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Item 7. Management’s Discussion and Analysis

2023-02-15 compared with 2022-02-16 · 163 added, 196 removed, 261 unchanged (58% of the section changed)

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You should read the following discussion and analysis of our financial condition and results of operations together with our financial statements and the related notes appearing under Item 8 of this Form 10-K.

Otter Tail Corporation (OTC) and its subsidiaries form a diverse group of businesses with operations classified into three segments:

Otter Tail Corporation and its subsidiaries form a diverse group of businesses with operations classified into three segments:

Electric, Manufacturing and Plastics.

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

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

Our Electric segment is complemented by our Manufacturing and Plastics segment businesses, which we expect to contribute to earnings growth by capitalizing on market expansion opportunities and increasing utilization of existing capacities and planned investments to create additional capacity and increased efficiencies.

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

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

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.

In 2021, all of our businesses were able to effectively manage through the challenges resulting from the COVID-19 pandemic and other marketplace challenges, including supply chain disruptions and rapidly escalating costs for certain raw material components used in our manufacturing processes.

We continue to remain focused on maintaining the health and safety of our employees, customers and communities and ensuring continued electrical reliability and continuous delivery of our products to our customers.

2022 FINANCIAL RESULTS

Our Electric segment produced earnings growth of 8.5% in 2021, driven by returns on our recent rate base investments.

Our Merricourt wind farm and Astoria Station natural gas plant, which collectively constitute a $420 million investment, were completed and placed in service in the fourth quarter of 2020 and the first quarter of 2021, respectively.

Recovery of these investments and associated operating costs through either rate riders or interim rates provided under our Minnesota rate case led to increasing operating revenues and net income.

Our Manufacturing segment produced earnings growth in 2021 of 55.6%, as strong end market demand across most of the markets we serve led to increased sales volumes.

Higher production volumes to meet customer demand led to improved leveraging of fixed manufacturing costs which, along with increased prices, led to improved gross profit levels.

Our Manufacturing segment was impacted in 2021 by steel supply constraints and a significant increase in steel prices, as further discussed below.

In 2022, our diversified business model generated record financial results, producing net income of $284.2 million, or $6.78 per diluted share, an increase of 61% from $176.8 million, or $4.23 per diluted share, in 2021.

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.

In 2022, we paid an annual dividend of $1.65 per share, or $68.8 million, completing our 84th 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 2021 resulted from extraordinary industry supply and demand dynamics.

As further described below, supply shortages 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.

Our ability to manage through these supply disruptions and to deliver products to our customers allowed us to capitalize on these unique industry conditions.

Collectively in 2021, our businesses generated net income of $176.8 million, or $4.23 per diluted share, an increase of 84.4% from $95.9 million, or $2.34 per diluted share, in 2020.

In 2021, we paid an annual dividend of $1.56 per share, or $64.9 million, completing our 83rd consecutive year of dividend payments to our shareholders.

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 estimate of 70% due to the unique market conditions that occurred in our Plastics segment.

We expect our earnings mix to return back to our expected 70% from our Electric segment and 30% from our Manufacturing and Plastics segments over the long term as the conditions within the Plastics' industry subside.

RESOURCE MATERIAL AVAILABILITY AND PRICING

Supply shortages and the cost of steel and resin, two key material inputs to our Manufacturing and Plastics segments, respectively, significantly impacted our operating results in 2021.

Steel supply shortages arose in 2021 following steel mill capacity reductions in 2020 in response to lower demand due to COVID-19.

Production and availability of steel began to improve late in 2021 after steel mill facilities increased production capacities in response to strong market demand for steel products.

The combination of supply shortages and strong end user demand led to significantly increased steel prices.

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.

Limited steel availability also heightened the complexity in managing our business, including effective management of our production and shipping schedules.

Steel costs began to recede late in 2021, but we anticipate steel prices will remain elevated relative to historic norms through at least the first half of 2022.

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.

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 initially arose as a result of production plant shutdowns due to abnormally low temperatures and ice storms in the Gulf Coast region of the United States in the first quarter of 2021 and were exacerbated by hurricane activity in the third quarter of the year.

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

Limited PVC resin resulted in reduced manufacturing of PVC pipe and low pipe inventories across the industry.

The combination of constrained PVC resin supply and the resulting low PVC pipe inventories along with significantly increased PVC resin costs and robust demand for PVC pipe led to rapidly increasing sale prices for PVC pipe, with the increase in sale prices outpacing the increase in PVC resin costs, leading to expanding gross profit margins and a significant increase in earnings in our Plastics segment.

We anticipate these market dynamics will continue through the first quarter of 2022 but begin to subside thereafter.

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.

We continue to monitor the progression of COVID-19 and its impact on our business.

As this pandemic continues, we are following the directives and advice of government leaders and medical professionals and have adopted practices to help curtail the spread of the virus and mitigate its impact on our employees, customers, vendors and other business partners, and communities in which we live and work.

While the impact of COVID-19 and the resulting macroeconomic conditions did not materially impact our operating results in 2021, uncertainty remains regarding the magnitude and duration of the pandemic and the resulting potential future financial effects.

Increased infection rates and any future responses to mitigate the spread of the virus, including any potential vaccination mandates that would apply to our employees, could impact our business and our financial results in future periods.

OSHA has issued an ETS requiring all employers with at least 100 employees to ensure their employees are fully vaccinated or require weekly testing for unvaccinated employees, and President Biden has issued an executive order, which requires employees of certain federal contractors

and covered subcontractors to be vaccinated, with no weekly testing option, unless they have an approved disability or religious exemption.

OSHA has withdrawn its ETS, however, they have emphasized that the ETS will continue to serve as its proposal for a permanent standard.

Currently, the mandate set forth by the President's executive order has been halted as several states are challenging its legality and the matter remains in litigation.

If these mandates are upheld in federal court and become effective, we expect one, or both, of these new regulations will apply to at least some, and possibly all, of our businesses which could require us to mandate COVID-19 vaccination of our workforce or have our unvaccinated employees undergo required weekly COVID-19 testing, or some combination thereof, which could be difficult and costly.

Further, additional vaccine and testing mandates may be announced in jurisdictions in which we operate our business, and there could be potential actions by certain states that are in conflict with the federal mandates, the impacts of which remain uncertain.

Requirements to mandate COVID-19 vaccination of our workforce or requirements of our unvaccinated employees to be tested could result in labor disruptions, employee attrition and difficulty securing future labor needs.

We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and the financial effects on our business.

However, due to the unprecedented and evolving nature of this pandemic, we cannot predict the full extent of the impact COVID-19 will have on our operating results, financial condition and liquidity.

FINANCIAL AND OTHER METRICS

Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level.

Normal weather conditions are defined as the 20-year average of actual historical weather conditions.

This measure is commonly used in calculations relating to the energy consumption required to heat buildings.

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This measure is commonly used in calculations relating to the energy consumption required to cool buildings.

Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (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.

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.

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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, 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.

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.

RESULTS OF OPERATIONS

For a comparison of fiscal year 2020 to 2019, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our report on Form 10-K for the fiscal year ended December 31, 2020, filed with the SEC on February 19, 2021 and incorporated by reference into this report on Form 10-K.

For a comparison of fiscal year 2021 to 2020, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our report on Form 10-K for the fiscal year ended December 31, 2021, filed with the SEC on February 16, 2022.

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.

Intersegment transactions were not material in 2021 or 2020 and amounted to less than $0.1 million of operating revenues and operating expenses for each year.

In addition to the segment results, we provide an overview of our Corporate costs.

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

Each operating segment contributed to the growth in operating revenues.

Electric segment operating revenue increased 7.7% primarily due to increased retail, transmission and wholesale revenues.

Manufacturing segment operating revenues increased 40.8% mainly as a result of higher material input costs, primarily steel, which are passed

through to customers, and increased volumes due to strong end market demand.

Plastics segment operating revenues increased 85.3% primarily due to unique supply and demand dynamics resulting from resin supply constraints coupled with robust demand for PVC pipe leading to rapid and significant increases in sale prices of PVC pipe.

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.

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 10.1% primarily due to increased production fuel and purchased power costs along with incremental operating costs and depreciation expense rising from our recent rate base investments.

Operating expenses in our Manufacturing segment increased 40.2%, driven by increased cost of products sold, which resulted from higher material input costs and increased sales volumes, and increased other operating expenses.

Operating expenses in our Plastics segment increased 47.8% primarily due to higher costs of products sold from higher resin inputs costs.

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.

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

Interest Charges increased $3.3 million in 2021 due to a $40.0 million long-term debt issuance in August 2020, a higher level of short-term debt borrowings outstanding in 2021 and a lower level of capitalized interest due to the completion and placement in service of Astoria Station in the first quarter of 2021.

The increase in our short- and long-term debt borrowings were largely used to finance the rate base investments in our Electric segment.

Nonservice Cost Components of Postretirement Benefits decreased $1.4 million in 2021 mostly due to a decrease in nonservice costs of our postretirement healthcare plan reflecting the effect of plan amendments adopted in 2020 and 2019.

Other Income decreased $3.2 million in 2021 due to a reduction of allowance for equity funds used during construction (AFUDC) on Electric segment investments, mainly for the Minnesota share of Astoria Station.

Astoria Station was placed into service, and the recognition of AFUDC discontinued, in the first quarter of 2021.

Income Tax Expense increased $15.8 million in 2021 primarily due to an increase in income before income taxes, but partially offset by an increase in production tax credits generated from our Merricourt wind farm, which was placed in service in the fourth quarter of 2020.

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.

Our effective tax rate was 20.5% in 2022 and 16.9% in 2021.

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Operating Income $ 113,138 $ 106,964 $ 6,174 5.8 %

Electric kilowatt-hour (kwh) Sales (in thousands)

Electric kwh Sales (in thousands)

Retail kwh Sales 5,592,368 4,789,879 802,489 16.8 %

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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:

2022 vs Normal 2022 vs 2021 2021 vs Normal

Effect on Diluted Earnings Per Share $ 0.11 $ 0.10 $ 0.01

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

• An $8.1 million increase in fuel recovery revenues primarily resulting from increased production fuel and purchase power costs, both of which were impacted by increasing natural gas prices throughout most of 2021.

Partially offsetting this increase are credits provided to retail customers from increased margins recognized on wholesale sales.

• A $6.6 million increase in rider revenues in our North Dakota and South Dakota jurisdictions primarily to recover our investments in and costs to operate Merricourt and Astoria Station.

• A $5.0 million increase in new retail revenues from an interim rate increase in Minnesota, net of estimated refunds.

These increases in retail revenue were partially offset by the impact of reduced demand, exclusive of the impact of weather, from residential customers, and net of the effect of a change in customer usage mix.

In addition, retail revenue in 2020 benefited from the recognition of $2.6 million of Minnesota transmission rider revenue resulting from a favorable judicial decision regarding the state jurisdictional treatment of federally approved transmission projects.

Transmission Services Revenues increased $4.8 million primarily due to increased recovery of higher transmission costs and increased transmission investment along with increased generator interconnection revenues.

Wholesale Revenues increased $13.1 million as a result of a 77.6% increase in wholesale sales volumes and a 107.9% increase in wholesale prices driven by increased fuel costs and market demand for wholesale energy, which serves to drive up spot market prices for electricity.

Production Fuel costs increased $13.0 million as a result of a 16.9% increase in kwhs generated from our fuel-burning plants, largely driven by output from Astoria Station after energy generation commenced in April of 2021.

Purchased Power costs increased $3.7 million due to a 27.9% increase in the cost per kwh purchased in 2021.

This increase was partially offset by a 17.1% decrease in the volume of purchased power in 2021 as our recent generation additions provide additional generation resources to serve customer demand and market conditions led to operating our facilities at higher capacity factors in lieu of purchasing power at higher market prices.

Operating and Maintenance Expense increased $8.8 million mainly due to:

• A $5.2 million increase in operating and maintenance costs for Merricourt and Astoria Station as these facilities were placed in service in the fourth quarter of 2020 and the first quarter of 2021, respectively.

• A $4.0 million increase in Big Stone plant maintenance costs arising from our planned facility outage, which began in the third quarter and was completed in the fourth quarter of 2021.

• Other additional costs including a $2.2 million increase in transmission tariff expenses and increases in information technology services, insurance costs and increased vegetative maintenance costs.

These expense increases were partially offset by, among other items, a $3.0 million reduction in bad debt expense as customer collections have improved from 2020, which were negatively impacted by the economic effects of COVID-19, along with lower operating costs following the closure of Hoot Lake Plant in May 2021.

Depreciation and Amortization expense increased $8.2 million primarily due to Merricourt and Astoria Station being placed in service in the fourth quarter of 2020 and the first quarter of 2021, respectively.

• 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.

Operating and Maintenance Expense increased $21.7 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.

MANUFACTURING SEGMENT RESULTS

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

• At BTD, operating revenues increased $91.3 million.

Parts revenue increased $78.4 million, primarily due to a 31.2% increase in material costs, which are passed through to customers, as steel prices increased significantly from the previous year.

Steel prices increased during the year as steel mill production did not match customer demand as mill capacity recovered from shutdowns in 2020 resulting from the COVID-19 pandemic.

Sales volumes increased 6.8% in 2021 from increased and robust end market demand across most markets served.

Demand in 2020 was impacted by COVID-19 after certain customers implemented temporary plant shutdowns in response to the pandemic.

A $7.3 million increase in scrap revenues, with $5.9 million due to higher scrap metal prices and $1.4 million attributable to higher volumes, also contributed to the increase in operating revenues.

Plastics, revenues increased $6.2 million, primarily due to a 12.5% increase in sales volumes as well as 5.6% increase in sale prices.

Increases in horticultural product sales volumes due to strong customer demand during the year were partially offset by decreases in sales to other end market customers.

Sales volumes in 2020 were impacted by the COVID-19 pandemic, as certain end markets experienced reduced demand.

• 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 $76.6 million as a result of both increased material costs and higher sales volumes.

Increased gross profit margins resulting from a higher leveraging of fixed costs due to increased sales volumes were partially offset by lower productivity and increased labor and freight costs.

The lower level of productivity during the year was primarily the result of increased staffing levels to meet higher business volumes and the time required for new employees to achieve peak productivity.

• 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.

• Cost of products sold at T.O.

Plastics increased $3.2 million primarily due to increased sales volumes.

Gross profit margins increased as a result of a higher leveraging of fixed costs due to increased sales volumes and better pricing spreads.

Other Operating Expenses increased $9.9 million due to increased staffing levels and associated recruitment costs, travel costs, incentive based compensation and other costs resulting from higher business volumes.

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

PLASTICS SEGMENT RESULTS

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Operating Income $ 264,578 $ 132,760 $ 131,818 99.3 %

Operating Revenues increased $175.0 million primarily due to unique supply and demand dynamics during the year.

The average price per pound of PVC pipe sold in 2021 increased 82.1% compared to 2020, which exceeded the 65.5% increase in the cost of PVC resin and other input materials.

The increase in sale prices was largely due to the combination of PVC resin supply constraints, which limited PVC pipe manufacturing output and led to extremely low inventory levels, and strong demand for PVC pipe products.

Resin supply was negatively impacted during the year by production disruptions caused by extreme weather events in the Gulf Coast region of the U.S.

in the first and third quarters of the year.

Pounds of pipe sold in 2021 increased 1.7% compared to the previous year.

Cost of Products Sold increased $80.0 million primarily due to the increase in the cost per pound of PVC pipe sold largely due to higher material input costs.

Other Operating Expenses decreased $0.7 million.

In 2020, our Plastics businesses made a $2.0 million contribution commitment to OTC’s charitable foundation, and no such contribution commitment was made in 2021.

The decrease in foundation contributions was partially offset by an increase in variable costs associated with the increased financial results in 2021.

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 Loss $ 16,342 $ 14,130 $ 2,212 15.7 %

Other Operating Expenses increased $1.1 million primarily due to increased labor and benefit costs as well as a $3.0 million contribution commitment to OTC’s charitable foundation in 2021, compared to a $2.5 million commitment in the previous year.

REGULATORY RATE MATTERS

The following provides a summary of our 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.

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.

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

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(1) 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 annual customer refunds of 50% of any weather-normalized revenue creating earnings in excess of the authorized ROE up to a maximum of 9.50% and 100% refunds revenue creating earnings above 9.50%.

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 a request with the MPUC for an increase in revenue recoverable through base rates in Minnesota.

In its filing, OTP requested a net increase in annual revenue of approximately $14.5 million, or 6.77%, based on an allowed rate of return on rate base of 7.59% and an allowed rate of return on equity of 10.20% on an equity ratio of 52.5% of total capital.

Through this proceeding, OTP has proposed changes to the mechanism of cost recovery, with some costs moving from riders into base rates and fuel, purchased power, and conservation program costs moving out of base rates and into riders.

The filing also included a revenue decoupling mechanism proposal.

Such mechanisms are designed to separate a utility's revenue from changes in energy sales.

The decoupling mechanism uses a tracker balance through which authorized customer margins are subject to a true-up mechanism to maintain or cap a given level of revenues.

On December 3, 2020, the MPUC approved an interim annual rate increase of $6.9 million, or 3.2%, effective January 1, 2021.

This approval was provided after an alternative recovery proposal was submitted by OTP, which, among other changes, requested the extension of depreciable lives of certain wind-related assets and deferred certain cost recovery decisions to the final rate determination.

In the aggregate, this alternative recovery proposal reduced operating costs and delayed recovery of certain other costs by approximately $7.0 million to lessen the interim rate impact on customers.

In a filing submitted to the MPUC on April 30, 2021, OTP lowered its requested net annual revenue increase from its initial request of $14.5 million to $8.2 million, primarily due to a reduction in operating costs from amounts included in its November 2020 filing.

The cost reductions include, among other items, lower depreciation expense on our wind generation assets due to the extension of depreciable lives from 25 to 35 years and a reduction in postretirement benefit costs.

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

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

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

Following the submission of certain compliance filings and a comment period on such filings, we expect final rates will be implemented in mid-2022.

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:

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Mechanism Jurisdiction Status Date (in millions) Date Notes

RRR - 2019 MN Approved 06/21/19 $ 12.5 01/01/20 Includes return on Merricourt construction costs.

TCR - 2018 MN Approved 05/07/20 10.3 01/21/20 See below for additional details.

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 Requested 11/23/21 7.2 07/01/22 Includes recovery of two new transmission projects.

RRR - 2021 MN Requested 12/06/21 2.7 07/01/22 Includes return on Hoot Lake Solar construction costs and costs associated with the acquisition of the Ashtabula III wind farm.

EUIC - 2021 MN Requested 06/07/21 1.3 01/01/22 Includes recovery of new infrastructure costs, including advanced metering, outage management and demand response systems.

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.

GCR - 2020 ND Approved 06/10/20 6.2 07/01/20 Includes return on Astoria Station construction 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.

RRR - 2020 ND Approved 03/18/20 5.8 04/01/20 Includes return on Merricourt construction costs.

TCR - 2020 ND Approved 08/31/20 5.7 01/21/20 Includes recovery of seven new transmission assets.

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.

TCR - 2020 SD Approved 01/29/20 2.3 03/02/20 Annual update to transmission cost recovery rider.

TCR - 2021 SD Requested 10/29/21 2.2 03/01/22 Annual update to transmission cost recovery rider.

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.

PIR - 2020 SD Approved 05/31/20 1.6 09/01/20 Includes return on Merricourt and Astoria Station construction costs.

Minnesota TCR:

On May 1, 2017, the MPUC ordered OTP to include in the TCR rider retail rate base the Minnesota jurisdictional share of OTP's investments in certain transmission assets and all revenues received from other utilities under MISO's tariffed rates as a credit in its TCR revenue requirement calculations.

The order had the effect of diverting interstate wholesale revenues that have been approved by the FERC to offset the FERC-approved expenses, effectively reducing OTP's recovery of FERC-approved expense levels.

On August 18, 2017, OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC transmission projects in the TCR rider.

On June 11, 2018, the Minnesota Court of Appeals reversed the MPUC's order.

On July 11, 2018, the MPUC filed a petition for review of the decision to the Minnesota Supreme Court, which granted review of the appellate court decision.

The Minnesota Supreme Court issued its opinion on April 22, 2020, concluding the MPUC lacked authority to amend an existing TCR rider approved under Minnesota state law to include the costs and revenues associated with these transmission projects and affirming the decision of the Minnesota Court of Appeals.

On October 22, 2020, the MPUC approved OTP's request for a Minnesota TCR rider update with the exclusion of these transmission projects.

In addition, the MPUC approved the inclusion of three new projects previously requested in the Minnesota TCR rider eligibility petition.

Updated rates went into effect in January 2021.

With this decision, one-half of the projected TCR rider tracker balance at December 2020 of $13.4 million will be included in the 2021 TCR rider annual revenue requirement, with the remainder included in the next annual update.

The annual updates provide for recovery of approximately $2.6 million in MISO revenue credits to Minnesota customers through the TCR rider prior to September 30, 2020.

As a result, OTP recognized additional rider revenue of $2.6 million during the third quarter of 2020.

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.

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 capital expenditures related to expansion of existing businesses and development of new projects.

Our liquidity, including our operating cash flows and access to capital markets, can be impacted by macroeconomic factors outside of our control, such as those which may be caused by COVID-19.

Our liquidity, including our operating cash flows and access to capital markets, can 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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Net Cash Provided by Operating Activities $ 389,309 $ 231,243

Net Cash Provided by Operating Activities increased $19.3 million primarily due to a $80.9 million increase in net income, but partially offset by an increase in working capital.

Our working capital increase was primarily the result of a $61.0 million increase in accounts receivable and a $54.3 million increase in inventories, which exceeded the increase in accounts payable and accrued and other liabilities.

The increase in accounts receivable was primarily due to increased sales prices in our Manufacturing and Plastics segments, as well as increased sales volumes in our Plastics segment in the fourth quarter of 2021 compared to the fourth quarter of 2020.

The increase in inventories was largely the result of increased material costs within our Manufacturing and Plastics segments.

The increase in material costs of our Plastics segment more than offset the significant decrease in pounds of pipe inventory, which decreased as a result of lower manufacturing output due to resin supply constraints and strong demand for PVC pipe.

The increase in accounts payable was largely due to the increased material costs in our Manufacturing and Plastics segments and increased inventory levels primarily in our Manufacturing segment.

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.

Unique market dynamics experienced by our Plastics segment businesses in 2022 and 2021 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.

(in thousands) 2022 2021

Net Cash Used in Investing Activities $ 175,071 $ 171,510

Net Cash Used in Investment Activities decreased $204.1 million primarily related to our Astoria Station natural gas plant and Merricourt wind farm being under construction during 2020, with the capital spend being substantially complete for both projects by year-end 2020.

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.

(in thousands) 2022 2021

Net Cash (Used in) Provided by Financing Activities $ (59,359) $ 143,695

Net Cash (Used in) Provided by Financing Activities decreased $203.1 million primarily related to a decrease in construction financing needs within our Electric segment, as capital spending was substantially complete for both Astoria Station and Merricourt by year-end 2020.

In 2021 our financing activities included the issuance of $140.0 million in long-term debt at OTP, which was used to repay long-term debt that matured in December 2021, and $10.2 million of net short-term borrowings on our lines of credit, which were primarily used to fund construction expenditures and support operating activities.

In 2021, we paid $64.9 million in dividends to common shareholders.

In 2020, $75.0 million of long-term debt was issued at OTP, we had $75.0 million of net short-term borrowings on our lines of credit, and we also raised $52.4 million from the issuance of common stock to fund capital expenditures at OTP.

In 2020, we paid $60.3 million in dividends to common shareholders.

Net Cash Used in Financing Activities $ 96,779 $ 59,359

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.

CAPITAL REQUIREMENTS

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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.

The 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 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.

The following provides a summary of capital expenditures for the years ended December 31, 2022 and 2021 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2023 through 2027:

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Electric Segment:

Renewables and Natural Gas Generation $ 30 $ 80 $ 92 $ 92 $ 160 a $ 454

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

Technology and Infrastructure 33 30 6 5 1 75

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Transmission (includes replacements) 34 36 46 87 78 281

Other 30 29 32 36 23 a 150

Other 26 25 30 25 22 128

Total Electric Segment $ 140 $ 148 $ 214 $ 247 $ 208 $ 234 $ 154 $ 1,057

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Total Contractual Cash Obligations $ 2,166 $ 92 $ 146 $ 262 $ 1,666

Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company under the lignite sales agreement 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, 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.

Off-Balance Sheet Arrangements

As of December 31, 2021, we have outstanding letters of credit totaling $15.9 million, a portion of which reduces our borrowing capacity under our lines of credit.

No outstanding letters of credit are reflected in outstanding short-term debt on our consolidated balance sheets.

We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes.

We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

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.

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, 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 our subsidiaries.

See Note 14 to our consolidated

financial statements included in this report on Form 10-K for additional information.

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.

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

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

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CAPITAL RESOURCES

Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

Financial flexibility is provided by operating cash flows, borrowing capacity under our lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

Debt financing will be required in the five-year period from 2023 through 2027 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

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

As of December 31, 2021, 1,384,820 shares remain available for purchase or issuance under the Plan.

As of December 31, 2022, 1,250,993 shares remained available for purchase or issuance under the Plan.

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.

The agreements generally bear interest at the London Interbank Offered Rate (LIBOR) plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the issuer.

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 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.

The weighted-average interest rate on all outstanding borrowings as of December 31, 2022 and 2021 was 5.61% and 1.42%.

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Interest Rate at Year-End 5.9 % 5.6 %

Maturity Date September 30, 2026 September 30, 2026

1 Each facility includes an accordion featuring allowing the borrower to increase the borrowing limit if certain terms and conditions are met.

Expiration Date October 29, 2027 October 29, 2027

1 Each facility includes an accordion feature allowing the borrower to increase the borrowing limit if certain terms and conditions are met.

LONG-TERM DEBT

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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 matures in August 2022.

Pursuant to a Note Purchase Agreement executed in June 2021, OTP intends to issue its Series 2022A notes in May 2022, for aggregate proceeds of $90.0 million, subject to the satisfaction of certain customary conditions to closing, and use a portion of the proceeds to repay the $30.0 million which is maturing in August 2022.

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

December 31, 2021, OTP's Interest-Bearing Debt to Total Capitalization was 0.48 to 1.00, its Interest and Dividend Coverage Ratio was 3.24 to 1.00 and it had no Priority Indebtedness outstanding.

As of December 31, 2022, OTP's Interest-Bearing Debt to Total Capitalization was 0.45 to 1.00, its Interest and Dividend Coverage Ratio was 3.66 to 1.00 and it had no Priority Indebtedness outstanding.

None of our debt agreements include any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

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

Outlook Stable Stable Negative Stable Stable Stable

CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES

Preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

While we believe the estimates and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates.

Outlook Stable Stable Stable Stable Stable Stable

CRITICAL ACCOUNTING ESTIMATES

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

While we believe the estimates, assumptions, and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates.

Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of our Board of Directors.

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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.

As of December 31, 2022 and 2021, we had regulatory assets of $119.7 million and $152.9 million and regulatory liabilities of $261.8 million and $259.3 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.

PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS

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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.

Also, a reduction 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 below assumed rates of return or an increase in the anticipated life expectancy of plan participants could result in significant increases 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.

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 and volatility rates with forward looking estimates based on existing and forecasted future market conditions.

We estimate the assumed long-term rate of return on plan assets based on asset category studies using historical market returns achieved by our asset portfolio allocation over long-term periods, as well as long-term projected return levels.

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

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

At December 31, 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.

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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.

The following table summarizes the impact on 2021 pension and postretirement costs for a 0.25 increase or decrease, holding all other variables constant, on certain key assumptions:

The following table summarizes the impact on 2022 pension and postretirement costs for a 25 basis point increase or decrease, holding all other variables constant, on certain key assumptions:

(in thousands) +0.25 -0.25

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Discount Rate (310) 326

For 2022, we expect pension benefit cost for our pension plan to be $3.0 million compared to $7.7 million in 2021, as the amortization of actuarial losses is reduced in 2022 following actuarial gains recognized as of December 31, 2021.

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 6.30% for 2022 compared with 6.51% for 2021.

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

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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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