What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-02-19 compared with 2024-02-14 · 241 added, 215 removed, 222 unchanged (67% of the section changed)

6 unchanged sentences

Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater and water reclamation projects.

Our strategy includes investing in rate base growth opportunities in our Electric segment and capitalizing on organic growth opportunities in our Manufacturing and Plastics segments.

Investments in our Electric segment are expected to produce increased earnings and cash flows, lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund our dividend.

Our Electric segment is complemented by our Manufacturing and Plastics segment businesses, which we expect to contribute to earnings growth by capitalizing

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on market expansion opportunities and increasing utilization of existing capacities, along with planned investments to create additional capacity and increased efficiencies.

Collectively, our mix of businesses is expected to contribute to the achievement of our long-term targeted annual growth in earnings per share of 5 - 7%.

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 Manufacturing segments, as well as lower corporate costs, as we benefited from returns on our short-term investments funded by the significant cash flows our businesses have generated over the last three years.

Our Plastics segment again produced extraordinary financial results as we continued to capitalize on favorable industry dynamics;

however, earnings in this segment did decline modestly from the record level achieved in 2022.

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 6% in 2023, from $80.0 million in 2022 to $84.4 million in 2023, primarily due to increased rider revenue, increased commercial and industrial sales, and lower pension and other postretirement benefit costs, partially offset by increased operating and maintenance expenses and the impact of unfavorable weather.

Our Manufacturing segment produced earnings growth of 2% in 2023, from $21.0 million in 2022 to $21.5 million in 2023, primarily due to increased sales volumes at our metal fabrication business driven by strong end market demand across several markets we serve, and incremental volumes from additional work with existing customers.

Increased sales volumes at our metal fabrication business were partially offset by increased labor and overhead costs, as well as decreased horticulture product sales volumes at our plastic thermoforming business.

Our Plastics segment earnings declined 4%, from $195.4 million in 2022 to $187.7 million in 2023.

We experienced an unprecedented level of earnings in 2022, resulting from extraordinary industry supply and demand dynamics.

Industry dynamics have begun to moderate, but at a modest pace, as further described below.

Our Plastics segment businesses continued to capitalize on these industry conditions in 2023, producing earnings significantly in excess of pre-2021 levels.

Our earnings mix in 2023 was 29% from our Electric segment and 71% from the combination of our Manufacturing and Plastics segments excluding unallocated corporate costs.

Electric segment earnings as a percentage of our total earnings were less than our long-term target of 65% due to the unique market conditions occurring in the plastics industry.

PVC PIPE SUPPLY AND DEMAND 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 three years.

Periodic disruptions in the supply of 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.

Low industry volumes of PVC pipe and robust end market demand for the product led to a rapid and significant increase in sales prices for PVC pipe, significantly outpacing the increase in resin input costs, leading to increased operating margins within our Plastics segment.

Demand for PVC pipe began to soften in the second half of 2022, as distributors and contractors reduced purchase volumes in response to uncertain and competitive market conditions.

Softening demand continued through the first half of 2023, but sales volumes in the second half of the year exceeded those in the previous year.

Resin prices have declined from the previous year and although sales prices for PVC pipe have also declined, they have declined at a slower pace than resin prices, continuing to produce expanded operating margins from those experienced in 2022.

The unique market dynamics impacting our Plastics segment resulted in a significant increase in earnings in the last three years compared to historical levels.

We expect these market conditions to gradually normalize over the course of 2024 and into 2025.

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

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.

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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.

Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency.

In general, rate base consists of the value of property used by the utility in providing service.

Rate base can also include cash, working capital, materials and supplies, construction work in progress, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and, in some cases, accumulated deferred ITCs.

We present actual and forecasted levels of utility rate base to provide an indication of expected investments on which we expect to earn future returns.

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RESULTS OF OPERATIONS

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Interest Expense (41,815) (37,677) (4,138) 11.0

(37,677) (36,016) (1,661) 4.6

Nonservice Components of Postretirement Benefits 9,609 10,597 (988) (9.3)

10,597 1,075 9,522 n/m

Other Income 12,650 2,037 10,613 n/m

Other Income 18,848 12,650 6,198 49.0

Income Before Income Taxes 366,892 363,489 3,403 0.9

2 unchanged sentences

Operating Revenues decreased $18.6 million on a consolidated basis in 2024.

Electric segment operating revenues decreased 4% primarily due to decreased fuel recovery and wholesale revenues and the impact of unfavorable weather, partially offset by increased rider revenues and increased commercial and industrial sales.

Manufacturing segment operating revenues increased 1% primarily due to higher sales volumes in our metal fabrication business.

Plastics segment operating revenues decreased 18% due to a combination of decreased sales volumes and sales prices.

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 and lower fuel costs due to decreased natural gas prices.

Operating expenses in our Manufacturing segment increased primarily due to increased sales volumes in our metal fabrication business and an increase in certain variable compensation costs.

Operating expenses in our Plastics segment decreased primarily due to lower sales volumes and decreased PVC resin costs.

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 $1.7 million in 2023 due to an increase in our average short-term borrowings, primarily used to fund capital investments in our Electric segment, and increased interest rates on our short-term borrowings.

Nonservice Components of Postretirement Benefits improved by $9.5 million in 2023, having a positive impact on net income, primarily due to a change in actuarial assumptions used to measure our pension benefit and postretirement benefit obligations, including an increase in the discount rate applied and an increase in the expected return on assets assumption.

Other Income increased $10.6 million in 2023 primarily due to an increase in investment income earned on our short-term cash equivalent investments and investment gains from our corporate-owned life insurance policies compared to investment losses in the previous year.

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.

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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

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(in thousands) 2024 2023 $ change % change

Retail Sales Revenue $ 455,840 $ 470,300 $ (14,460) (3.1) %

Transmission Services Revenues 52,555 52,213 342 0.7

Wholesale Revenues 12,459 18,539 (6,080) (32.8)

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)

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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

Retail kwh Sales 5,681,268 5,772,215 (90,947) (1.6) %

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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:

2023 vs Normal 2023 vs 2022 2022 vs Normal

2024 vs Normal 2024 vs

2023 2023 vs Normal

Effect on Diluted Earnings Per Share $ (0.13) $ (0.15) $ 0.02

Retail Revenues decreased $14.5 million primarily due to the following:

• A $26.2 million decrease in fuel recovery revenues, primarily due to lower purchased power and fuel costs arising from decreased market energy costs and natural gas prices, as described below.

• A $5.2 million decrease in revenues from the unfavorable impact of weather compared to last year.

• Our Minnesota rate case, which was finalized in 2022, included a determination of the final interim rate refund and resulted in an additional $4.1 million of retail revenue last year.

The decreases in retail revenues described above were partially offset by the following:

• A $10.5 million increase in retail revenues from increased sales volumes from commercial and industrial customers, including the impact of a new commercial customer load in North Dakota added during 2022.

• A $9.6 million increase in rider revenues, including recovery of our investment in the Ashtabula III wind farm, which we acquired in January 2023, and the recovery of our investment in Hoot Lake Solar, which was completed during the year, as well as operating costs associated with these facilities.

Wholesale Revenues decreased $6.1 million primarily due to a 49% decrease in wholesale electric prices driven by decreased fuel costs.

Production Fuel costs decreased $4.8 million due to a 17% decrease in fuel cost per kwh resulting from decreases in natural gas prices, partially offset by an increase in kwhs generated from our natural gas-burning plants.

Purchased Power costs to serve retail customers decreased $22.0 million due to a 14% decrease in the price of purchased power per kwh, primarily due to decreased market energy costs, as well as decreased purchase volumes due to the acquisition of the Ashtabula III wind farm and completion of our Hoot Lake Solar project in the current year.

Prior to the acquisition of Ashtabula III, OTP purchased the wind generated electricity from the facility under the terms of a power purchase agreement.

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Operating and Maintenance Expense increased $9.9 million primarily due to:

• A $3.9 million increase in labor and benefit costs partially due to increased health insurance costs, wage increases, and increased headcount.

• A $2.2 million increase in vegetative maintenance costs.

• A $1.9 million increase in insurance expense due in part to the addition of Ashtabula III and Hoot Lake Solar to our generation fleet during the year.

• A $1.3 million increase in maintenance related to the addition and operation of Ashtabula III.

These expense increases were partially offset by, among other items, decreased outage-related costs and travel costs compared to the previous year.

Depreciation and Amortization expense increased $3.3 million primarily due to the acquisition of Ashtabula III and continued investment in distribution facilities during the year.

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.

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

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Cost of Products Sold (excluding depreciation) 267,904 310,601 (42,697) (13.7)

310,601 315,375 (4,774) (1.5)

Selling, General, and Administrative Expenses 35,203 44,545 (9,342) (21.0)

44,545 37,341 7,204 19.3

Depreciation and Amortization 20,393 18,495 1,898 10.3

Operating Income 19,092 29,140 (10,048) (34.5)

Operating Revenues increased $4.8 million primarily due to the combination of the following:

• At BTD, operating revenues increased $12.5 million primarily due to a combination of higher sales volumes and increased pricing.

Sales volumes increased 12% compared to the previous year due to strong end market demand in several segments, including the construction, industrial, and agricultural segments, and incremental volumes from additional work with existing customers.

Sales price increases were implemented during the year in response to labor and non-steel material cost inflation.

Sales price increases and sales volume growth were partially offset by decreased steel prices, resulting in an 11% decrease in material costs, which are passed through to customers.

Plastics, operating revenues decreased $7.7 million primarily due to lower sales volumes.

Sales volumes decreased 19% primarily due to decreased sales of horticulture products, as order and delivery lead times for these products have normalized after volatility experienced in the previous year, and customers reduced their inventory levels and are beginning to return to normal seasonal buying patterns.

Cost of Products Sold decreased $4.8 million primarily due to the combination of the following:

• Cost of products sold at BTD increased $0.8 million primarily due to higher sales volumes, as discussed above.

Cost of products sold also increased due to lower productivity and inflationary cost pressures which resulted in higher non-steel material, labor and overhead costs.

The increase in labor costs and lower level of productivity was partially attributable to increased shift incentives and overtime wages combined with increased staffing levels to meet higher production volumes and the time required for new employees to achieve peak productivity.

The impacts of higher sales volumes and increased labor and overhead costs were largely offset by decreased material costs, as discussed above.

• Cost of products sold at T.O.

Plastics decreased $5.6 million primarily due to lower sales volumes of horticulture products, as discussed above.

Selling, General, and Administrative Expenses increased $7.2 million primarily due to increased employee compensation from an increase in headcount, inflationary cost pressure and variable compensation driven by current year financial performance.

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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Cost of Products Sold (excluding depreciation) 166,628 143,521 23,107 16.1

143,521 227,569 (84,048) (36.9)

Selling, General, and Administrative Expenses 20,414 16,076 4,338 27.0

16,076 16,175 (99) (0.6)

Depreciation and Amortization 4,494 4,027 467 11.6

Operating Income 271,905 254,402 17,503 6.9

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Operating Revenues decreased $94.5 million primarily due to a 14% decrease in sales volumes.

Sales volume decreases were attributable to softer end market demand coupled with distributor inventory management, as these customers reduced their inventory levels during the first half of the year after previously building higher inventory levels in response to market uncertainty and supply chain challenges.

Operating revenue decreases were also the result of a 5% decrease in sales prices, as prices in 2023 decreased from record highs in 2022.

Cost of Products Sold decreased $84.0 million due to a 26% decrease in the cost per pound of PVC pipe sold, primarily due to lower resin costs, as well as the 14% decrease in sales volumes discussed above.

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.

The following table summarizes Corporate results of operations for the years ended December 31, 2024 and 2023:

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Selling, General, and Administrative Expenses $ 24,438 $ 12,042 $ 12,396 102.9 %

$ 12,042 $ 16,202 $ (4,160) (25.7) %

Depreciation and Amortization 98 102 (4) (3.9)

Operating Loss $ 12,144 $ 16,342 $ (4,198) (25.7) %

Selling, General, and Administrative Expenses decreased $4.2 million primarily due to lower health care costs related to our self-funded health insurance program in 2023 compared to higher claim costs in 2022.

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.

REGULATORY MATTERS

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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%.

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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 return on equity of 10.6% on an equity ratio of 53.5% of total capital.

Through this proceeding, OTP has proposed changes to the mechanism of cost and investment recovery, with recovery moving from riders into base rates.

The filing also includes a proposal to implement a sales adjustment mechanism to address potential significant load additions or losses.

The filing 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, and interim rates went into effect on January 1, 2024.

These interim rate revenues, when collected, are subject to potential refund until the finalization of the rate case.

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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%.

The following table includes a summary of substantial pending and recently concluded rate rider proceedings:

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Mechanism Jurisdiction Status Date (in millions) Date Notes

11/01/22 $17.5 07/01/23 Recovery of Hoot Lake Solar costs, Ashtabula III costs, and true up for PTCs from Merricourt.

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.

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.

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.

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.

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.

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.

ND Approved 07/08/22 3.1 01/01/23 Recovery of advanced metering infrastructure, outage management system and demand response projects.

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.

MDT - 2023 ND Approved 07/08/22 3.1 01/01/23 Recovery of advanced metering infrastructure, outage management system and demand response projects.

09/16/24 3.1 01/01/25 Recovery of transmission project costs.

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.

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

On March 31, 2023, OTP submitted a supplemental resource plan filing to the MPUC, the NDPSC, and the South Dakota Public Utilities Commission (SDPUC).

The supplemental filing updated OTP’s original 2022 Integrated Resource Plan (2022 IRP), which was filed on September 1, 2021.

In the supplemental filing, OTP outlined its updated plan for meeting all customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates in light of several changes that had occurred since the original filing, including significant winter and spring reserve planning margins adopted by MISO, tax credits made available for renewable energy projects under the Inflation Reduction Act, the enactment of the Clean Energy Bill in Minnesota, and volatility experienced in energy and capacity markets.

On December 15, 2023, OTP submitted a second supplemental resource plan filing to the MPUC outlining an updated plan specifically for meeting Minnesota customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates.

Based on feedback received on the preferred plan outlined in the March 31, 2023 supplemental filing and the inability to reach a consensus on certain aspects of the plan, the second supplemental filing includes a proposal to bifurcate OTP's resource planning by jurisdiction.

Under bifurcated resource planning, it is anticipated that OTP would develop two separate resource plans, one plan developed for Minnesota and a second developed for North Dakota and South Dakota.

Each plan would be developed incorporating the assumption that all existing generation resources, except Hoot Lake Solar, would continue to be allocated to all jurisdictions using established jurisdictional allocators.

Hoot Lake Solar is currently directly allocated to only Minnesota.

As new generation resources are needed for each plan, those generation resources would be allocated to the jurisdiction that is needing the resource.

To the extent a common generation resource is needed for both plans, that resource would be allocated using established jurisdictional allocators.

This method of resource planning would diverge from OTP’s historical practice of planning on an integrated basis for all jurisdictions served.

With the proposal of bifurcated resource planning, the supplemental filing outlines OTP’s preferred plan for Minnesota only.

The preferred plan in this supplemental filing includes:

• repowering four of our existing wind facilities in 2025;

• the addition of approximately 200 megawatts of solar generation in 2025;

• the addition of approximately 100 megawatts of wind generation in 2026;

• the addition of on-site liquefied natural gas fuel storage at our Astoria Station natural gas plant in 2027;

• the designation of Coyote Station, a jointly owned coal-fired generation plant, as an Available Maximum Emergency (AME) Resource beginning in 2029 and annually thereafter;

• a withdrawal from our 35 percent ownership interest in Coyote Station in the event we are required to make a major, non-routine capital investment in the plant;

• the addition of approximately 50 megawatts of wind generation in 2032.

The preferred plan requests the MPUC issue an order requiring the Minnesota’s jurisdictionally allocated share of the generation from Coyote Station be designated as an AME Resource beginning March 1, 2029, subject to additional analysis to be performed by OTP.

AME Resources are

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resources called on only in the event of a maximum generation event, such as in the cases of extreme heat, cold, or other extreme events.

Designating Coyote Station as an AME Resource would allow us to retain Coyote Station’s capacity, thereby providing an important reliability benefit.

This also helps ensure we remain compliant with market monitoring regulations and our contractual obligations to the co-owners of Coyote Station while advancing our compliance with Minnesota's carbon-free standard.

The supplemental filing requests Minnesota customer rates continue to include the recovery of an allocated share of OTP’s costs associated with owning the plant, and a return on those costs, as well as the fixed costs of operating the plant.

The variable cost of operating the plant, which consists primarily of variable fuel costs, would not be attributed to Minnesota customers, except when the plant is called upon to serve Minnesota customers in emergency situations.

The supplemental IRP filing made December 15, 2023 outlines our proposed resource plan for Minnesota.

We anticipate filing future resource plans on a bifurcated basis in North Dakota and South Dakota.

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.

• 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;

• 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.

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.

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 OVERVIEW

We believe our financial condition is strong and our cash, 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 and fund our capital expenditure program.

Our liquidity, including our operating cash flows and access to capital markets, could be impacted by macroeconomic factors outside of our control.

In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments.

As of December 31, 2023, we were in compliance with all debt 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, 2023 and 2022:

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:

(in thousands) Line Limit Amount Outstanding Letters

of Credit Amount Available Amount Available

of Credit Amount Available

OTC Credit Agreement $ 170,000 $ — $ — $ 170,000

$ 170,000 $ — $ — $ 170,000 $ 170,000

OTP Credit Agreement 220,000 69,615 8,772 141,613

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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, 2023, we had $249.4 million of available liquidity under our credit facilities and $230.4 million of available cash and cash equivalents, resulting in total available liquidity of $479.8 million, compared to total available liquidity of $441.2 million as of December 31, 2022.

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.

The following is a discussion of our cash flows for the years ended December 31, 2024 and 2023:

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Net Cash Provided by Operating Activities $ 452,731 $ 404,499

Net Cash Provided by Operating Activities increased $15.2 million primarily due to an increase in net income, the absence of any pension contribution in 2023 due to the plan's funded status, and the timing of customer collections of forecasted fuel costs, partially offset by increased working capital.

Working capital increased primarily due to an increase in receivables in our Plastics segment, due to increased sales volumes in the fourth quarter of the current year, and a decrease in payables due to the timing of capital investment spending in our Electric segment and inventory purchases in our Plastics segment compared to last year.

Unique market dynamics experienced by our Plastics segment businesses in 2023 and 2022 resulted in a significant increase in our overall cash from operations compared to prior periods, and we do not expect cash from operations at these levels to continue in future years.

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.

(in thousands) 2024 2023

Net Cash Used in Investing Activities $ 411,374 $ 289,287

Net Cash Used in Investment Activities increased $114.2 million primarily due to a higher amount of Electric segment capital investment compared to last year, including the purchase of the Ashtabula III wind farm, investments in our Hoot Lake Solar facility and several wind repowering projects, transmission and distribution asset investments, and investments in new technology.

Capital expenditures in our Manufacturing and Plastics segments increased $23.1 million as a result of investments in additional equipment and facility expansion projects at our Plastics segment facility in Arizona and our Manufacturing segment facility in Georgia.

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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 Used in Financing Activities $ 3,835 $ 96,779

Net Cash Used in Financing Activities decreased $92.9 million primarily due to increased short-term borrowings on our OTP credit facility, which were primarily used to fund capital expenditures in our Electric segment, including the acquisition of the Ashtabula III wind farm.

Our financing activities in 2023 included net short-term borrowings of $73.2 million compared to net short-term repayments of $83.0 million in 2022.

There was no change in our long-term debt in 2023.

In 2022, OTP issued $60.0 million of long-term debt, net of retirements, which was primarily used to fund the repayment of short-term credit facility borrowings and fund capital expenditures.

In 2023, we made dividend payments of $73.1 million compared to $68.8 million in 2022.

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, 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 changes, business expansion opportunities, the costs of labor, materials and equipment and our financial condition.

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:

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Electric Segment:

$ 118 $ 93 $ 33 $ 113 $ 129 $ 486

51 85 111 98 100 445

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

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Total Capital Expenditures $ 287 $ 359 $ 278 $ 335 $ 374 $ 382 $ 186 $ 1,555

CONTRACTUAL OBLIGATIONS

The following table summarizes our contractual obligations at December 31, 2023 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.

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

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Coal Contracts 441 24 50 53 314

Capacity and Energy Requirements 4 — — — 4

Land Easements 62 2 4 4 52

Postretirement Benefit Obligations 65 5 11 11 38

Other Purchase Obligations (including land easements) 79 6 9 5 59

Operating Lease Obligations 35 6 10 6 13

Total Contractual Cash Obligations $ 2,161 $ 157 $ 227 $ 175 $ 1,602

Other Obligations

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, level of earnings and cash flows from operations, our capital expenditure plan and our future business prospects.

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.

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The decision to declare a dividend is reviewed quarterly by our Board of Directors.

On February 5, 2024, our Board of Directors increased the quarterly dividend from $0.4375 to $0.4675 per common share.

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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, borrowing capacity under our lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

Debt financing will be required in the five-year period from 2024 through 2028 to refinance maturing debt and to finance our capital investments within our Electric segment.

Our financing plans are subject to change and are impacted by our planned level of capital investments, a decision to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes.

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, 2021, we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement.

The registration statement expires in May 2024, at which time we anticipate filing a new shelf registration statement.

No shares were issued pursuant to the registration statement in 2023.

On May 3, 2021, we filed a second registration statement with the SEC for the issuance of up to 1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends or making optional cash investments.

Shares purchased under the plan may be new issue common shares or common shares purchased on the open market.

The registration statement expires in May 2024, at which time we plan to file a new registration statement.

In 2023, we issued 105,663 shares under the plan.

All shares issued under the plan to date have been open market purchases and there have been no new issue shares, resulting in no proceeds received by the Company.

As of December 31, 2023, 1,145,330 shares remained available for purchase or issuance under the plan.

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.

SHORT-TERM DEBT

The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit.

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 issuer.

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%.

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Interest Rate at Year-End 5.83 % 5.61 %

Expiration Date October 29, 2027 October 29, 2027

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

At December 31, 2023, we had $827.0 million of principal outstanding under long-term debt arrangements.

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.

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Financial Covenants

Certain of our short- and long-term debt agreements require OTC and OTP to maintain certain 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, 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, 2023, our Interest-Bearing Debt to Total Capitalization was 0.39 to 1.00, our Interest and Dividend Coverage Ratio was 10.85 to 1.00 and we had no Priority Indebtedness outstanding.

OTP, under its financial covenants, may not permit its ratio of Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Debt to exceed 20% of its Total Capitalization.

As of December 31, 2023, OTP's Interest-Bearing Debt to Total Capitalization was 0.46 to 1.00, its Interest and Dividend Coverage Ratio was 3.54 to 1.00 and it had no Priority Indebtedness outstanding.

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.

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Credit Ratings

The credit ratings of OTC and OTP as of December 31, 2023 are summarized below:

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

Senior Unsecured Debt n/a BBB

Outlook Stable Stable Stable Stable Stable Stable

CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and the Company’s discussion and analysis of its financial condition and operating results requires management to make assumptions, estimates and judgments that affect the reported amounts.

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

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.

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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 statement 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.

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.

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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 statement of income as an expense or income item, or in the consolidated statement of comprehensive income as a loss or gain item, in the period in which this accounting treatment is no longer applicable.

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.

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PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS

Pension and postretirement benefit liabilities and expenses are determined by actuaries using assumptions about the discount rate, expected return on plan assets, rate of compensation increase and healthcare cost-trend rates.

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.

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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.

Pension plan assets are invested in a portfolio according to our return, liquidity and diversification objectives to provide a source of funding for plan obligations and manage contributions to the plan.

The principal process for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.

At December 31, 2023, we set the discount rate used to measure our pension plan obligations at 5.57% and at 5.53% to measure postretirement healthcare obligations, a six and one basis point increase, respectively, from the estimates used at December 31, 2022.

Our estimates used to determine benefit cost for 2023 included a discount rate of 5.51% for pension benefits and 5.52% for postretirement healthcare costs, a 248 and 251 basis point increase, respectively, from 2022 estimates.

The 5.52% discount rate for postretirement healthcare costs was adjusted to 6.06% effective September 30, 2023, in connection with a remeasurement of our plan liability due to an amendment to the plan.

The adjustment to 6.06% was a 305 basis point increase from the 2022 estimate.

In addition, we estimated our assumed rate of return on pension assets to be 7.00% for 2023, a 70 basis point increase from our 2022 estimate.

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:

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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 footnote 10 of the consolidated financial statements.

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.

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Goodwill is tested for impairment at the reporting unit level.

We have identified two reporting units which carry a material amount of goodwill.

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.

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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 primarily using an income approach, which includes 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.

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.

To supplement our income approach, we reference various market indications of fair value, where available, and include fair value estimates using multiples derived from comparable enterprise values to earnings before interest, taxes, depreciation, and amortization (EBITDA), 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 estimated terminal growth rate and the selection of an appropriate weighted-average cost of capital, among others.

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.

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 1% decrease in projected operating revenues, a one hundred basis point decrease in projected gross profit margins and a twenty five basis point increase in the discount rate would not lead to a goodwill impairment charge for either reporting unit.

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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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis