within Net Income
Lower property and other taxes recovered in revenue, offset in property and other taxes
(2.5)
Lower revenue from higher production tax credits, offset in income tax expense (0.5)
Higher operating expenses recovered in revenue, offset in operating and maintenance expense 0.3
Change in Utility Margin Items Offset Within Net Income (2.7)
Increase in Utility Margin (1)
$ 10.7
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Lower retail volumes were driven by unfavorable weather in Montana and South Dakota impacting residential demand and lower commercial demand, partly offset by customer growth.
The change in regulatory amortization revenue is primarily due to timing differences between when we incur electric supply costs and property taxes and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
28
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 fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
• Wholesale: Primarily represents transportation and storage for others.
Three Months Ended March 31, 2024 Compared with the Three Months Ended March 31, 2023
Revenues Change Dekatherms (Dkt) Avg. Customer Counts
2024 2023 $ % 2024 2023 2024 2023
(in thousands)
Montana $ 48,590 $ 66,882 $ (18,292) (27.3) % 6,257 6,517 185,216 183,500
South Dakota 13,605 19,935 (6,330) (31.8) 1,437 1,752 42,602 42,150
Nebraska 10,517 20,513 (9,996) (48.7) 1,231 1,407 38,050 37,965
Residential 72,712 107,330 (34,618) (32.3) 8,925 9,676 265,868 263,615
Montana 25,083 36,339 (11,256) (31.0) 3,397 3,687 26,083 25,666
South Dakota 9,267 14,286 (5,019) (35.1) 1,314 1,502 7,371 7,252
Nebraska 6,218 13,163 (6,945) (52.8) 861 999 5,082 5,076
Commercial 40,568 63,788 (23,220) (36.4) 5,572 6,188 38,536 37,994
Industrial 419 729 (310) (42.5) 60 75 236 231
Other 575 796 (221) (27.8) 89 93 195 188
Total Retail Gas $ 114,274 $ 172,643 $ (58,369) (33.8) % 14,646 16,032 304,835 302,028
Regulatory amortization 6,926 (25,401) 32,327 127.3
Wholesale and other 10,956 11,992 (1,036) (8.6)
Total Revenues $ 132,156 $ 159,234 $ (27,078) (17.0) %
Fuel, purchased supply and direct transmission expense (1)
59,380 87,358 (27,978) (32.0)
Utility Margin (2)
$ 72,776 $ 71,876 $ 900 1.3 %
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Heating Degree Days 2024 as compared with:
2024 2023 Historic Average 2023 Historic Average
Montana (1)
3,380 3,592 3,333 6% warmer 1% colder
South Dakota 3,475 4,344 4,188 20% warmer 17% warmer
Nebraska 2,993 3,364 3,349 11% warmer 11% warmer
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
29
The following summarizes the components of the changes in natural gas utility margin for the three months ended March 31, 2024 and 2023:
Utility Margin 2023 vs. 2022
(in millions)
Utility Margin Items Impacting Net Income
New base rates $ 4.9
Higher Montana natural gas transportation 0.2
Lower retail volumes (3.5)
Montana property tax tracker collections (1.1)
Other 0.2
Change in Utility Margin Items Impacting Net Income 0.7
Utility Margin Items Offset Within Net Income
Higher property and other taxes recovered in revenue, offset in property and other taxes
0.1
Higher operating expenses recovered in revenue, offset in operating and maintenance expense 0.1
Change in Utility Margin Items Offset Within Net Income 0.2
Increase in Utility Margin (1)
$ 0.9
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Lower retail volumes were driven by unfavorable weather in all jurisdictions impacting residential and commercial demand, partly offset by customer growth.
30
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 16 - Common Stock in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 for further information regarding these dividend restrictions. As of March 31, 2024, we are in compliance with these provisions.
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.
As of March 31, 2024, our total net liquidity was approximately $418.2 million, including $4.2 million of cash and $414.0 million of revolving credit facility availability with no letters of credit outstanding.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
Three Months Ended March 31,
2024 2023
Operating Activities
Net income $ 65.1 $ 62.5
Non-cash adjustments to net income 69.4 43.8
Changes in working capital 33.4 107.8
Other noncurrent assets and liabilities (6.2) (0.4)
Cash Provided by Operating Activities 161.7 213.7
Investing Activities
Property, plant and equipment additions (108.8) (136.6)
Investment in equity securities (0.2) —
Cash Used in Investing Activities (109.0) (136.6)
Financing Activities
Issuance of long-term debt 215.0 220.0
Line of credit repayments, net (132.0) (253.0)
Repayments on long-term debt (100.0) —
Dividends on common stock (39.6) (38.0)
Other financing activities, net (0.9) (1.5)
Cash Used in Financing Activities (57.5) (72.5)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash (4.8) 4.6
Cash, Cash Equivalents, and Restricted Cash, beginning of period 25.2 22.5
Cash, Cash Equivalents, and Restricted Cash, end of period $ 20.4 $ 27.1
Operating Activities
As of March 31, 2024, cash, cash equivalents, and restricted cash were $20.4 million as compared with $25.2 million as of December 31, 2023 and $27.1 million as of March 31, 2023. Cash provided by operating activities totaled $161.7 million for the three months ended March 31, 2024 as compared with $213.7 million during the three months ended March 31, 2023. As
31
shown in the table below, this decrease in operating cash flows is primarily due to an increase in our under collection of energy supply costs for the three months ended March 31, 2024, compared to a decrease in our under collection of energy supply costs for the same period in 2023. The increase in uncollected energy supply costs for the three months ended March 31, 2024, was due to a January 2024 cold weather event.
Uncollected energy supply costs (in millions)
Beginning of period End of period Net cash inflows (outflows)
2023 $ 115.4 $ 66.5 $ 48.9
2024 $ 7.8 $ 40.4 $ (32.6)
Decrease in net cash inflows $ (81.5)
Investing Activities
Cash used in investing activities totaled $109.0 million during the three months ended March 31, 2024, as compared with $136.6 million during the three months ended March 31, 2023. Plant additions during the first three months of 2024 include maintenance additions of approximately $49.2 million and capacity related capital expenditures of $59.6 million. Plant additions during the first three months of 2023 included maintenance additions of approximately $83.1 million and capacity related capital expenditures of approximately $53.5 million.
Financing Activities
Cash used in financing activities totaled $57.5 million during the three months ended March 31, 2024, as compared with $72.5 million during the three months ended March 31, 2023. During the three months ended March 31, 2024, cash used in financing activities reflects net repayments under our revolving lines of credit of $132.0 million, repayment of 1.00 percent, $100.0 million of Montana First Mortgage Bonds, and payment of dividends of $39.6 million, partly offset by proceeds from the issuance of debt of $215.0 million. During the three months ended March 31, 2023, cash used in financing activities reflects net repayments under our revolving lines of credit of $253.0 million and payment of dividends of $38.0 million, partly offset by proceeds from the issuance of debt of $220.0 million.
Cash Requirements and Capital Resources
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.
Our material cash requirements are also related to investment in our business through our capital expenditure program. Our estimated capital expenditures are discussed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As of March 31, 2024, there have been no material changes in our estimated capital expenditures. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
Credit Facilities
Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.
32
For further information on our credit facilities, see Note 10 - Unsecured Credit Facilities in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 .
As of March 31, 2024 and 2023 the outstanding balances of our credit facilities were $186.0 million and $197.0 million, respectively. As of April 19, 2024, the availability under our credit facilities was approximately $529.0 million, and there were no letters of credit outstanding.
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities.
For further information on our recent long-term debt activity, see Note 5 - Financing Activities to the Condensed Consolidated Financial Statements included herein.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of April 19, 2024, our current ratings with these agencies are as follows:
Issuer Rating Senior Secured Rating Senior Unsecured Rating Outlook
NorthWestern Energy Group
Fitch (1)(2)
BBB - BBB Stable
Moody’s - - - -
S&P (2)
BBB - - Stable
NW Corp
Fitch (1)(2)
BBB A- BBB+ Stable
Moody’s (2)
Baa2 A3 Baa2 Stable
S&P (2)
BBB A- - Stable
NWE Public Service
Fitch (1)(2)
BBB A- BBB+ Stable
Moody’s (2)
Baa2 A3 - Stable
S&P (2)
BBB A- - Stable
(1) This Fitch Issuer Rating represents the Issuer Default Rating.
(2) As part of completing the holding company reorganization, NorthWestern Energy Group and NWE Public Service received their credit ratings from these agencies in December 2023. These agencies also affirmed their ratings for NW Corp.
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.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of March 31, 2024.
33
Total 2024 2025 2026 2027 2028 Thereafter
(in thousands)
Long-term debt (1)
$ 2,780,660 $ — $ 300,000 $ 105,000 $ — $ 365,660 $ 2,010,000
Finance leases 7,996 2,535 3,596 1,865 — — —
Estimated pension and other postretirement obligations (2)
57,063 12,215 11,437 11,137 11,137 11,137 N/A
Qualifying facilities liability (3)
284,535 55,583 60,360 55,393 56,665 42,400 14,134
Supply and capacity contracts (4)
3,418,292 257,795 289,569 297,364 277,189 259,089 2,037,286
Contractual interest payments on debt (5)
1,608,248 92,784 117,702 111,612 109,952 107,096 1,069,102
Commitments for significant capital projects (6)
40,865 35,082 5,783 — — — —
Total Commitments (7)
$ 8,197,659 $ 455,994 $ 788,447 $ 582,371 $ 454,943 $ 785,382 $ 5,130,522
_________________________
(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 $67 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $284.5 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $251.3 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. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC.
(5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 6.82 percent on the outstanding balance through maturity of the facilities.
(6) Represents significant firm purchase commitments for construction of planned capital projects.
(7) The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 10 - Commitments and Contingencies ) and asset retirement obligations as the amount and timing of cash payments may be uncertain.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our 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 and income taxes. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 . As of March 31, 2024, there have been no material changes in these policies.
34
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.