Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our financial condition and results of operations together with our financial statements and the related notes appearing under Item 8 of this Form 10-K.
OVERVIEW
Otter Tail Corporation and its subsidiaries form a diverse group of businesses with operations classified into three segments: Electric, Manufacturing and Plastics. Our Electric business is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve our customers in western Minnesota, eastern North Dakota and northeastern South Dakota. Our Manufacturing segment provides metal fabrication for custom machine parts and metal components, and manufactures extruded and thermoformed plastic products. Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater and water reclamation projects.
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2024 FINANCIAL RESULTS
In 2024, our diversified business model generated record financial results, producing net income of $301.7 million, or $7.17 per diluted share, an increase of 3% from $294.2 million, or $7.00 per diluted share, in 2023. Our financial results for the year were driven by earnings growth in our Electric and Plastics segments, partially offset by a decline in our Manufacturing segment earnings. In 2024, we paid an annual dividend of $1.87 per share, or $78.3 million, completing our 86th consecutive year of dividend payments to our shareholders.
Our Electric segment produced earnings growth of 8% in 2024, from $84.4 million in 2023 to $91.0 million in 2024, primarily due to increased retail revenue resulting from an interim rate increase in North Dakota and increased rider revenue, partially offset by the investment and financing costs associated with our rate base investments, resulting in increased depreciation and interest expense compared to the prior year.
Our Manufacturing segment earnings decreased 36% in 2024, from $21.5 million in 2023 to $13.7 million in 2024, primarily due to soft end market demand, which resulted in lower sales volumes and a decrease in gross profit margins in our plastics thermoforming business, partially offset by reduced general and administrative expenses. Decreased profit margins were primarily due to reduced leveraging of fixed manufacturing costs resulting from decreased production and sales volumes.
Our Plastics segment produced earnings growth of 7%, from $187.7 million in 2023 to $200.7 million in 2024, primarily due to the impact of increased sales volumes, driven by strong customer and end market demand. Increased operating revenues, driven by increased sales volumes, were partially offset by a decrease in gross profit margins. Gross profit margins decreased primarily due to decreases in sales prices, which outpaced decreases in the cost of PVC resin and other input materials.
Our earnings mix in 2024 was 30% from our Electric segment and 70% from the combination of our Manufacturing and Plastics segments including unallocated corporate costs. Since 2021, our earnings mix has diverged from our long-term target of 65% from our Electric segment and 35% from our Manufacturing Platform primarily due to market conditions within the PVC pipe industry. These conditions have led to significant revenue, earnings and cash flow growth in our Plastics segment. Currently, we expect these industry conditions to gradually normalize through 2027. As they do, we expect earnings and cash flow generation within our Plastics segment to moderate from current levels and our earnings mix to return to our long-term targeted mix.
PVC PIPE MARKET CONDITIONS
Extraordinary supply and demand conditions in the PVC industry beginning in 2021 have led to a significant expansion in operating margins and elevated earnings in our Plastics segment over the past four years. Periodic disruptions in the supply of PVC resin, the primary material input used in the manufacturing of PVC pipe, coupled with robust demand for resin, led to a significant increase in the cost of resin beginning in 2021. During this time, robust end market demand for PVC pipe led to a rapid and significant increase in sales prices for the product, significantly outpacing the increase in resin input costs, leading to increased operating margins within our Plastics segment. PVC pipe prices and resin costs reached historic levels, peaking in 2022. Sales prices have steadily declined since the third quarter of 2022, a trend that continued throughout 2024; however, operating margins remain elevated relative to historical levels.
In the second half of 2022, our sales volumes declined in response to uncertain and competitive market conditions, which continued through the first half of 2023. Robust infrastructure investment plans, particularly in water supply, sewage, and drainage systems, and increased construction activity drove strong distributor and end market demand for PVC pipe beginning in the second half of 2023 and those trends continued throughout 2024.
The market dynamics impacting our Plastics segment resulted in a significant increase in earnings in the last four years compared to historical levels. We anticipate PVC pipe sales prices will continue to decline over time; however, future supply and demand dynamics, as well as other factors, could impact future product prices. We anticipate PVC pipe prices will gradually normalize through 2027. The marketplace dynamics impacting our Plastics segments are fluid and subject to change and may impact our operating results prospectively.
FINANCIAL AND OTHER METRICS
Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. Normal weather conditions are defined as the 20-year average of actual historical weather conditions. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.
Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
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OTP generally bases its forecasted kwh sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast, and on period-to-period results.
RESULTS OF OPERATIONS
For a comparison of fiscal year 2023 to 2022, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our report on Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 14, 2024.
Provided below is a summary and discussion of our operating results on a consolidated basis followed by a discussion of the operating results of each of our segments, Electric, Manufacturing and Plastics. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment, but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated statements of income.
CONSOLIDATED RESULTS
The following table summarizes our consolidated results of operations for the years ended December 31, 2024 and 2023:
(in thousands) 2024 2023 $ change % change
Operating Revenues $ 1,330,548 $ 1,349,166 $ (18,618) (1.4) %
Operating Expenses 950,298 971,247 (20,949) (2.2)
Operating Income 380,250 377,919 2,331 0.6
Interest Expense (41,815) (37,677) (4,138) 11.0
Nonservice Components of Postretirement Benefits 9,609 10,597 (988) (9.3)
Other Income 18,848 12,650 6,198 49.0
Income Before Income Taxes 366,892 363,489 3,403 0.9
Income Tax Expense 65,230 69,298 (4,068) (5.9)
Net Income $ 301,662 $ 294,191 $ 7,471 2.5 %
Operating Revenues decreased $18.6 million on a consolidated basis in 2024. Electric segment operating revenues decreased 1% primarily due to decreased fuel recovery and wholesale revenues and the impact of unfavorable weather, partially offset by retail revenue increases due to an interim rate increase in North Dakota in connection with our most recent rate case, as well as increased commercial and industrial sales volumes, and increased rider revenue. Manufacturing segment operating revenues decreased 15% primarily due to lower sales volumes due to soft end market demand across most end markets. Plastics segment operating revenues increased 11% primarily due to increased sales volumes driven by strong customer demand, partially offset by a decrease in sales prices. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses decreased $20.9 million in 2024. Electric segment operating expenses decreased primarily due to decreased purchased power costs resulting from lower market energy prices. Operating expenses in our Manufacturing segment decreased primarily due to decreased sales volumes, as discussed above. Operating expenses in our Plastics segment increased primarily due to increased sales volumes, as discussed above. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Expense increased $4.1 million in 2024 due to the issuance of an additional $120.0 million of long-term debt at OTP in March, the proceeds of which were used to repay short-term borrowings, fund capital expenditures and support operating activities.
Other Income increased $6.2 million in 2024 primarily due to an increase in investment income earned on our short-term cash equivalent investments and our long-term fixed income investments.
Income Tax Expense decreased $4.1 million in 2024 primarily due to an increase in PTCs produced by our wind and solar generation assets. Our effective tax rate was 17.8% in 2024 and 19.1% in 2023. See Note 1 3 to our consolidated financial statements included in this report on Form 10-K for additional information regarding factors impacting our effective tax rate.
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ELECTRIC SEGMENT RESULTS
The following table summarizes the operating results of our Electric segment for the years ended December 31, 2024 and 2023:
(in thousands) 2024 2023 $ change % change
Retail Revenue
$ 453,214 $ 455,840 $ (2,626) (0.6) %
Transmission Services Revenue
53,517 52,555 962 1.8
Wholesale Revenue
11,077 12,459 (1,382) (11.1)
Other Electric Revenues 6,707 7,505 (798) (10.6)
Total Operating Revenue 524,515 528,359 (3,844) (0.7)
Production Fuel 60,945 60,339 606 1.0
Purchased Power 61,561 78,292 (16,731) (21.4)
Operating and Maintenance Expenses 190,422 191,263 (841) (0.4)
Depreciation and Amortization 82,136 75,330 6,806 9.0
Property Taxes 15,662 16,614 (952) (5.7)
Operating Income 113,789 106,521 7,268 6.8
Interest Expense
(38,216) (33,864) (4,352) 12.9
Nonservice Cost Components of Postretirement Benefits 10,578 11,661 (1,083) (9.3)
Other Income 3,268 1,754 1,514 86.3
Income Before Income Taxes 89,419 86,072 3,347 3.9
Income Tax (Benefit) Expense
(1,544) 1,648 (3,192) (193.7)
Net Income $ 90,963 $ 84,424 $ 6,539 7.7 %
Electric kwh Sales (in thousands)
2024 2023 kwh change
% change
Retail kwh Sales 5,681,268 5,772,215 (90,947) (1.6) %
Wholesale kwh Sales 273,365 351,729 (78,364) (22.3)
Heating Degree Days 5,313 6,259 (946) (15.1)
Cooling Degree Days 440 590 (150) (25.4) %
Our Electric segment operating results are impacted by fluctuations in weather conditions and the resulting demand for electricity for heating and cooling. The following table presents heating and cooling degree days as a percent of normal for the years ended December 31, 2024 and 2023:
2024 2023
Heating Degree Days 83.7 % 98.4 %
Cooling Degree Days 93.8 % 127.2 %
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail sales under actual weather conditions and expected retail sales under normal weather conditions for the years ended December 31, 2024 and 2023, and between years:
2024 vs Normal 2024 vs
2023 2023 vs Normal
Effect on Diluted Earnings Per Share $ (0.13) $ (0.15) $ 0.02
Retail Revenue decreased $2.6 million primarily due to the following:
• A $13.4 million decrease in fuel recovery revenues, primarily due to lower purchased power costs, as described below.
• A $8.1 million decrease in base revenues from the unfavorable impact of weather compared to last year.
The decreases in retail revenue described above were partially offset by the following:
• A $12.4 million increase from an interim rate increase in North Dakota, effective January 1, 2024, in connection with our most recent rate case.
• A $3.2 million increase in rider revenues, including recovery of our continued investments in advanced metering and outage management systems and wind repowering projects.
• Increased sales volumes to commercial and industrial customers, the mix of customer rates compared to the prior year and other factors.
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Purchased Power costs to serve retail customers decreased $16.7 million due to a 17% decrease in the price of purchased power, primarily due to decreased market energy costs, as well as a 5% decrease in the volume of purchased power primarily due to decreased demand resulting from unfavorable weather.
Operating and Maintenance Expense decreased $0.8 million primarily due to decreased vegetative maintenance, outage, transmission tariff and insurance costs, partially offset by increased labor, software and environmental protection costs.
Depreciation and Amortization expense increased $6.8 million primarily due to the placing in service of our metering infrastructure project throughout the year, a full year of depreciation recognized for Hoot Lake Solar, which was placed in service in August 2023, and continued investments in distribution facilities during the year.
Property Taxes decreased $1.0 million due to lower taxes associated with certain wind farm facilities in North Dakota due to a revision of the tax methodology applied to the property and lower taxes in Minnesota.
Interest Expense increased $4.4 million due to the issuance of an additional $120.0 million of long-term debt in March, partially offset by lower interest on short-term borrowings due to lower average borrowings and interest rates compared to the prior year.
Income Tax Expense decreased $3.2 million due to an increase in PTCs produced by our wind and solar generation assets, partially attributable to Hoot Lake Solar going into service in August 2023.
MANUFACTURING SEGMENT RESULTS
The following table summarizes the operating results of our Manufacturing segment for the years ended December 31, 2024 and 2023:
(in thousands) 2024 2023 $ change % change
Operating Revenues $ 342,592 $ 402,781 $ (60,189) (14.9) %
Cost of Products Sold (excluding depreciation) 267,904 310,601 (42,697) (13.7)
Selling, General, and Administrative Expenses 35,203 44,545 (9,342) (21.0)
Depreciation and Amortization 20,393 18,495 1,898 10.3
Operating Income 19,092 29,140 (10,048) (34.5)
Interest Expense
(2,516) (2,295) (221) 9.6
Other Income — (1) 1 (100.0)
Income Before Income Taxes 16,576 26,844 (10,268) (38.3)
Income Tax Expense 2,895 5,390 (2,495) (46.3)
Net Income $ 13,681 $ 21,454 $ (7,773) (36.2) %
Operating Revenues decreased $60.2 million primarily due to a 15% decrease in sales volumes, with declines experienced in the recreational vehicle, agriculture, construction, lawn and garden, and horticulture end markets. Sales volumes decreased due to lower end market demand and inventory management efforts by manufacturers, distributors and dealers. A 28% decline in scrap metal revenues, largely driven by lower production volumes, also contributed to the decrease in operating revenues.
Cost of Products Sold decreased $42.7 million primarily due to lower sales volumes, as described above. In response to declines in end market demand and decreased sales volumes, we reduced our headcount and operating hours and placed employees on temporary furlough during the year, which also reduced our costs. These decreases were partially offset by reduced leveraging of fixed manufacturing costs resulting from the decreased production and sales volumes.
Selling, General, and Administrative Expenses decreased $9.3 million primarily due to decreased employee compensation costs resulting from a decrease in headcount and lower variable compensation driven by financial performance in the current year.
Depreciation and Amortization increased $1.9 million due to capital expenditures during the year, which included investments in facility improvements and purchases of equipment.
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PLASTICS SEGMENT RESULTS
The following table summarizes the operating results for our Plastics segment for the years ended December 31, 2024 and 2023:
(in thousands) 2024 2023 $ change % change
Operating Revenues $ 463,441 $ 418,026 $ 45,415 10.9 %
Cost of Products Sold (excluding depreciation) 166,628 143,521 23,107 16.1
Selling, General, and Administrative Expenses 20,414 16,076 4,338 27.0
Depreciation and Amortization 4,494 4,027 467 11.6
Operating Income 271,905 254,402 17,503 6.9
Interest Expense
(590) (602) 12 (2.0)
Other Income 76 14 62 442.9
Income Before Income Taxes 271,391 253,814 17,577 6.9
Income Tax Expense 70,644 66,066 4,578 6.9
Net Income $ 200,747 $ 187,748 $ 12,999 6.9 %
Operating Revenues increased $45.4 million primarily due to a 27% increase in sales volumes driven by customer sales volume growth and strong distributor and end market demand. Sales volumes in 2023 were negatively impacted by distributors and contractors reducing purchase volumes in response to uncertain and competitive market conditions. Although market conditions remain somewhat uncertain, infrastructure investment and active construction across our sales territories contributed to increased distributor and end market demand in 2024. The impact of increased sales volumes was partially offset by decreased sales prices. Our sales prices have steadily declined after peaking in late 2022 and decreased 12% in 2024 compared to the prior year due to continuing changes in market conditions.
Cost of Products Sold increased $23.1 million primarily due to increased sales volumes, as described above. The supply and demand conditions for PVC resin experienced in recent years appear to have normalized and resin costs were less volatile throughout the year than they were in the recent past. The cost of PVC resin and other input materials decreased 13% compared to the prior year, partially offsetting the impact of increased sales volumes.
Selling, General, and Administrative Expenses increased $4.3 million due to costs associated with ongoing litigation regarding the pricing of PVC pipe, which is further described in Note 1 4 to the consolidated financial statements, as well as increased variable costs associated with our increase in sales volumes and current year financial performance.
CORPORATE
The following table summarizes Corporate results of operations for the years ended December 31, 2024 and 2023:
(in thousands) 2024 2023 $ change % change
Selling, General, and Administrative Expenses $ 24,438 $ 12,042 $ 12,396 102.9 %
Depreciation and Amortization 98 102 (4) (3.9)
Operating Income (Loss)
(24,536) (12,144) (12,392) 102.0
Interest Expense
(493) (916) 423 (46.2)
Nonservice Cost Components of Postretirement Benefits (969) (1,064) 95 (8.9)
Other Income 15,504 10,883 4,621 42.5
Income (Loss) Before Income Taxes
(10,494) (3,241) (7,253) 223.8
Income Tax (Benefit) (6,765) (3,806) (2,959) 77.7
Net Income (Loss)
$ (3,729) $ 565 $ (4,294) (760.0) %
Selling, General, and Administrative Expenses increased $12.4 million primarily due to increased insurance expense driven by higher claims costs associated with our self-funded insurance programs, as well as increased variable compensation based on the current year financial performance.
Other Income increased $4.6 million primarily due to an increase in investment income earned on our short-term cash equivalent investments and our long-term fixed income investments, primarily due to additional investments made during the year driven by an increase in cash available for investment.
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REGULATORY MATTERS
The following provides a summary of OTP's current and recent rate case filings, rate rider filings, and other regulatory filings that have or are expected to have a material impact on our operating results, financial position or cash flows.
RATE CASES
The following includes a summary of electric rate cases as determined in OTP's most recent general rate case in each state:
Revenue Allowed
Implementation Requirement Return on Return Equity
Jurisdiction Date (in millions) Rate Base on Equity Ratio
Minnesota 07/01/22 $ 209.0 7.18 % 9.48 % 52.50 %
North Dakota (1)(2)
03/15/25 225.6 7.53 10.10 53.50
South Dakota (3)
08/01/19 35.5 7.09 8.75 52.92
(1) Includes an earnings sharing mechanism to share with North Dakota customers any earnings above an ROE of 10.20%. The mechanism requires 70% of any revenue creating annual earnings in excess of the authorized ROE be returned to customers.
(2) A compliance filing affirming the implementation date, revenue requirement, return on rate base, allowed return on equity, and equity ratio was made on February 7, 2025, and remained subject to final approval by the NDPSC as of the date of this annual report on Form 10-K.
(3) Includes an earnings sharing mechanism to share with South Dakota customers any weather-normalized earnings above the authorized ROE of 8.75%. The mechanism requires 50% of any weather-normalized revenue creating annual earnings in excess of the authorized ROE up to a maximum of 9.50% be returned to customers and 100% returns of revenue creating annual earnings above 9.50%.
North Dakota Rate Case: On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of ROE of 10.6% on an equity ratio of 53.5% of total capital. The filing also included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023. Interim rates went into effect on January 1, 2024. On July 3, 2024, OTP filed an update to the original request increasing the amount of the net annual revenue requirement increase from $17.4 million to $22.5 million, or a net increase of 10.9% in annual revenue, to account for certain items identified throughout the regulatory process.
On December 30, 2024, the NDPSC approved a settlement agreement between OTP and certain interested parties in the general rate case and issued its written order on final rates. The key provisions of the order include a revenue requirement of $225.6 million, based on a return on rate base of 7.53%, and an allowed ROE of 10.10% on an equity ratio of 53.5%. The net annual revenue requirement includes a net increase of $13.1 million, or 6.18%. OTP’s revenue requirement was reduced by approximately $3.0 million primarily due to the inclusion of forecasted PTCs plus adjustments for new customer load additions, which were not included in OTP’s updated request filed on July 3, 2024. Through the settlement of the case, the parties also agreed to establish an earnings sharing mechanism, whereby 70% of actual earnings in excess of a 10.20% ROE would be returned to customers, with OTP retaining the remaining 30%.
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RATE RIDERS
The following table includes a summary of substantial pending and recently concluded rate rider proceedings:
Recovery Filing Amount Effective
Mechanism Jurisdiction Status Date (in millions) Date Notes
RRR - 2023 MN Approved 11/01/22 $17.5 07/01/23 Recovery of Hoot Lake Solar costs, Ashtabula III costs, and true up for PTCs from Merricourt.
ECO - 2023 MN Approved 04/03/23 9.7 10/01/23 Recovery of energy conservation improvement costs as well as a demand side management financial incentive.
ECO - 2024
MN
Approved
04/01/24 8.8 10/01/24 Recovery of energy conservation improvement costs as well as a demand side management financial incentive.
RRR - 2024 MN Approved
12/04/23 8.0 09/01/24 Recovery of Hoot Lake Solar costs, Ashtabula III costs, wind upgrade project costs at our four owned wind facilities, and true up of PTCs for Merricourt.
EUIC - 2025
MN
Approved
05/03/24 4.1 02/01/25 Recovery of advanced metering infrastructure, outage management system, geographic information system, and demand response projects.
RRR - 2023 ND Approved 12/30/22 12.2 05/01/23 Recovery of Merricourt, Ashtabula III and other costs.
RRR - 2022 ND Approved 01/05/22 7.8 04/01/22 Recovery of Merricourt costs, Ashtabula III costs, and deferred taxes and PTCs.
TCR - 2023 ND Approved 09/15/22 7.5 01/01/23 Recovery of transmission project costs.
TCR - 2024 ND Approved 11/02/23 4.5 01/01/24 Recovery of transmission project costs.
GCR - 2022 ND Approved 03/01/22 3.3 07/01/22 Annual update to generation cost recovery rider.
MDT - 2023 ND Approved 07/08/22 3.1 01/01/23 Recovery of advanced metering infrastructure, outage management system and demand response projects.
TCR - 2025
ND
Approved
09/16/24 3.1 01/01/25 Recovery of transmission project costs.
PIR - 2024
SD
Approved
06/03/24 3.2 09/01/24 Recovery of Ashtabula III, Merricourt, Astoria Station, wind upgrade projects, Advanced Grid Infrastructure project costs, and impact of load growth credits.
PIR - 2025
SD
Requested
12/20/24 3.2 09/01/25 Recovery of Ashtabula III, Merricourt, Astoria Station, wind upgrade projects, advanced metering infrastructure, outage management system, demand response system, and impact of load growth credits.
PIR - 2022 SD Approved 06/01/22 3.0 09/01/22 Recovery of Ashtabula III, Merricourt, Astoria Station, Advanced Grid Infrastructure project costs, and impact of load growth credits.
TCR - 2023 SD Approved 11/01/22 3.0 03/01/23 Recovery of transmission project costs.
RESOURCE PLANNING
Minnesota
In May 2024, the MPUC approved OTP’s 2023 to 2037 IRP. Consistent with MPUC practice, the decision was made during deliberations by oral vote and was finalized in a written order issued in July 2024.
The MPUC:
• Directed OTP to procure the following generation resources, subject to additional regulatory review and approval:
◦ 200 to 300 MW of solar generation by November 1, 2027, or as soon as practicable thereafter,
◦ 150 to 200 MW of wind generation by December 31, 2029, or as soon as practicable thereafter,
◦ 20 to 75 MW of battery storage by December 31, 2029, or as soon as practicable thereafter;
• Approved the project to add on-site liquified natural gas storage at our Astoria Station natural gas plant by 2027;
• Directed OTP to designate the Minnesota share of the jointly owned Coyote Station coal-fired plant as an Available Maximum Emergency (AME) resource beginning in 2026 and ending no later than December 2031. If the designation as an AME resource is found to not be feasible, then Minnesota customers shall not continue to pay for or depend on capacity or energy from Coyote Station past 2028; and
• Directed OTP to commence activities to no longer serve Minnesota customers with capacity or energy from Coyote Station as soon as feasible and no later than December 31, 2031.
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Under the MPUC’s order, OTP will file its next IRP in May 2026. In this filing, the company will include, among other options, an analysis considering the continued operation of Big Stone Plant with AME.
North Dakota
In December 2024, the NDPSC issued its final order on OTP's IRP. The order stipulated that the commission does not support the addition of new wind or solar generation or battery storage through 2030. Therefore, none of the costs or benefits of the new renewable and battery storage assets in OTP's IRP approved by the MPUC will be assigned to North Dakota customers, including any that may be physically located in North Dakota. In addition, at an informal hearing in July 2024, the NDPSC denied our request for an Advanced Determination of Prudence (ADP) for the on-site liquified natural gas storage at Astoria Station, a project that was part of OTP's IRP approved by the MPUC. We continue to evaluate the benefits of on-site fuel storage at Astoria Station and the development of this project in the future.
LIQUIDITY
LIQUIDITY OVERVIEW
We believe our financial condition is strong and our cash and cash equivalents, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability, because of investment-grade credit ratings, when taken together, provide us ample liquidity to conduct business operations, fund our capital expenditure program and satisfy our obligations as they become due. Our liquidity, including our operating cash flows and access to capital markets, could be impacted by macroeconomic factors outside of our control, including higher interest rates and debt capital costs, and diminished credit availability. In addition, our liquidity could be impacted by non-compliance with certain financial covenants under our various debt instruments. As of December 31, 2024, we were in compliance with all financial covenants (see the Financial Covenant section under Capital Resources below).
The following table presents the status of our lines of credit as of December 31, 2024:
2024
(in thousands) Line Limit Amount Outstanding Letters
of Credit Amount Available
OTC Credit Agreement $ 170,000 $ — $ — $ 170,000
OTP Credit Agreement 220,000 69,615 8,772 141,613
Total $ 390,000 $ 69,615 $ 8,772 $ 311,613
OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. Should additional liquidity be needed, the OTC Credit Agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $300 million, subject to certain terms and conditions.
As of December 31, 2024, we had $311.6 million of available liquidity under our credit agreements and $294.7 million of available cash and cash equivalents, resulting in total available liquidity of $606.3 million, compared to total available liquidity of $479.8 million as of December 31, 2023.
CASH FLOWS
The following is a discussion of our cash flows for the years ended December 31, 2024 and 2023:
(in thousands) 2024 2023
Net Cash Provided by Operating Activities $ 452,731 $ 404,499
Net Cash Provided by Operating Activities increased $48.2 million primarily due to a decrease in working capital and increased net income. In our Plastics segment, sales and related receivable balances were less volatile than the prior year where sales and related receivable balances increased in the later part of the year. This resulted in decreased working capital in the current year compared to the prior year. Working capital also decreased due to an increase in payables in our Electric segment, due to the timing of capital investment spending, and decreases in receivables and inventories in our Manufacturing segment, due to decreased sales and production volumes during the later part of the current year.
Market dynamics experienced by our Plastics segment businesses in 2024 and 2023 resulted in a significant increase in our overall cash from operations compared to prior periods. We anticipate our cash from operations in future years will decline from current levels consistent with the anticipated decline in Plastics segment earnings.
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(in thousands) 2024 2023
Net Cash Used in Investing Activities $ 411,374 $ 289,287
Net Cash Used in Investment Activities increased $122.1 million primarily due to an increase in capital expenditures. Capital expenditures during the year included additional investments in our wind repowering and advanced metering and outage management projects at OTP, as well as continued investments in our manufacturing facility expansion projects in Arizona and Georgia. A $50.1 million investment in U.S. treasuries made during the year to secure a fixed rate of return until their maturity in September 2026 also contributed to the increase in net cash used in investing activities.
(in thousands) 2024 2023
Net Cash Provided by (Used in) Financing Activities
$ 22,921 $ (3,835)
Net Cash Provided by (Used in) Financing Activities increased $26.8 million compared to the prior year. Financing activities during the year included the issuance of $120.0 million of long-term debt at OTP, the proceeds of which were used to repay short-term borrowings under the OTP credit agreement, fund Electric segment construction expenditures and support operating activities. We manage the capital structure of OTP independently from our consolidated financial position to ensure compliance with the capital structure approved through regulation; therefore, our decision to issue long-term debt at OTP is not impacted by our consolidated cash and cash equivalent position.
Financing activities during the year also included net repayments of short-term debt of $11.8 million compared to net short-term borrowings of $73.2 million in 2023, and in 2024, we made dividend payments of $78.3 million compared to $73.1 million in 2023.
CAPITAL REQUIREMENTS
CAPITAL EXPENDITURES
Our capital expenditure plan includes investments in electric generation facilities, transmission and distribution lines and facilities, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. Our capital expenditure plan is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory approvals, business expansion opportunities, the costs of labor, materials and equipment, and our overall financial condition.
The following provides a summary of capital expenditures for the years ended December 31, 2024 and 2023 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five-year period 2025 through 2029:
(in millions) 2023 2024 2025 2026 2027 2028 2029 Total
2025 - 2029
Electric Segment:
Renewable Generation
$ 106 $ 134 $ 101 $ 127 $ 118 $ 179 $ 4 $ 529
Transmission 49 60 59 93 162 114 100 528
Distribution 45 46 37 37 36 37 34 181
Other 41 61 54 51 31 27 25 188
Total Electric Segment 241 301 251 308 347 357 163 1,426
Manufacturing and Plastics Segments 46 58 27 27 27 25 23 129
Total Capital Expenditures $ 287 $ 359 $ 278 $ 335 $ 374 $ 382 $ 186 $ 1,555
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CONTRACTUAL AND OTHER OBLIGATIONS
The following table summarizes our contractual obligations on December 31, 2024 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.
(in millions) Total Less than
1 Year 1-3
Years 3-5
Years More than
5 Years
Debt Obligations $ 1,017 $ 70 $ 122 $ 70 $ 755
Interest on Debt Obligations 700 42 81 71 506
Coal Contracts 441 24 50 53 314
Land Easements 62 2 4 4 52
Postretirement Benefit Obligations 65 5 11 11 38
Operating Lease Obligations 35 6 10 6 13
Other Obligations
11 2 2 1 6
Total Contractual Obligations
$ 2,331 $ 151 $ 280 $ 216 $ 1,684
Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company (CCMC) under the Lignite Sales Agreement (LSA) that ends in 2040. Postretirement benefit obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan (ESSRP), but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make any contributions to that plan. OTP also has contractual agreements for the purchase of capacity and wind-generated energy. Generally, the terms of OTP's wind power purchase agreements require OTP to purchase all of the electricity generated by a particular wind farm, but do not include fixed or minimum payments.
On October 30, 2024, OTP entered into an agreement to acquire the assets of a solar facility currently under development. Under the terms of the agreement, the purchase price is equal to $23.6 million, plus the reimbursement of certain interconnection costs and costs to purchase and store the main power transformer. Closing of the transaction is expected to occur in late 2025 or early 2026.
COMMON STOCK DIVIDENDS
We paid dividends to our shareholders totaling $78.3 million, or $1.87 per share, in 2024. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, our actual or expected level of earnings and cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC subsidiaries to OTC. These intercompany distributions serve as the primary source of funding for dividends paid to our shareholders. See Note 1 5 to our consolidated financial statements included in this report on Form 10-K for additional information. The decision to declare a dividend is reviewed quarterly by our Board of Directors. On February 4, 2025, our Board of Directors approved a quarterly dividend of $0.525 per common share.
CAPITAL RESOURCES
Financial flexibility is provided by operating cash flows, unused lines of credit, access to capital markets and alternative financing arrangements such as leasing. Debt financing will be required in the five-year period from 2025 through 2029 to refinance maturing debt and to finance our planned capital investments. Our financing plans are subject to change and are impacted by our planned level of capital investments, decisions to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or to use capital for other purposes.
REGISTRATION STATEMENTS
On May 3, 2024, we filed two registration statements with the SEC, replacing two previously filed registration statements upon their expiration. The first statement, a shelf registration, allows us to offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the registration statement. No new equity, debt, or other securities have been issued pursuant to this registration statement. The second registration statement allows for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan, which provides our common shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends and/or making optional cash investments. Shares purchased under the plan may be newly issued common shares or common shares purchased on the open market. As of December 31, 2024, there were 1,429,531 shares available for purchase or issuance under the plan. Both registration statements expire in May 2027.
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SHORT-TERM DEBT
The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit. In December 2024, the credit agreements were amended to extend the maturity date of each credit facility and amend certain financial covenants. The OTP Credit Agreement was also amended to increase the borrowing limit. The agreements generally bear interest at the Secured Overnight Financing Rate (SOFR) plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the borrower. The weighted-average interest rate on all outstanding borrowings as of December 31, 2024 and 2023 was 5.61% and 6.70%.
The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2024:
(in thousands, except interest rates) OTC Credit Agreement OTP Credit Agreement
Borrowing Limit $ 170,000 $ 220,000
Borrowing Limit if Accordion Exercised 1
290,000 300,000
Amount Restricted Due to Outstanding Letters of Credit at Year-End — 8,772
Amount Outstanding at Year-End — 69,615
Average Amount Outstanding During Year — 38,475
Maximum Amount Outstanding During the Year — 102,024
Interest Rate at Year-End 5.83 % 5.61 %
Expiration Date December 11, 2029 December 11, 2029
1 Each facility includes an accordion feature allowing the borrower to increase the borrowing limit if certain terms and conditions are met.
LONG-TERM DEBT
In March 2024, OTP entered into a Note Purchase Agreement pursuant to which OTP issued, in a private placement transaction, $120.0 million of senior unsecured notes consisting of (a) $60.0 million of 5.48% Series 2024A Senior Unsecured Notes due April 1, 2034, and (b) $60.0 million of 5.77% Series 2024B Senior Unsecured Notes due April 1, 2054. The proceeds of the notes were used to repay existing short-term borrowings, fund capital expenditures and for general corporate purposes.
As of December 31, 2024, we had $947.0 million of principal outstanding under long-term debt arrangements. Note 10 to our consolidated financial statements included in this report on Form 10-K includes information regarding these instruments. The agreements generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2026 to 2054.
Financial Covenants
Our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2024, we were in compliance with these financial covenants as further described below:
OTC, under its financial covenants, may not permit its ratio of interest-bearing debt to total capitalization to exceed 0.60 to 1.00 or 0.65 to 1.00, depending on the debt agreement, may not permit its interest and dividend coverage ratio to be less than 1.50 to 1.00 and may not permit its priority indebtedness to exceed 10% of our total capitalization. As of December 31, 2024, OTC's interest-bearing debt to total capitalization was 0.38 to 1.00, OTC's interest and dividend coverage ratio was 10.00 to 1.00 and OTC had no priority indebtedness outstanding.
OTP, under its financial covenants, may not permit its ratio of interest-bearing debt to total capitalization to exceed 0.60 to 1.00 or 0.65 to 1.00, depending on the debt agreement, may not permit its interest and dividend coverage ratio to be less than 1.50 to 1.00 and may not permit its priority indebtedness to exceed 20% of its total capitalization. As of December 31, 2024, OTP's interest-bearing debt to total capitalization was 0.47 to 1.00, OTP's interest and dividend coverage ratio was 3.34 to 1.00 and OTP had no priority indebtedness outstanding.
None of our debt agreements include any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
Credit Ratings
The current credit ratings of OTC and OTP are summarized below:
Otter Tail Corporation Otter Tail Power Company
Moody's Fitch S&P Moody's Fitch S&P
Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB BBB A3 BBB+ BBB+
Senior Unsecured Debt n/a BBB n/a n/a A- n/a
Outlook Stable Stable Stable Negative
Stable Stable
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CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The discussion and analysis of our results of operations are based on financial statements prepared in accordance with generally accepted accounting principles in the United States of America. Certain of our accounting policies require management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the preparation of our consolidated financial statements. While we believe the estimates, assumptions and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of our Board of Directors. The following critical accounting policies affect the most significant judgments and estimates used in the preparation of our consolidated financial statements.
REGULATORY ACCOUNTING
Our utility business is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. Accordingly, our utility business must adhere to the accounting requirements of regulated operations, which requires the recognition of regulatory assets and regulatory liabilities for amounts that otherwise would impact the statements of income or comprehensive income when it is probable that such amounts will be collected from customers or credited to customers through the rate-making process. This guidance also provides recognition criteria for adjustments to rates outside of a general rate case proceeding, which are provided to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. Regulatory assets generally represent costs that have been incurred but have been deferred because future recovery from customers, as established through the rate-making process, is probable. Regulatory liabilities generally represent amounts to be refunded to customers or amounts currently collected from customers for future costs.
We assess the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Our probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which we operate and the impact these incurred costs may have on our customers. Changes in our assessments regarding the likelihood of recovery or settlement of our regulatory assets and liabilities may have a material impact on our operating results and financial position. Further, if we determine that all or a portion of our utility business no longer meets the criteria for continued application of regulatory accounting, or our regulators disallow recovery of a previously incurred cost or eliminate a regulatory liability, we would be required to remove the associated regulatory assets and liabilities from our consolidated balance sheets and recognize those amounts in the consolidated statements of income as an expense or income item, or in the consolidated statements of comprehensive income as a loss or gain, in the period in which this accounting treatment is no longer applicable.
As of December 31, 2024 and 2023, we had regulatory assets of $108.6 million and $111.8 million and regulatory liabilities of $318.2 million and $302.0 million. If future recovery of amounts recorded as regulatory assets was no longer probable, we would be required to recognize an expense or loss in the period in which recovery was deemed to no longer be probable.
PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS
Pension and postretirement benefit liabilities and expenses are determined by actuaries using numerous assumptions, including a discount rate, an expected return on plan assets, a rate of compensation increase and healthcare cost-trend rates. See Note 1 1 to our consolidated financial statements included in this report on Form 10-K for additional information on our pension and postretirement benefit plans and related assumptions.
These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 30 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Likewise, compensation decreases and healthcare cost decreases or an increase in the discount rate applied from one year to the next can significantly decrease our benefit expenses in the year of the change. Also, a change in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well above or below assumed rates of return or a change in the anticipated life expectancy of plan participants could result in significant increases or decreases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.
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We estimate the discount rate through the use of a hypothetical bond portfolio method, which incorporates yields on a collection of high credit quality bonds that produce cash flows similar to our anticipated future benefit payments. We estimate the assumed long-term rate of return on plan assets based on asset category studies using historical market returns achieved by our asset portfolio allocation over long-term periods, as well as long-term projected return levels. Other assumptions are developed by reference to available trend or historical data adjusted as necessary for future expectations.
On December 31, 2024, the discount rates used to measure our pension plan and postretirement healthcare obligations were 5.70% and 5.61%, a thirteen and eight basis point increase, respectively, from the estimates used on December 31, 2023. Our estimates used to determine benefit cost for 2024 included a discount rate of 5.57% for pension benefits and 5.53% for postretirement healthcare costs, a six and one basis point increase, respectively, from 2023 estimates. In addition, we estimated our assumed rate of return on pension assets to be 7.00% for 2024, which was unchanged from our 2023 estimate.
The following table summarizes the impact on 2024 pension and postretirement costs for a 25 basis point increase or decrease, holding all other variables constant, on certain key assumptions:
(in thousands) +0.25 -0.25
Pension Plan:
Discount Rate $ (96) $ 931
Rate of Increase in Future Compensation 573 (424)
Long-Term Return on Plan Assets (911) 911
Other Postretirement Benefits:
Discount Rate (14) 15
For 2025, we expect pension and other postretirement benefit income to be $4.3 million compared to $8.5 million of income in 2024 due to the impacts of updated actuarial assumptions. See additional information at Note 11 of the consolidated financial statements.
Subsequent increases or decreases in actual rates of return on plan assets over assumed rates, increases or decreases in the discount rate, increases in future compensation levels and increases in retiree healthcare cost inflation rates could significantly change projected costs.
We believe the estimates made for our pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are subject to change.
GOODWILL IMPAIRMENT
Goodwill is required to be evaluated annually for impairment and more frequently as events or circumstances require. Goodwill is tested for impairment at the reporting unit level. We have identified two reporting units which carry a material amount of goodwill, BTD Manufacturing, our contract metal fabrication business, and our Plastics segment. As of December 31, 2024, BTD Manufacturing and our Plastics segment carried a goodwill balance of $18.1 million and $19.3 million, respectively.
We historically tested goodwill for impairment as of December 31st each year; however, in 2024, we elected to change the date of our annual goodwill impairment test to October 1st. We believe this new testing date allows us to better align our annual goodwill impairment testing procedures with our year-end financial reporting, as well as our annual budgeting and forecasting process. This change did not delay, accelerate or avoid the recognition of an impairment charge.
The goodwill impairment test is a single-step quantitative assessment which compares the estimated fair value of the reporting unit to its carrying value. An impairment charge is recognized if the carrying amount exceeds the estimated fair value in an amount that is equal to the excess but limited to the amount of recorded goodwill of the reporting unit. An optional qualitative impairment assessment may be performed prior to, and may eliminate the need to perform, the quantitative assessment.
Estimating the fair value of a reporting unit under the quantitative impairment method requires significant judgments and estimates. We estimate the fair value of our reporting units using income and market approaches. Our income approach uses a discounted cash flow methodology to arrive at a fair value estimate by determining the present value of projected future cash flows over a specified period plus a terminal value to reflect cash flows beyond the projection period. The discount rate applied to the estimated future cash flows reflects our estimate of the weighted-average cost of capital of comparable entities. Our market approach includes estimating the fair value of our reporting units by reference to various market indications of value, including fair value estimates using multiples derived from comparable enterprise values to earnings before interest, taxes, depreciation and amortization (EBITDA) of select peer companies, and, if available, comparable sales transactions for comparative peer companies.
Our discounted cash flow methodology incorporates significant estimates, which include assumptions of future operating results and cash flows, which are impacted by economic and industry conditions, the amount and timing of estimated capital expenditures, an
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estimated terminal growth rate and the selection of an appropriate weighted-average cost of capital, among others. Our market approaches require significant judgment in selecting comparable peer companies and comparable sales transactions and from these peer groups selecting an appropriate EBITDA multiple and indication of fair value. In addition, weighting the indications of fair value between the income and market approaches to arrive at a single fair value estimate for each reporting unit also requires judgment.
Our goodwill impairment testing performed in the fourth quarter of 2024 indicated no impairment was present for either reporting unit and the estimated fair value of each reporting unit substantially exceeded the respective carrying value. As part of our testing, we perform various sensitivity analyses to understand if our conclusions are sensitive to changes in certain assumptions. A 3% decrease in projected operating revenues, a one hundred basis point decrease in projected gross profit margins, a one hundred basis point decrease in projected terminal growth rate, a 50 basis point increase in weighted-average cost of capital or a 1.0x decrease in the assumed EBITDA multiple would not lead to a goodwill impairment charge for either reporting unit.
We believe the estimates and assumptions used in our impairment assessments are reasonable and based on the best information available. However, these estimates and assumptions include an inherent degree of uncertainty. Significant adverse changes in our expectations for any of these estimates could result in an impairment charge in a future period which may materially impact our operating results and financial position.