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Item 7. Management’s Discussion and Analysis

2026-02-18 compared with 2025-02-19 · 185 added, 193 removed, 270 unchanged (58% of the section changed)

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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 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.

2025 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.

In 2025, our diversified business model generated strong financial results, producing net income of $275.9 million, or $6.55 per diluted share.

As expected, our earnings declined from the record level achieved in 2024 when we generated earnings of $301.7 million, or $7.17 per diluted share.

As we anticipated, product prices within our Plastics segment continued to decline in 2025 leading to the reduction in earnings compared to the prior year.

We anticipate earnings from our Plastics segment will continue to decline through 2027 until such time that product pricing is expected to stabilize.

We generated $386.0 million of cash from operations in 2025 and ended the year with total available liquidity of $705.5 million.

Our year-end equity ratio to total capital was 62.8%.

We paid dividends totaling $2.10 per share, or $88.1 million, marking our 87th consecutive year of dividend payments to our shareholders.

Our Electric segment generated 7% earnings growth in 2025, producing earnings of $97.6 million.

Our earnings growth was driven by the recovery of our rate base investments, which include investments in new generation and enhancements to our transmission and distribution system to promote reliable electric service.

We also benefited from increased sales volumes in 2025, partially the result of favorable weather conditions compared to last year which impacted our customers' demand for energy, and lower operating and maintenance costs.

Earnings in our Manufacturing segment decreased 16% in 2025 to $11.5 million.

Our sales volumes in the year were negatively impacted by soft end-market demand and customer inventory management efforts within many of the end markets we serve.

Weak farm economics, persistently elevated interest rates, a cautious consumer and tariff uncertainty led to demand headwinds.

We were able to partially mitigate the financial effects of lower sales volumes through cost-management efforts aligning our cost structure with the current demand environment, and enhanced production efficiencies.

Our Plastics segment earnings decreased 15% in 2025 to $170.4 million.

As anticipated, sales prices for our PVC pipe products, after peaking in 2022, have gradually declined, including in 2025 when average prices declined 15% compared to the prior year.

This pricing decline was the primary driver of our lower earnings in 2025.

Partially offsetting the decline in product pricing was reduced material input costs and higher sales volumes.

Our sales volumes in 2025 benefited from the additional production capacity and large diameter pipe capability installed at our Phoenix location in late 2024.

In 2025, our earnings mix was 35% from our Electric segment and 65% from the combination of our Manufacturing and Plastics segments including unallocated corporate costs.

Since 2021, this mix has diverged from our long‑term target of 70% Electric and 30% Manufacturing Platform, largely due to market conditions in the PVC pipe industry.

These conditions have resulted in elevated revenue, earnings, and cash flow in our Plastics segment.

We currently expect industry conditions within the PVC pipe market to gradually normalize through 2027.

As this normalization occurs, we anticipate that earnings and cash flow from our Plastics segment will moderate from current levels and that our earnings mix will shift back toward our long‑term target.

FINANCIAL AND OTHER METRICS

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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.

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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.

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.

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Net Income $ 275,893 $ 301,662 $ (25,769) (8.5) %

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.

Operating Revenues decreased $26.5 million in 2025 primarily due to decreased sales prices in our Plastics segment and decreased sales volumes in our Manufacturing segment, partially offset by increased sales volumes in our Plastics segment as well as increased fuel recovery revenues and sales volumes in our Electric segment.

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.

Operating Expenses increased $8.1 million in 2025 primarily due to an increase in purchased power costs, production fuel costs, and depreciation expense in our Electric segment, partially offset by lower cost of goods sold driven by decreased sales volumes in our Manufacturing segment and the impact of lower material costs in our Plastics segment, as well as lower operating and maintenance expenses in our Electric segment.

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.

Interest Expense increased $5.4 million in 2025 primarily due to the issuance of $100.0 million of long-term debt at OTP during the year, the proceeds of which were used to repay short-term borrowings, fund capital expenditures and support operating activities.

Nonservice Components of Postretirement Benefits decreased by $6.3 million in 2025, having a negative impact on net income, primarily due to a decrease in the amortization of postretirement plan amendment-related gains and an increase in the amortization of actuarial losses.

Income Tax Expense decreased $18.8 million in 2025 primarily due to a decrease in income before income taxes, as well as an increase in PTCs at OTP.

The increase in PTCs was the result of increased wind generation that qualified for tax credits.

We completed the first of our wind facility upgrades in late 2024 and completed additional upgrades throughout 2025.

The completion of these upgrades resulted in the commencement of PTCs earned from the generation at these facilities.

Our effective tax rate was 14.4% in 2025 and 17.8% in 2024, with the decrease primarily driven by the increase in PTCs.

ELECTRIC SEGMENT RESULTS

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Income Before Income Taxes 85,787 89,419 (3,632) (4.1)

Income Tax (Benefit) Expense

(1,544) 1,648 (3,192) (193.7)

Income Tax Benefit (11,799) (1,544) (10,255) 664.2

Net Income $ 97,586 $ 90,963 $ 6,623 7.3 %

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Effect on Diluted Earnings Per Share $ (0.03) $ 0.10 $ (0.13)

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.

Retail Revenue increased $30.8 million primarily due to the following:

• A $21.7 million increase in fuel recovery revenues due to higher purchased power and fuel costs, as described below.

• An $8.7 million increase primarily from recovery of rate base investments.

• A $6.1 million increase in sales volumes, exclusive of the impact of weather, primarily driven by increased customer usage.

• A $5.7 million increase from the impact of favorable weather compared to last year.

These increases were partially offset by a net decrease in rider revenues resulting from higher PTCs during the year following the completion of certain of our wind facility upgrades.

PTCs generated during the year increased $9.6 million.

These credits are generally passed through to customers, reducing retail revenue.

Wholesale Revenues increased $10.0 million due to a 29% increase in wholesale prices driven by increased fuel costs and market demand for wholesale energy, as well as a 48% increase in wholesale sales volumes.

Wholesale revenues, net of wholesale fuel costs, are generally returned to customers and result in a reduction of retail revenue.

Production Fuel costs increased $14.1 million driven by higher fuel consumption associated with increased generation at Big Stone Plant and our natural gas facilities in response to increased customer demand.

Higher natural gas prices also contributed to the increase in production fuel costs.

Purchased Power costs to serve retail customers increased $17.1 million due to a 20% increase in the price of purchased power, primarily due to increased market energy costs, as well as a 7% increase in the volume of purchased power driven by increased customer demand.

Operating and Maintenance Expenses decreased $6.1 million primarily due to decreased labor costs.

Compared to the last year, a greater percentage of labor hours were dedicated to capital investment projects, which resulted in an increase in capitalized labor costs and a corresponding reduction in operating and maintenance expenses.

External service provider costs also decreased compared to last year.

These decreases were partially offset by expenses related to a planned outage at Coyote Station during the year.

Depreciation and Amortization expense increased $8.0 million due to additional assets, including certain wind generation, transmission and distribution assets, being placed into service during the year.

Interest Expense increased $5.4 million primarily due to the issuance of an additional $100.0 million of long-term debt during the year, the proceeds of which were primarily used to repay short-term debt and fund our capital investments.

Nonservice Cost Components of Postretirement Benefits decreased by $6.2 million, having a negative impact on net income, due to a decrease in the amortization of plan amendment-related gains and an increase in the amortization of actuarial losses.

Income Tax Benefit increased $10.3 million primarily due to an increase in PTCs driven by increased wind generation that qualified for tax credits compared to last year.

PTCs are generally credited to customers and result in a reduction of operating revenue as well as income taxes.

MANUFACTURING SEGMENT RESULTS

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(2,506) (2,516) 10 (0.4)

Other Income — (1) 1 (100.0)

Income Before Income Taxes 14,394 16,576 (2,182) (13.2)

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Net Income $ 11,517 $ 13,681 $ (2,164) (15.8) %

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.

Operating Revenues decreased $28.0 million primarily driven by a 7% decline in sales volumes at our metal fabrication business, with reductions across several end markets, including agriculture, lawn and garden and recreational vehicles.

Sales volumes were negatively affected by soft end-market demand and inventory management efforts by manufacturers and dealers throughout much of the year, continuing a trend that began in the third quarter of 2024.

A 1% decrease in steel costs, which are passed through to customers, also contributed to the decrease in operating revenues.

Cost of Products Sold decreased $29.1 million primarily due to lower sales volumes.

Our gross profit margin increased to 24.1% in 2025 from 21.8% in the prior year.

This improvement was driven by cost management efforts made to align our cost structure with the current demand environment, and improved labor productivity and production efficiencies.

Selling, General, and Administrative Expenses increased $2.4 million primarily due to variable compensation costs.

Depreciation and Amortization expense increased $0.9 million, largely driven by our facility expansion and new equipment at our BTD location in Georgia, which were placed into service in early 2025.

PLASTICS SEGMENT RESULTS

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Net Income $ 170,400 $ 200,747 $ (30,347) (15.1) %

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.

Operating Revenues decreased $40.7 million primarily driven by a 15% decline in sales prices compared to last year.

Prices have been declining for several years after peaking in late 2022.

The impact of lower sales prices was partially offset by an 8% increase in sales volumes, largely driven by additional production capacity following the completion of the first phase of our expansion project at Vinyltech in late 2024.

Cost of Products Sold decreased $2.8 million primarily reflecting a 14% reduction in the cost of input materials, including PVC resin.

The reduction in PVC resin cost was driven by global supply and demand dynamics which has resulted in elevated resin supply.

This decrease was partially offset by higher sales volumes, as discussed above.

Selling, General, and Administrative Expenses increased $1.0 million primarily due to costs associated with ongoing litigation and related matters regarding the pricing of PVC pipe, which is further described in Note 14 to the consolidated financial statements.

There is considerable uncertainty regarding the timing of significant developments or the resolution of these matters.

As such, it is reasonably possible that our estimate of a loss, if any, arising from these matters could change in the near term and have a material impact on our future operating results.

Depreciation and Amortization expense increased $1.9, largely driven by our facility expansion and new equipment at Vinyltech, which were placed into service in late 2024.

Income Tax Expense decreased $10.6 million due to a decrease in income before taxes.

The following table summarizes Corporate results of operations for the years ended December 31, 2025 and 2024:

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Depreciation and Amortization 235 98 137 139.8

Operating Income (Loss)

(24,536) (12,144) (12,392) 102.0

Operating Loss 23,846 24,536 (690) (2.8)

Interest Expense

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Other Income 17,036 15,504 1,532 9.9

Income (Loss) Before Income Taxes

(10,494) (3,241) (7,253) 223.8

Loss Before Income Taxes 8,303 10,494 (2,191) (20.9)

Income Tax Benefit (4,693) (6,765) 2,072 (30.6)

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.

Net Loss $ 3,610 $ 3,729 $ (119) 3.2 %

Other Income increased $1.5 million driven by higher investment income earned on our short-term investments resulting from increased cash available for investment, as well as gains on our corporate-owned life insurance policies.

Income Tax Benefit decreased $2.1 million primarily due to a decrease in loss before taxes.

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.

The following includes a summary of electric rate cases as determined in OTP's most recent general rate case in each state:

The following includes a summary of electric rate cases as determined in OTP's most recently concluded general rate case in each state:

Revenue Allowed

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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.

(2) 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%.

South Dakota Rate Case

On June 4, 2025, OTP filed a request with the South Dakota Public Utilities Commission (SDPUC) for an increase in revenue recoverable under general rates in South Dakota.

In its filing, OTP requested a net increase in annual revenue of $5.7 million, or 12.50%, based on an allowed rate of return on rate base of 8.29% and an allowed ROE of 10.80% on an equity ratio of 53.54% of total capital.

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

Interim rates went into effect on December 1, 2025, and are subject to potential refund until the finalization of the rate case.

Minnesota Rate Case

On October 31, 2025, OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota.

In its filing, OTP requested a net increase in annual revenue of $44.8 million, or 17.7%, based on an allowed rate of return on rate base of 7.92% and an allowed ROE of 10.65% on an equity ratio of 53.5% of total capital.

The request includes, among other items, accelerated recovery of the remaining investment of the jurisdictionally allocated share of Coyote Station, which has a $4.3 million annual impact.

The request for accelerated recovery is driven by the MPUC’s order in OTP’s most recent IRP to discontinue serving Minnesota customers with capacity and energy from Coyote Station prior to the currently estimated end of its useful life.

If this part of the request is granted, we anticipate the amounts collected would be deferred and recognized over the remaining estimated useful life of the plant, which extends until 2041.

The filing also included an interim rate request for a net increase in annual revenue of $31.8 million, or 12.6%.

On December 23, 2025, the MPUC approved the interim rate request with a modification to exclude the impact of the accelerated recovery of the remaining investment of the jurisdictionally allocated share of Coyote Station from interim rates.

The resulting interim net increase in annual revenue is $28.6 million, or 11.3%.

Interim rates went into effect on January 1, 2026, and are subject to potential refund until the finalization of the rate case.

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

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.

04/01/25 9.5 12/01/25 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

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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.

09/15/25 5.1 02/01/26 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.

08/01/25 3.7 01/01/26 Recovery of advanced metering infrastructure and demand-response projects.

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

12/20/24 3.2 09/01/25 Recovery of Ashtabula III, Merricourt, Astoria Station, Abercrombie Solar, Solway Solar, wind upgrade projects, advanced metering infrastructure, outage management system, demand-response system, and impact of load-growth credits.

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

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.

In July 2025, the utility commissions from five states, including the NDPSC, filed a complaint with FERC challenging MISO’s analysis supporting the benefits of MISO’s Tranche 2.1 portfolio of transmission projects.

The complaint alleges that the benefits of the Tranche 2.1 projects do not exceed forecasted costs and contends that MISO lacks the authority to direct these projects under the current cost allocation system.

FERC has not established a timeline to review this matter and no statutory deadline exists.

OTP will be a co-owner of three projects within the Tranche 2.1 portfolio of projects, with an estimated total capital investment of approximately $800 million to $1.0 billion.

The complaint, FERC’s adjudication of it, and potential rehearing proceedings and legal challenges to the outcome, could delay OTP’s investments or result in the cancellation of the projects.

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.

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 our 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.

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Net Cash Provided by Operating Activities $ 385,985 $ 452,731

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.

Net Cash Provided by Operating Activities decreased $66.7 million primarily due to higher working capital requirements, largely in our Electric segment, and a decrease in earnings.

These working capital changes were largely driven by the timing of capital spending and the timing of fuel cost and rider recoveries from our utility customers.

Operating cash flows in our Electric segment may fluctuate materially from period to period because they are significantly influenced by the timing of payments for operating costs and the regulatory mechanisms through which we recover or return costs.

The timing of these recoveries and refunds varies depending on the specific cost-recovery mechanism approved by regulators.

As a result, cash provided by operating activities may differ significantly from net income in any given reporting period.

Market dynamics experienced by our Plastics segment businesses in 2025 and 2024 contributed to a substantial increase in consolidated cash from operations over this period.

We expect cash provided by operating activities in future years to decline from recent levels, consistent with the anticipated normalization of earnings in the Plastics segment.

(in thousands) 2025 2024

Net Cash Used in Investing Activities $ 290,724 $ 411,374

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.

Net Cash Used in Investment Activities decreased $120.7 million, primarily the result of a $70.6 million decrease in capital expenditures.

Capital expenditures in our Manufacturing and Plastics segments decreased $40.1 million following the completion of our expansion projects at Vinyltech and BTD Manufacturing in late 2024 and early 2025.

Capital expenditures in our Electric segment also decreased, primarily due to the timing of investments under our capital spending plan.

Investing activities in 2024 also included a $50.1 million investment in U.S.

treasuries, which was made to secure a fixed rate of return until their maturity in September 2026.

(in thousands) 2025 2024

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$ (3,719) $ 22,921

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.

Net Cash Used in Financing Activities totaled $3.7 million in 2025, compared with $22.9 million of net cash provided by financing activities in 2024.

Financing activities in 2025 included the issuance of $100.0 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.

In 2024, financing activities included the issuance of $120.0 million of long-term debt at OTP.

We manage OTP's capital structure independently from our consolidated financial position to ensure compliance with the capital structure approved

through regulation.

As a result, decisions related to the issuance of long-term debt at OTP are not influenced by our consolidated cash and cash equivalent position.

Financing activities during 2025 also included net repayments of short-term debt of $9.4 million, compared with net repayments of $11.8 million in 2024.

Dividend payments totaled $88.1 million in 2025, compared to $78.3 million in 2024.

CAPITAL REQUIREMENTS

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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:

The following provides a summary of capital expenditures for the years ended December 31, 2025 and 2024 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five-year period from 2026 through 2030:

(in millions) 2024 2025 2026 2027 2028 2029 2030 Total

Electric Segment:

Renewable Generation

Renewable Generation and Storage

$ 134 $ 91 $ 251 $ 295 $ 89 $ 4 $ 6 $ 645

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Interest on Debt Obligations 773 47 87 79 560

Coal Contracts 441 24 50 53 314

Land Easements 62 2 4 4 52

Coal Contract Obligations 417 24 51 53 289

Equipment Purchase Obligations 53 12 41 — —

Land Easement Payments

Postretirement Benefit Obligations 70 6 12 12 40

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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

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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.

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.

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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.

On January 8, 2026, our Board of Directors approved a quarterly dividend of $0.5775 per common share.

CAPITAL RESOURCES

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REGISTRATION STATEMENTS

On May 3, 2024, we filed two registration statements with the SEC, replacing two previously filed registration statements upon their expiration.

On May 3, 2024, we filed two registration statements with the SEC.

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.

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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.

Outstanding balances under these facilities bear interest at a variable rate comprised of a benchmark rate 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, 2025 and 2024 was 5.08% and 5.61%.

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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.

In March 2025, OTP entered into a Note Purchase Agreement pursuant to which OTP issued, in a private placement transaction, $100.0 million of senior unsecured notes consisting of (a) $50.0 million of 5.49% Series 2025A Senior Unsecured Notes due March 27, 2035, and (b) $50.0 million of 5.98% Series 2025B Senior Unsecured Notes due June 5, 2055.

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.

As of December 31, 2025, we had $1.0 billion 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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Moody's Fitch S&P Moody's Fitch S&P

Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB BBB A3 BBB+ BBB+

Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB BBB Baa1

Senior Unsecured Debt n/a BBB n/a n/a A- n/a

Outlook Stable Stable Stable Negative

Outlook Stable Stable Positive

Stable Stable

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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 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.

Accordingly, our utility business must adhere to the accounting requirements of regulated operations, which require 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 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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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.

Our probability estimates incorporate numerous factors, including recent rate-making decisions, historical precedents for similar matters, the current 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.

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, 2025 and 2024, we had regulatory assets of $106.5 million and $108.6 million and regulatory liabilities of $314.0 million and $318.2 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 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.

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:

Pension and postretirement benefit liabilities and expenses are actuarially determined and incorporate numerous assumptions, including a discount rate, an expected return on plan assets, compensation changes, healthcare cost-trend rates and other demographic assumptions.

These assumptions are reviewed annually, or more frequently under certain circumstances.

Discount Rate - the discount rate used to measure pension and other postretirement benefit obligations should reflect the rate at which the obligations could be effectively settled as of the measurement date.

We estimate the discount rate using 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.

Lower discount rates increase the benefit obligation and future pension expense, while higher discount rates reduce such amounts.

Expected Return on Plan Assets - we estimate the long-term expected rate of return on pension plan assets based on asset category studies using historical returns and forward-looking capital market assumptions based on our asset allocation.

Differences between expected and actual returns are recognized as actuarial gains or losses and amortized to expense over time.

Other Assumptions - additional assumptions applicable to the measurement of benefit obligations and expense for some or all of our plans include projected participant compensation changes, healthcare cost trends, mortality or life expectancy, and other demographic assumptions.

We estimate these items by reference to relevant third-party information, internal projections and historical experience of our plan participants.

Differences between our assumptions and actual results are recognized as actuarial gains or losses and amortized to expense over time.

Actuarial gains and losses reflect differences between actual plan experience and our actuarial assumptions, as discussed above.

Such actuarial gains and losses can materially impact our benefit obligations, in certain instances plan funding requirements, and plan expense.

Actuarial gains and losses are initially recognized as a component of accumulated other comprehensive income or as a regulatory asset or liability and are subsequently amortized to plan expense.

We have elected to apply a corridor approach as allowed under applicable accounting standards to determine the amount of actuarial gains and losses amortized to plan expense.

This approach is intended to moderate short-term fluctuations in pension expense.

Under the corridor method, actuarial gains and losses are amortized to plan expense only when they exceed 10% of the greater of the benefit obligation or, where applicable, the market value of plan assets for our funded pension plan.

Cumulative gains and losses in excess of the 10% threshold are amortized to plan expense generally over the expected average remaining future service period of active plan participants, which for our pension plan is currently approximately 10 years.

The Company sponsors a noncontributory funded pension plan (the Pension Plan), an unfunded, nonqualified Executive Survivor and Supplemental Retirement Plan (ESSRP), both accounted for as defined benefit pension plans, and a postretirement healthcare plan accounted for as an other postretirement benefit plan.

The following table summarizes the discount rates used to measure our pension plan and other postretirement obligations, as well as the assumed rate of return on pension plan assets for our funded pension plan, as of December 31, 2025 and 2024:

2025 2024 change

Pension Plan (Pension):

Discount Rate 5.71 % 5.70 % 1 bp

Long-Term Return on Plan Assets 7.00 % 7.00 % —

Pension Plan (ESSRP):

Discount Rate 5.46 % 5.60 % (14 bps)

What changed 10-K

Item 7. Management’s Discussion and Analysis