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Item 7. Management’s Discussion and Analysis

2024-02-14 compared with 2023-02-15 · 197 added, 184 removed, 240 unchanged (61% of the section changed)

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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 targeted annual growth in earnings per share of five to seven percent over the next several years, using 2024 as the base for measurement.

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%.

2023 FINANCIAL RESULTS

In 2023, our diversified business model generated record financial results, producing net income of $294.2 million, or $7.00 per diluted share, an increase of 4% from $284.2 million, or $6.78 per diluted share, in 2022.

All three of our operating segments produced double digit earnings growth in 2022 compared to the prior year, led by our Plastics segment, which capitalized on the continuation of unique market conditions to produce extraordinary financial results.

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.

In 2023, we paid an annual dividend of $1.75 per share, or $73.1 million, completing our 85th consecutive year of dividend payments to our shareholders.

Our Electric segment produced earnings growth of 10% in 2022, driven by increased customer demand from commercial and industrial customers, including the addition of a new large commercial customer in North Dakota, and the impacts of favorable weather.

We continued the construction of rate base investments, including our Hoot Lake Solar project, which we anticipate will be in commercial operation by the end of 2023.

Our utility also accomplished all of its key regulatory objectives for the year, including completing a general rate case in Minnesota, with final rates becoming effective on July 1, 2022, and securing all necessary approvals to acquire the Ashtabula III wind farm, which was finalized and purchased on January 3, 2023.

Our Manufacturing segment produced earnings growth in 2022 of 22%, as strong end market demand across most markets we serve led to increased sales volumes.

Pricing increases and favorable cost absorption offset increased labor, material, and overhead costs, which resulted in consistent gross profit levels.

Our Manufacturing segment was also impacted in 2022 by steel price volatility, as further discussed below.

Our Plastics segment produced earnings of $195.4 million in 2022, compared to $97.8 million in 2021.

The unprecedented level of earnings in 2022 resulted from extraordinary industry supply and demand dynamics which emerged in 2021 and continued into 2022.

As further described below, increases in the price of resin, the primary raw material used in the manufacturing of PVC pipe, coupled with robust end market demand for PVC pipe led to a rapid escalation in PVC pipe prices and gross margins in 2021 and into 2022.

Resin prices declined from peak levels in the second half of the year, and pipe distributors and contractors reduced purchase volumes and inventory levels in response to changing market conditions.

Despite softening demand in the second half of the year, strong pipe sales prices and profit margins resulted in earnings growth of 100% in 2022.

Our earnings mix in 2022 was 28% from our Electric segment and 72% from the combination of our Manufacturing and Plastics segments net of 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 that occurred in our Plastics segment.

We expect our earnings mix to return to our targeted mix of 65% from the Electric segment and 35% from the Manufacturing and Plastics segments in 2024.

STEEL PRICING

Volatility in the price of steel, a key material input to our Manufacturing segment, significantly impacted our operating results in 2022.

Steel prices increased rapidly throughout 2021, peaking in the fourth quarter at historically high levels.

Steel prices, which were highly volatile in 2022, began to steadily decline at the end of the second quarter and returned to near historical levels by the end of the year.

The increase in steel prices led to increased sale prices for our products at BTD, our metal fabrication business within our Manufacturing segment, as we passed along material cost increases to our customers.

Scrap metal prices, which typically follow steel prices, also increased throughout 2021 and remained elevated in the first half of 2022, but declined sharply throughout the second half of the year, negatively impacting our 2022 financial results.

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

PVC resin is the primary material input of the PVC pipe manufactured by our Plastics segment businesses.

Resin supply disruptions throughout 2021, along with robust domestic and global demand for PVC resin, led to significantly increased resin prices.

Supply disruptions for resin and other additives and ingredients used in the manufacturing process also resulted in reduced manufacturing of PVC pipe and low pipe inventories across the industry.

This combination of disrupted raw material supply and the resulting low PVC pipe inventories, along with robust demand for PVC pipe, led to rapidly increasing sale prices for PVC pipe throughout 2021 and 2022.

The increase in sale prices outpaced the increase in PVC resin costs and led to expanding gross profit margins which positively impacted our 2022 financial results.

However, beginning in the third quarter of 2022, demand for PVC pipe began to decline as PVC pipe distributors and contractors reduced purchase volumes and inventory levels in response to changing market conditions.

The unique market dynamics experienced by our Plastics segment businesses in 2021 and 2022 resulted in a significant increase in earnings compared to prior periods.

We currently expect earnings of our Plastics segment to decrease in 2023, but to remain elevated relative to historical levels.

We currently expect segment earnings to normalize in 2024, as industry supply and demand conditions normalize throughout 2023.

The marketplace dynamics impacting both our Manufacturing and Plastics segments are fluid and subject to change which may impact our operating results prospectively.

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.

The marketplace dynamics impacting our Plastics segments are fluid and subject to change and may impact our operating results prospectively.

FINANCIAL AND OTHER METRICS

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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, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits dependent on the method that is used in the calculation, which can vary from jurisdiction to jurisdiction.

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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Operating Income 377,919 390,439 (12,520) (3.2)

Interest Charges 36,016 37,771 (1,755) (4.6)

Nonservice Cost Components of Postretirement Benefits (1,075) 2,016 (3,091) (153.3)

Other Income 2,037 2,900 (863) (29.8)

Interest Expense

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

Nonservice Components of Postretirement Benefits

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

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

Income Before Income Taxes 363,489 357,535 5,954 1.7

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Net Income $ 294,191 $ 284,184 $ 10,007 3.5 %

Operating Revenues increased $263.4 million on a consolidated basis in 2022.

Each operating segment contributed to the overall growth.

Electric segment operating revenues increased 14% primarily due to increased fuel recovery revenues and higher sales volumes.

Manufacturing segment operating revenues increased 18% mainly as a result of higher sales volumes and increased pricing to pass through material input costs.

Plastics segment operating revenues increased 35% due to an increase in the price per pound of PVC pipe sold, partially offset by decreased sales volumes.

Operating Revenues decreased $111.0 million on a consolidated basis in 2023.

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.

See our segment disclosures below for additional discussion of items impacting operating revenues.

Operating Expenses increased $122.6 million in 2022.

Electric segment operating expenses increased 17% primarily due to increased purchased power costs resulting from increased purchase volumes and higher operating and maintenance expenses.

Operating expenses in our Manufacturing segment increased 18%, driven by increased cost of products sold, which resulted from higher material input costs and increased sales volumes.

Operating expenses in our Plastics segment were consistent year over year due to lower sales volumes which were offset by higher costs of products sold from higher resin costs and increased operating costs.

Operating Expenses decreased $98.5 million in 2023.

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.

See our segment disclosures below for additional discussion of items impacting operating expenses.

Interest Charges decreased $1.8 million in 2022 primarily due to a decrease in our average short-term borrowings, partially offset by increased interest rates on our short-term borrowings and a net increase in our long-term debt of $60.0 million.

The increase in our long-term debt was largely used to finance rate base investments in our Electric segment.

Nonservice Cost Components of Postretirement Benefits decreased $3.1 million in 2022 primarily due to the amortization of actuarial gains resulting from the increase in the discount rates used to measure our pension benefit and other postretirement benefit liabilities as of December 31, 2021.

Other Income decreased $0.9 million in 2022 primarily due to investment losses on our corporate-owned life insurance policies and the investments of our captive insurance entity.

Income Tax Expense increased $37.3 million in 2022 primarily due to an increase in income before income taxes.

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.

Income Tax Expense decreased $4.1 million in 2023 primarily due to an increase in PTCs produced by our wind and solar generation assets.

Our effective tax rate was 19.1% in 2023 and 20.5% in 2022.

See Note 12 to our consolidated financial statements included in the report on Form 10-K for additional information regarding factors impacting our effective tax rate.

See Note 12 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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Cooling Degree Days 127.2 % 113.5 %

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions for the years ended December 31, 2022 and 2021, and between years:

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, 2023 and 2022, and between years:

2023 vs Normal 2023 vs 2022 2022 vs Normal

Effect on Diluted Earnings Per Share $ 0.02 $ (0.09) $ 0.11

Retail Revenues increased $64.8 million primarily due to the following:

• A $42.5 million increase in fuel recovery revenues primarily due to increased purchased power volumes and pricing to recover production fuel costs, as described below.

• A $12.8 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.

• A $5.4 million increase in revenues from the favorable impact of weather compared to last year.

• A $4.1 million increase in interim rate revenue due to the finalization of the interim rate refund, as approved by the MPUC in the second quarter of 2022.

Retail revenues also benefited from increased transmission, renewable and phase-in rider revenue in 2022.

These increases were partially offset by a decrease in CIP revenue as a result of decreased CIP spending and related cost recovery.

Transmission Services Revenues increased $3.4 million primarily due to increased recovery of higher transmission costs and increased transmission investments along with increased transmission volumes and formula rate adjustments.

Production Fuel costs increased $5.8 million due to a 22% increase in fuel cost per kwh, which was partially offset by a decrease in kwhs generated from our fuel-burning plants due to an outage at Coyote Station in 2022, and the retirement of Hoot Lake Plant in May 2021.

Purchased Power costs to serve retail customers increased $34.9 million due to a 54% increase in the volume of purchased power, resulting from outages at both Coyote Station and Big Stone Plant, the retirement of Hoot Lake Plant and increased customer demand.

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 $6.7 million increase in employee compensation and benefit costs, including discretionary incentive and retirement benefit compensation based on current year financial results.

• A $3.7 million increase in transmission tariff expenses.

• A $3.3 million increase in maintenance and other costs due to our plant outages at Coyote Station and Big Stone Plant during the year.

• A $1.4 million increase in travel costs driven by higher fuel costs for our vehicle fleet and increased travel activities.

• Other additional costs including additional maintenance costs, increases in information technology expenses, increases in insurance costs and various other expenses.

These expense increases were partially offset by, among other items, a $2.1 million reduction in CIP expenses compared to the previous year.

• 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.

MANUFACTURING SEGMENT RESULTS

The following table summarizes operating results of our Manufacturing segment for the years ended December 31, 2022 and 2021:

The following table summarizes the operating results of our Manufacturing segment for the years ended December 31, 2023 and 2022:

(in thousands) 2023 2022 $ change % change

Operating Revenues $ 402,781 $ 397,983 $ 4,798 1.2 %

Cost of Products Sold 315,375 259,581 55,794 21.5

Other Operating Expenses 37,341 37,163 178 0.5

Cost of Products Sold (excluding depreciation)

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

Selling, General, and Administrative Expenses

44,545 37,341 7,204 19.3

Depreciation and Amortization 18,495 16,202 2,293 14.2

Operating Income $ 29,140 $ 29,065 $ 75 0.3 %

Operating Revenues increased $61.7 million primarily due to the following:

• At BTD, operating revenues increased $52.8 million 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.

Material costs, which are passed through to customers, increased 8%, as annual steel prices increased from the previous year.

Steel prices increased drastically in 2021, peaking in the fourth quarter, and remained elevated compared to historical levels throughout the first half of 2022.

Increases in sales volumes and prices were partially offset by a $2.5 million decrease in scrap revenues due to a decrease in both scrap metal prices and scrap volumes.

Plastics, revenues increased $8.8 million due to a combination of increased sales prices and higher sales volumes.

Sales prices increased 16% and sales volumes increased 7% due to strong customer demand primarily in horticulture product sales.

Cost of Products Sold increased $55.8 million due to the following:

• Cost of products sold at BTD increased $50.2 million primarily due to higher sales volumes and increased material costs, as discussed above.

Cost of products sold also increased due to higher labor and overhead costs, partially offset by lower freight costs.

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 increased $5.6 million primarily due to higher sales volumes, primarily in horticulture product sales, partially offset by favorable cost absorption.

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.

Depreciation and Amortization increased $2.3 million due to capital expenditures during the year, which included investments in facility improvements and purchases of equipment.

PLASTICS SEGMENT RESULTS

The following table summarizes operating results for our Plastics segment for the years ended December 31, 2022 and 2021:

The following table summarizes the operating results for our Plastics segment for the years ended December 31, 2023 and 2022:

(in thousands) 2023 2022 $ change % change

Operating Revenues $ 418,026 $ 512,527 $ (94,501) (18.4) %

Cost of Products Sold 227,569 228,789 (1,220) (0.5)

Other Operating Expenses 16,175 14,326 1,849 12.9

Cost of Products Sold (excluding depreciation)

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

Selling, General, and Administrative Expenses

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

Depreciation and Amortization 4,027 4,205 (178) (4.2)

Operating Income $ 254,402 $ 264,578 $ (10,176) (3.8) %

Operating Revenues increased $132.3 million primarily due to a 66% increase in the price per pound of PVC pipe sold, as sales prices remained high and continued to increase in 2022, due to a continuation of extraordinary market conditions first experienced in the previous year.

Sales volumes decreased 19% due to raw material constraints in the first half of 2022 and softening customer demand during the second half of 2022 driven by contractors delaying projects due to supply chain issues, softening housing market outlook, and customers reducing purchases of PVC pipe in order to use up existing on hand inventory.

Cost of Products Sold decreased $1.2 million primarily due to a 19% decrease in sales volumes, partially offset by a 22% increase in the cost per pound of PVC pipe sold, largely due to higher resin costs.

Other Operating Expenses increased $1.8 million due to increases in various cost categories including compensation costs and sales commissions.

CORPORATE COSTS

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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.

The following table summarizes Corporate results of operations for the years ended December 31, 2023 and 2022:

(in thousands) 2023 2022 $ change % change

Other Operating Expenses $ 16,202 $ 13,905 $ 2,297 16.5 %

Selling, General, and Administrative Expenses

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

Depreciation and Amortization 102 140 (38) (27.1)

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

Other Operating Expenses increased $2.3 million primarily due to increased external service costs during the year, as well as increased employee compensation and other costs.

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.

REGULATORY MATTERS

The following provides a summary of OTP's current general rates and a summary of recent rate case filings and rate rider filings that have or are expected to have a material impact on our operating results, financial position, or cash flows.

GENERAL RATES

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

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:

Revenue Allowed

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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%.

Minnesota Rate Case:

On November 2, 2020, OTP filed an initial request with the MPUC for an increase in revenue recoverable through base rates in Minnesota, and on December 3, 2020, the MPUC approved an interim annual rate increase of $6.9 million, or 3.2%, effective January 1, 2021.

On February 1, 2022, the MPUC issued its written order on final rates.

The key provisions of the order included a revenue requirement of $209.0 million, based on a return on rate base of 7.18% and an allowed ROE of 9.48% on an equity ratio of 52.5%.

The order also authorized recovery of our remaining Hoot Lake Plant net asset over a five-year period and approved the requested decoupling mechanism for most residential and commercial customer rate groups with a cap of 4% of annual base revenues.

On May 12, 2022, OTP's final rate case compliance filing was approved by the MPUC.

The filing included final revenue calculations, rate design, and resulting tariff revisions, along with a determination of the interim rate refund, which resulted in an increase in revenues in 2022 of $4.1 million.

Final rates took effect on July 1, 2022, and interim rate refunds of $15.3 million were completed in the third quarter of 2022.

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

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

Recovery Filing Amount Effective

Mechanism Jurisdiction Status Date (in millions) Date Notes

RRR - 2022 MN Requested 11/01/22 $17.5 07/01/23 Includes the recovery of the Hoot Lake Solar Project, the purchase of the Ashtabula III wind farm, and true up PTCs in base rates to actual PTCs generated at the Merricourt wind farm.

CIP - 2022 MN Approved 04/01/22 10.8 10/01/22 Includes recovery of energy conservation improvement costs as well as a demand side management financial incentive.

CIP - 2021 MN Approved 04/01/21 9.4 12/01/21 Includes recovery of energy conservation improvement costs as well as a demand side management financial incentive.

TCR - 2021 MN Approved 11/23/21 7.2 08/01/22 Includes recovery of two new transmission projects.

RRR - 2021 MN Approved 12/06/21 7.0 08/01/22 Includes return on Hoot Lake Solar construction costs and costs associated with the acquisition of the Ashtabula III wind farm.

RRR - 2023 ND Requested 12/30/22 17.0 04/01/23 Includes recovery of Ashtabula III investment, along with other proposals, see additional information below.

RRR - 2021 ND Approved 03/07/21 11.8 04/01/21 Includes recovery of Merricourt investment and operating costs.

RRR - 2022 ND Approved 01/05/22 7.8 04/01/22 Includes Merricourt recovery, the proposed purchase of Ashtabula III, and credits related to deferred taxes and PTCs.

TCR - 2022 ND Approved 09/15/22 7.5 01/01/23 Includes recovery of three new transmission projects, one transmission rebuild project, and six transmission projects related to extending the useful life of transmission assets.

TCR - 2021 ND Approved 09/15/21 6.1 01/01/22 Includes recovery of three new transmission projects/programs.

TCR - 2020 ND Approved 08/31/20 5.6 01/01/21 Includes recovery of eight new transmission projects.

GCR - 2021 ND Approved 03/01/21 5.2 07/01/21 Includes recovery of Astoria Station, net of anticipated savings associated with the retirement of Hoot Lake Plant.

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.

12/04/23 8.0 07/01/24 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.

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.

GCR - 2022 ND Approved 03/01/22 3.3 07/01/22 Annual update to generation cost recovery rider.

AMDT - 2022 ND Approved 07/08/22 3.1 01/01/23 Includes recovery of the advanced metering infrastructure, outage management system, and demand response projects.

PIR - 2022 SD Approved 06/01/22 3.0 09/01/22 Includes recovery of the Ashtabula III wind farm purchase, Merricourt, Astoria Station, and the Advanced Grid Infrastructure project, as well as load growth credits.

TCR - 2023 SD Requested 11/01/22 3.0 03/01/23 Includes the recovery of one new and four previously approved transmission projects.

TCR - 2022 SD Approved 10/29/21 2.2 03/01/22 Annual update to TCR rider.

TCR - 2021 SD Approved 10/30/20 2.2 03/01/21 Includes recovery of two new transmission projects.

Renewable Resource Rider (RRR) and Energy Adjustment Rider (EAR):

On December 30, 2022, OTP filed an update to its North Dakota RRR.

The update included, among other items, a request to modify load allocation factors in North Dakota given the large new load added in the state in 2022.

If approved, the load allocation factor change would produce an additional $4.4 million of rider recovery over a 12 month period.

On January 23, 2023, OTP filed an update to its North Dakota EAR proposing to refund MISO planning resource auction revenues to North Dakota customers if the NDPSC approves the load allocation factor modification as filed in the RRR docket.

If approved, OTP would refund approximately $4.2 million of planning resource auction revenues to North Dakota customers.

MISO PLANNING RESOURCE AUCTION

OTP offered 88-megawatts of excess capacity into the annual MISO planning resource auction for the period June 2022 through May 2023.

As a result of a capacity shortage in the MISO region, capacity prices cleared the auction at maximum pricing.

As a result, the 88-megawatts of auctioned capacity will generate approximately $9.3 million of net capacity auction revenues over the twelve month period ending in May 2023.

We anticipate the Minnesota allocated portion of net capacity auction revenues will be returned to customers through the FCA mechanism in the state, and the majority of the net capacity auction revenues allocated to our other jurisdictions will be used to mitigate customer rate increases or returned to customers through various mechanisms.

INTEGRATED RESOURCE PLAN

The MPUC recently approved a change to the procedural schedule for our 2022 IRP, which was originally filed in September 2021, and we plan to file an updated IRP in March 2023.

In conjunction with the updated IRP, our preferred plan could change based on the results of the updated resource modeling we perform, incorporating recent changes affecting the energy industry and the passing of the IRA, as well as other changes.

A change to our preferred plan could ultimately impact the nature, timing and amount of future capital investments, as well as the potential for OTP's withdrawal from Coyote Station, and could have a material impact on our operating results, financial position or cash flows.

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.

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.

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, can be impacted by macroeconomic factors outside of our control.

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.

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of Credit Amount Available Amount Available

Otter Tail Corporation Credit Agreement $ 170,000 $ — $ — $ 170,000 $ 147,363

OTC Credit Agreement

$ 170,000 $ — $ — $ 170,000 $ 170,000

OTP Credit Agreement 170,000 81,422 9,132 79,446 152,223

Total $ 340,000 $ 81,422 $ 9,132 $ 249,446 $ 322,223

We have an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the OTC Credit Agreement.

Should additional liquidity be needed, this agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions.

OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit.

Should additional liquidity be needed, the OTC Credit Agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions.

The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 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.

The following is a discussion of our cash flows for the years ended December 31, 2023 and 2022:

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Net Cash Provided by Operating Activities $ 404,499 $ 389,309

Net Cash Provided by Operating Activities increased $158.1 million primarily due to a $107.4 million increase in net income and a lower level of working capital needs compared to the previous year.

Our working capital decrease was primarily the result of a $30.6 million decrease in accounts receivable and a $5.3 million decrease in inventories, which exceeded the decrease in accounts payable and accrued and other liabilities.

The decrease in accounts receivable was primarily due to decreased sales prices in our Manufacturing segment in the second half of the year, as steel prices declined from historically high levels in 2021, and decreased sales volumes in our Plastics segment in the second half of the year, as customer demand softened.

The decrease in inventories was largely the result of decreased material costs within our Manufacturing segment, due to the decrease in steel prices.

The decrease in accounts payable was largely due to the decreased material costs in our Manufacturing segment and decreased sales volumes in our Plastics segment in the second half of the year.

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.

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Net Cash Used in Investing Activities $ 289,287 $ 175,071

Net Cash Used in Investment Activities increased $3.6 million due to a $7.8 million increase in capital investments in our Electric segment, combined with a decrease in proceeds received from the sale of debt and equity securities at our captive insurance entity, largely offset by a decrease in capital investments in our Manufacturing and Plastics segments.

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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(in thousands) 2023 2022

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

Net Cash Used in Financing Activities increased $37.4 million primarily due to repayments of short-term borrowings, partially offset by increases in long-term debt.

Our financing activities in 2022 included the issuance of $90.0 million of long-term debt and the maturity and repayment of $30.0 million of debt at OTP, net repayments of short-term borrowings of $83.0 million, which were repaid with available cash resulting from increased cash from operations, and dividend payments of $68.8 million.

In 2021, $140.0 million of long-term debt was issued and used to repay $140.0 million of maturing long-term debt at OTP, we incurred $10.1 million of net short-term borrowings on our lines of credit, and paid $64.9 million in dividends.

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.

CAPITAL REQUIREMENTS

CAPITAL EXPENDITURES

We have a capital expenditure program for expanding, upgrading and improving our facilities and operating equipment.

Typical uses of cash for capital expenditures are investments in electric generation facilities and environmental upgrades, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems.

Our capital expenditure program 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, 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.

The following provides a summary of capital expenditures for the years ended December 31, 2023 and 2022 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2024 through 2028:

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Electric Segment:

Renewables and Natural Gas Generation $ 88 $ 119 $ 88 $ 79 $ 10 $ 384

Technology and Infrastructure 33 30 6 5 1 75

Distribution Plant Replacements 33 37 38 38 43 189

Transmission (includes replacements) 34 36 46 87 78 281

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

51 85 111 98 100 445

38 39 36 38 39 190

Other 67 37 30 27 25 186

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Total Capital Expenditures $ 171 $ 287 $ 353 $ 289 $ 237 $ 301 $ 319 $ 1,499

Total Electric Utility Average Rate Base $ 1,575 $ 1,624 $ 1,750 $ 1,850 $ 1,990 $ 2,110 $ 2,210

Rate Base Growth 13.7 % 3.1 % 7.8 % 5.7 % 7.6 % 6.0 % 4.7 %

CONTRACTUAL OBLIGATIONS

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

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 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 a contribution to that plan.

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.

COMMON STOCK DIVIDENDS

We paid dividends to our shareholders totaling $73.1 million, or $1.75 per share, in 2023.

The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, improvement in earnings per share, 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.

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.

As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC subsidiaries to OTC.

These intercompany distributions serve as the primary source of funding for dividends paid to our shareholders.

See Note 14 to our consolidated financial statements included in this report on Form 10-K for additional information.

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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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CAPITAL RESOURCES

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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.

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.

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.

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 and/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.

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.

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SHORT-TERM DEBT

OTC and OTP are each party to a credit agreement (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provides for unsecured revolving lines of credit.

On October 31, 2022, the credit agreements were amended to extend the maturity date of each credit facility from September 30, 2026 to October 29, 2027, and to replace the London Interbank Offered Rate (LIBOR) as a benchmark interest rate.

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.

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The agreements generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2026 to 2052.

One OTP debt instrument with a principal balance of $30.0 million matured in August 2022.

Pursuant to a Note Purchase Agreement executed in June 2021, OTP issued its Series 2022A notes in May 2022, for aggregate proceeds of $90.0 million, and used a portion of the proceeds to repay the $30.0 million which matured in August 2022.

Financial Covenants

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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

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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+

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

Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB

Senior Unsecured Debt n/a BBB

Outlook Stable Stable Stable Stable Stable Stable

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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 sheet and recognize in the consolidated statement of income as an expense or income 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 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.

As of December 31, 2023 and 2022, we had regulatory assets of $111.8 million and $119.7 million and regulatory liabilities of $302.0 million and $261.8 million.

If future recovery of amounts recorded as regulatory assets was no longer probable we would be required to recognize expense or other comprehensive loss in the period in which recovery was deemed to no longer be probable.

If future recovery of amounts recorded as regulatory assets was no longer probable we would be required to recognize an expense or loss in the period in which recovery was deemed to no longer be probable.

PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS

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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.

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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, 2022, we set the discount rate used to measure our pension plan obligations at 5.51% and at 5.52% to measure postretirement healthcare obligations, a 248 and 251 basis point increase, respectively, from the estimates used at December 31, 2021.

Our estimates used to determine benefit cost for 2022 included a discount rate of 3.03% for pension benefits and 3.01% for postretirement healthcare costs, a 25 and 26 basis point decrease, respectively, from 2021 estimates.

In addition, we estimated our assumed rate of return on pension assets to be 6.30% for 2022, a 21 basis point decrease from our 2021 estimate.

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.

The following table summarizes the impact on 2023 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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Discount Rate 13 3

For 2023, we expect pension benefit income for our pension plan to be $5.8 million compared to $3.1 million of pension benefit expense in 2022, due to an increase in the discount rate used to determine benefit costs and an increase in the expected return on plan assets, partially offset by an increase in expected future compensation costs.

The estimated discount rate used to determine annual benefit cost accruals increased from 3.03% in 2022 to 5.51% in 2023.

The assumed rate of return on pension plan assets is 7.00% for 2023, compared with the assumption of 6.30% in 2022.

For 2024, we expect pension and other postretirement benefit income to be $8.5 million compared to $9.5 million of income in 2023, due to the impacts of updated actuarial assumptions.

See additional information at footnote 10 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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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 EBITDA, comparable price earnings ratios and, if available, comparable sales transactions for comparative peer companies.

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.

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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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We believe the estimates and assumptions used in our impairment assessments are reasonable and based on the best information available.

However, these estimates and assumptions inherently include a degree of uncertainty.

However, these estimates and assumptions include an inherent degree of uncertainty.

Significant adverse changes in our expectations for any of these estimates could result in an impairment charge in a future period which may materially impact our operating results and financial position.

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