What changed in this filing

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Item 1. Business

2024-02-14 compared with 2023-02-15 · 127 added, 132 removed, 280 unchanged (48% of the section changed)

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Electric includes the generation, purchase, transmission, distribution and sale of electric energy in western Minnesota, eastern North Dakota and northeastern South Dakota.

OTP, our largest operating subsidiary and primary business since 1907, serves more than 133,000 customers in more than 400 communities across a predominantly rural and agricultural service territory.

Manufacturing consists of businesses in the following manufacturing activities:

Otter Tail Power (OTP), our largest operating subsidiary and primary business since 1907, serves more than 133,000 customers in more than 400 communities across a predominantly rural and agricultural service territory.

Manufacturing consists of businesses engaged in the following manufacturing activities:

contract machining;

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We maintain a moderate risk profile by investing in rate base growth opportunities in our Electric segment and organic growth opportunities in our Manufacturing and Plastics segments (collectively, our manufacturing platform).

This strategy and risk profile are designed to provide a more predictable earnings stream, maintain our credit quality and preserve our ability to fund our dividend payments.

This strategy and risk profile are designed to provide a more predictable and growing earnings stream, support quality credit ratings, and provide for dividend payments.

Our long-term focus remains on executing our strategy to grow our business and achieving operational, commercial and talent excellence to strengthen our position in the markets we serve.

We remain confident in our ability to achieve a compounded annual growth rate in earnings per share in the range of five to seven percent using 2024 as the base year.

We currently expect to see elevated earnings per share from our manufacturing platform into 2023 with our earnings mix expected to move to approximately 65% from our Electric segment and 35% from our manufacturing platform beginning in 2024.

We expect our earnings growth beyond 2024 to be driven by rate base investments in our Electric segment and from existing capacities and planned investments within our Manufacturing and Plastics segments.

Over the past two years, we delivered earnings growth well in excess of our five to seven percent target due to unique industry conditions within the PVC pipe industry which led to extraordinary revenue, earnings and cash flow growth in our Plastics Segment.

Our long-term financial objectives include achieving a compounded annual growth rate in earnings per share in the range of 5 - 7%, with a long-term earnings mix of approximately 65% from our Electric segment and 35% from our manufacturing platform.

We also are targeting an annual increase in our dividend to be in the range of 5 - 7%.

We expect our earnings growth and cash flow generation to be driven by rate base investments in our Electric segment and from existing capacities and planned investments within our Manufacturing and Plastics segments.

Over the past three years, we delivered earnings growth well in excess of our 5 - 7% target due to unique industry conditions within the PVC pipe industry, which led to extraordinary revenue, earnings and cash flow growth in our Plastics Segment.

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

As they do, we expect earnings and cash flow generation within our Plastics segment to moderate from current levels.

Once these industry conditions have normalized, we expect to achieve our long-term financial objectives as outlined above.

We will continue to review our business portfolio to identify additional opportunities to improve our risk profile, enhance our credit metrics and generate additional sources of cash to support the organic growth opportunities in our Electric, Manufacturing, and Plastics segments.

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We are a committed long-term owner and do not acquire companies in pursuit of short-term gains.

However, we will divest businesses which no longer fit into our strategy and risk profile over the long term.

However, we will divest of businesses which no longer fit into our strategy and risk profile over the long term.

We maintain a set of criteria used in evaluating the strategic fit of our operating businesses.

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• Have a strong management team committed to operational and commercial excellence.

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Our actual mix of earnings for the years ended December 31, 2023, 2022 and 2021 was as follows:

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We strive to provide an environment of opportunity and accountability where people are valued and empowered to do their best work.

We are focused on the health and safety of our employees and creating a culture of inclusion, excellence and learning.

Our human capital management efforts include monitoring various metrics and objectives associated with i) employee safety, ii) workforce stability, iii) management and workforce demographics, including gender, racial and ethnic diversity, iv) leadership development and succession planning and v) productivity.

We have established the following programs in furtherance of these efforts:

We are focused on the health and safety of our employees and creating a culture of inclusion, excellence and learning, and our executive annual incentive plan reflects those commitments.

We monitor various metrics and objectives associated with i) employee safety, ii) workforce stability, iii) management and workforce demographics, including gender, racial and ethnic diversity, iv) leadership development and succession planning and v) productivity.

We have established the following in furtherance of these efforts:

Safety - Safety is one of our core values.

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Safety is also a metric used and evaluated in determining annual incentive compensation.

We continually monitor the Occupational Safety and Health Administration (OSHA) Total Recordable Incident Rate (number of work-related injuries per 100 employees for a one-year period) and Lost Time Incident Rate (number of employees who lost time due to work-related injuries per 100 employees for a one-year period).

We continually monitor the Occupational Safety and Health Administration Total Recordable Incident Rate (number of work-related injuries per 100 employees for a one-year period) and Lost Time Incident Rate (number of employees who lost time due to work-related injuries per 100 employees for a one-year period).

New cases are reported and evaluated for corrective action during monthly safety meetings attended by safety professionals at all locations.

Our 2022 Total Recordable Incident Rate was 2.08, compared to 1.86 in 2021 and our Lost Time Incident Rate was 0.49, compared to 0.57 in 2021.

In both 2022 and 2021 these rates were favorable when compared to the rates of our peers.

Employee and Leadership Development, Succession Planning and Training Programs - We invest in leadership development for various levels of employees, management and leaders throughout the Company to build enterprise-wide understanding of our culture, strategy and processes.

Our 2023 Total Recordable Incident Rate was 1.70, compared to 2.08 in 2022 and our Lost Time Incident Rate was 0.53 in 2023, compared to 0.49 in 2022.

Employee and Leadership Development, Succession Planning and Training Programs - We invest in training and professional development for various levels of employees, management and leaders throughout the Company to ensure all have the necessary training and skills to perform their work well, and to build enterprise-wide understanding of our culture, strategy and processes.

Annual succession planning, individual development planning, mentoring, and supervisory and leadership development programs all play a role in ensuring a capable leadership team now and in the future.

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We use the feedback to help shape the employee programs of our organization.

Human Rights - We are committed to the protection of our employee’s freedom of expression and freedom of organization and assembly.

Diversity, Equity, and Inclusion - We expect, and are committed to, diversity, equity and inclusion as part of who we are, what we value, and how we achieve individual, business and community success.

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We have implemented education initiatives for all employees, aimed at inclusive leadership and a respectful workplace, focused on identities and culture, unconscious bias, the power of diverse teams and culturally sensitive conversations.

We have implemented initiatives to improve upon our demographic profile, including revised hiring processes and a commitment to diverse interview slates.

We have implemented initiatives to improve upon our demographic profile, including revised hiring processes and a commitment to diverse slates of interview candidates.

Code of Business Ethics - We require employees to complete training on several topics associated with our code of business ethics to reinforce our commitment to compliance with laws, regulations and values that guide who we are and how we do business.

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As of December 31, 2023, we employed 2,655 full-time employees as shown in the table below:

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The demographics of our workforce, including our Board of Directors, as of December 31, 2023 was as follows:

% Female % Racially and Ethnically Diverse % Female % Racially and Ethnically Diverse

% Female % Racially and Ethnically Diverse

Board of Directors

36 % 9 % 20 % 10 %

CEO Direct Reports 33 % — %

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Non-Management Employees 15 % 15 %

(1) 2022 includes the new directors appointed to our Board effective January 1, 2023.

ELECTRIC Contribution to Operating Revenues:

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Our service territory is predominantly rural and agricultural and includes over 400 communities, most of which have populations of less than 10,000.

While our customer base includes relatively few large customers, sales to commercial and industrial customers are significant, with one industrial customer accounting for 11% and 10%, respectively, of segment operating revenues for the years ended December 31, 2022 and 2021.

While our customer base includes relatively few large customers, sales to commercial and industrial customers are significant, with two customers accounting for 21% of segment operating revenues for the year ended December 31, 2023 and 16% for the year ended December 31, 2022.

The following charts summarize our retail electric revenues by state and by customer segment for the years ended December 31, 2023 and 2022:

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In addition to retail revenue, our Electric segment also generates operating revenues from the transmission of electricity for others over the transmission assets we wholly or jointly own with other transmission service providers, and from the sale of electricity we generate and sell into the wholesale electricity market.

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Wholesale electricity markets are competitive under the Federal Energy Regulatory Commission (FERC) open access transmission tariffs, which require utilities to provide nondiscriminatory access to all wholesale users.

In addition, the FERC has established a competitive process for the construction and operation of certain new electric transmission facilities whereby electric transmission providers, including the Midcontinent Independent System Operator, Inc.

(MISO), of which OTP is a member, are required to remove from their tariffs a federal right of first refusal to construct transmission facilities selected in a regional transmission plan for purposes of cost allocation.

The FERC is contemplating potential reforms for electric regional transmission planning, cost allocation and generator interconnection processes.

While the ultimate regulatory outcome is uncertain at this time, changes to the regulatory framework could impact future transmission investments.

In addition, the FERC has established a competitive process for the construction and operation of certain new electric transmission facilities under federal regulation.

Certain states have laws which provide the incumbent transmission owner the right of first refusal to construct and own new transmission facilities.

OTP has franchises to operate as an electric utility in substantially all of the incorporated municipalities it serves.

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Our mix of owned generation and wholesale market energy purchases to meet customer demand are impacted by wholesale energy prices and the relative cost of each energy source.

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As of December 31, 2023, OTP’s wholly or jointly owned plants and facilities, as well as in place power purchase agreements, and their dependable kilowatt (kW) capacity were:

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Owned Wind Facilities (rated at nameplate)

Merricourt Wind Energy Center 150,000

Luverne Wind Farm 49,500

Ashtabula Wind Center 48,000

Langdon Wind Center 40,500

Ashtabula III

Total Owned Wind Facilities 350,400

Hoot Lake Solar

Hydroelectric Facilities 2,600

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Purchased Wind Power (rated at nameplate and greater than 2,000 kW)

Ashtabula Wind III (3)

Edgeley 21,000

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(2) Reflects OTP's 35.0% ownership percentage of jointly owned facility.

(3) OTP acquired the assets of the Ashtabula III wind farm on January 3, 2023.

The following charts summarize the percentage of our generating capacity by source, including owned and jointly owned facilities and through power purchase arrangements, as of December 31, 2023 and 2022:

Under MISO requirements, OTP is required to provide sufficient capacity through wholly- or jointly-owned generating capacity or power purchase agreements to meet its monthly weather-normalized forecast demand, plus a reserve obligation.

On August 31, 2022, FERC issued an order to approve MISO's proposal to revise its resource adequacy requirement, including the adoption of a seasonal resource adequacy construct rather than a single requirement based on a summer peak.

MISO proposed the seasonal adequacy construct to address significant increases in emergency declarations that occur throughout the year, driven by factors including declining excess reserve margin, generation retirements, reliance on intermittent resources and outages resulting from extreme weather events.

These new provisions will be implemented in the 2023/2024 planning year.

Under the new seasonal resource adequacy construct, the seasonal reserve margin requirements deviate significantly from MISO’s 2022/2023 annual planning reserve margin requirements.

For planning year 2022/2023, the last year under the

annual construct, our required planning reserve margin was 8.7%.

For planning year 2023/2024, under the new seasonal construct, our planning reserve margin requirements range between 7.4% and 25.5%, depending on the season.

Under Midcontinent Independent System Operator (MISO) requirements, OTP is required to provide sufficient capacity through wholly or jointly owned generating capacity or power purchase agreements to meet its monthly weather-normalized forecast demand, plus a reserve obligation.

MISO operates under a seasonal resource adequacy construct in which generation resources are accredited and planning reserve margin requirements are implemented on a seasonal basis.

Current planning reserve margin requirements range between 7.4% and 25.5%, depending on the season.

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The following charts summarize the percentage of retail kwh sold by source during the years ended December 31, 2023 and 2022:

Capacity Retirements and Additions

Hoot Lake Plant , our 142-megawatt coal-fired power plant in Fergus Falls, Minnesota was retired in mid-2021.

As part of our investment plan to meet our future energy needs, the following significant projects are at various stages of planning and construction or have been recently completed:

Merricourt Wind Energy Center (Merricourt) is a 150-megawatt wind farm located in southeastern North Dakota.

The facility was placed into commercial operation in December 2020, with a total cost of approximately $260 million.

Astoria Station Natural Gas Plant (Astoria) is a 245-megawatt simple cycle natural gas combustion turbine generation facility near Astoria, South Dakota.

The facility was placed into commercial operation in February 2021, with a total cost of approximately $160 million.

Hoot Lake Solar is a 49-megawatt solar farm under construction on and around our Hoot Lake Plant property in Fergus Falls, Minnesota, with an anticipated cost of approximately $60 million.

We anticipate the facility will be in commercial operation by the end of 2023.

Ashtabula III Wind Farm is a 62-megawatt wind farm located in eastern North Dakota.

Capacity Additions

As part of our investment plan to meet our future energy needs, the following projects have been recently undertaken, completed, or acquired:

Ashtabula III Wind Farm is a 62-megawatt (MW) wind farm located in eastern North Dakota.

The facility was purchased for approximately $50 million in January 2023.

Prior to the purchase of the wind farm assets, we were purchasing the wind-generated electricity from the wind farm pursuant to a power purchase agreement.

Hoot Lake Solar is a 49-MW solar farm constructed on and around our Hoot Lake Plant property in Fergus Falls, Minnesota, with a total cost of approximately $60 million.

The facility was placed into commercial operation in August 2023.

Wind Energy Facility Upgrades consisting of the replacement and upgrade of hubs, gearboxes, blades, generators and other components of our Ashtabula, Ashtabula III, Langdon and Luverne wind facilities at a total cost of approximately $230 million.

Once complete, we expect the increased energy production from these facilities will be equivalent to an additional 40-MW of generation.

We anticipate the repowering of our Langdon facility will be completed in 2024 and the remaining facilities to be completed in 2025.

Once complete, the energy production from each of these facilities is eligible for production tax credits (PTCs) over a ten-year period.

We expect these projects will lower customer costs through a combination of fuel savings and the tax credit benefits afforded to our customers.

ENERGY TRANSITION

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We have developed the following goals in furtherance of our efforts to support the energy transition:

Own or purchase energy generation that’s more than 50% renewable by 2025 .

Own or purchase energy generation that is 55% renewable by 2030 .

Reduce carbon emissions from owned generation resources 50% by 2030 from 2005 levels.

Reduce carbon emissions from owned generation resources 97% by 2050 from 2005 levels.

To date, we have undertaken numerous initiatives to reduce our carbon footprint and mitigate greenhouse gas (GHG) emissions in the process of generating electricity for our customers.

Our initiatives include increasing the efficiency of our plants, retiring Hoot Lake Plant, adding renewable energy to our resource mix and sponsoring energy conservation programs.

From 2005 through 2022, we have reduced our carbon dioxide (CO 2 ) emissions approximately 43% and increased the amount of renewable generation resources we own or purchase through power purchase agreements by approximately 370-megawatts.

Our future resource plans to deliver affordable, reliable, and increasingly clean energy to our customers include the addition of 49-megawatts of solar energy from Hoot Lake Solar in 2023 and repowering various wind farm assets to increase their efficiency and output.

The following chart depicts our energy resource mix, which is the electricity we use to serve our customers, in 2005 and 2022 and the projected mix in 2030 and 2050.

We have based these goals on our December 2023 supplemental Integrated Resource Plan (IRP) filing in Minnesota.

While modified from our previously published goals, they reflect current market conditions, including the impact of higher natural gas prices, and higher than originally forecasted dispatch levels of our co-owned, coal-fired power plants.

We have undertaken numerous initiatives to reduce our carbon footprint and mitigate greenhouse gas (GHG) emissions in the process of generating electricity for our customers.

Our recent initiatives include retiring the 140-MW coal-fired Hoot Lake Plant, adding the 150-MW Merricourt Wind Energy Center and the 49-MW Hoot Lake Solar facility to our resource mix and sponsoring energy conservation programs.

We anticipate our Minnesota retail sales will be 80% carbon free by 2030, in compliance with Minnesota clean energy requirements.

From 2005 through 2023, we have reduced our carbon dioxide (CO 2 ) emissions approximately 39% and increased the amount of renewable generation resources we own or purchase through power purchase agreements by approximately 420-MW.

We currently own or contract energy generation that is 37% renewable.

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The following chart depicts our energy resource mix, which is the electricity we used to serve our customers in 2005 and 2023, and the projected mix in 2030 and 2050.

The amounts include energy generated from owned resources, procured through power purchase agreements and energy purchased in the wholesale market:

Inflation Reduction Act

On August 16, 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law.

The IRA includes funding for climate and clean energy investments and other provisions affecting corporate taxpayers.

The climate and clean energy provisions of the IRA include, among other items, i) the extension of the traditional production tax credits (PTC) and investment tax credits (ITC) for renewable technologies (including wind and solar) if construction is begun before 2025, along with elimination of the existing phase-down of the PTC and ITC, and transitions to a new technology neutral credit for property placed in service after 2024, ii) a new PTC for sale of domestically produced electricity with a GHG emission rate of not greater than zero produced at a qualifying facility placed in service after 2024, iii) a new ITC for investment in qualifying zero-emission electricity generation facilities or energy storage technology placed in service after 2024, and iv) alternative ways to monetize renewable tax credits by allowing certain entities to sell tax credits to third parties.

The tax incentives provided under the IRA are intended to incentivize the transition to a cleaner energy economy and to reduce GHG emissions from the electric utility industry.

These financial incentives could impact the planning of our future generation resources and our long-term capital spending plan.

See the Integrated Resource Plan (IRP) section below for additional details on how the passage of the IRA has impacted our recently filed IRP.

RESOURCE MATERIALS

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We source coal for our coal-fired power plants through requirements contracts which do not include minimum purchase requirements but do require all coal necessary for the operation of the respective plant to be purchased from the counterparty.

Our coal supply contracts for our Big Stone Plant and Coyote Station have expiration dates in 2024 and 2040.

Our coal supply contracts for our Big Stone Plant and Coyote Station have expiration dates in 2024 and 2040, respectively.

The supply agreement between the Coyote Station owners, including OTP, and the coal supplier includes provisions requiring the Coyote Station owners to purchase the membership interests and pay off or assume loan and lease obligations of the coal supplier, as well as complete mine closing and post-mining reclamation, in the event of certain early termination events and at the expiration of the coal supply agreement in 2040.

See below and Note 1 to our consolidated financial statements included in this report on Form 10-K for additional information.

Coal is transported to our non-mine-mouth facility, Big Stone Plant, by rail and is provided under a common carrier rate which includes a mileage-based fuel surcharge.

Coal is transported to Big Stone Plant by rail and is provided under a common carrier rate which includes a mileage-based fuel surcharge.

We purchase natural gas for use at our combustion turbine facilities based on anticipated short-term resource needs.

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In addition, we earn revenue from the transmission of electricity over our wholly or jointly owned transmission assets for others under approved rate tariffs.

As of December 31, 2022, we were the sole or joint owner of nearly 15,000 miles of transmission and distribution lines.

As of December 31, 2023, we were the sole or joint owner of approximately 14,000 miles of transmission and distribution lines.

Midcontinent Independent System Operator

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MISO seeks to optimize the efficiency of the interconnected system, provide solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions.

In 2022, MISO approved several projects within the first tranche of its long-range transmission plan, which includes two new 345 kV transmission projects and a project to upgrade an existing transmission line.

OTP will have a varying level of ownership interest in these projects, which will be completed over several years, and our total capital investment in these projects is anticipated to be approximately $390 million.

Transmission Additions

In 2022, MISO approved several projects within the first tranche of its long-range transmission plan, which includes two new 345 kV transmission projects.

OTP will have a varying level of ownership interest in these projects, which will be completed over several years and are at various stages of planning and development:

Jamestown-Ellendale includes the construction of a new 345 kV transmission line in southeastern North Dakota spanning approximately 95 miles from Jamestown, North Dakota to Ellendale, North Dakota.

This project is in the initial stages of planning and development.

This jointly owned project is expected to be completed in 2028 and our capital investment is estimated to be approximately $230 million.

Big Stone South-Alexandria-Big Oaks includes the construction of a new 345 kV transmission line in eastern South Dakota and western Minnesota and the addition of a second circuit to an existing 345 kV line in central Minnesota.

The new transmission line will span approximately 100 miles between Big Stone, South Dakota and Alexandria, Minnesota.

A second circuit will be added to the existing transmission line spanning from Alexandria, Minnesota to Big Oaks, Minnesota.

This project is in the initial stages of planning and development.

This jointly owned project is expected to be completed in 2031 and our capital investment is estimated to be approximately $190 million.

Electricity demand is affected by seasonal weather differences, with peak demand occurring in the summer and winter months.

As a result, our Electric segment operating results regularly fluctuate on a seasonal basis.

In addition, fluctuations in electricity demand within the same season but between years can impact our operating results.

In addition, fluctuations in electricity demand within the same season but

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between years can impact our operating results.

We monitor the level of heating and cooling degree days in a period to assess the impact of weather-related effects on our operating results between periods.

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>50,000 kW for non-wind generating facilities) and high voltage transmission lines (>115 kV).

Review and approval of fifteen-year Integrated Resource Plan.

Review of fifteen-year Integrated Resource Plan.

South Dakota Public Utilities Commission

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Compliance with North American Electric Reliability Corporation (NERC) reliability standards, including standards on cybersecurity and protection of critical infrastructure.

In addition to base rates, which are established through periodic rate case proceedings within each state jurisdiction, there are other mechanisms for recovery of plant investments, including a return on investment and operating expenses, between rate cases.

In addition to base rates, which are established through periodic rate case proceedings within each state jurisdiction, there are other mechanisms for recovery of our capital investments and operating expenses between rate cases.

The following table summarizes these recovery mechanisms:

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Fuel Clause Adjustment (FCA) MN, ND, SD Provides for periodic billing adjustments for changes in prudently incurred costs of fuel and purchased power.

In North and South Dakota, fuel and purchased power costs are generally adjusted on a monthly basis with over or under collections from the previous month applied to the next monthly billing.

In Minnesota, fuel and purchased power costs are estimated on an annual basis and the accumulated difference between actual and estimated cost per kwh are refunded or recovered, subject to regulatory approval, in subsequent periods.

In North and South Dakota, fuel and purchased power costs are generally adjusted on a monthly basis.

In Minnesota, fuel and purchased power costs are estimated on an annual basis and the accumulated difference between actual and estimated cost per kwh is refunded or recovered, subject to regulatory approval, in subsequent periods.

Transmission Cost Recovery Rider (TCR) MN, ND, SD Provides for the recovery of costs outside of a general rate case for investments in new or modified electric transmission assets and certain MISO transmission service and related costs.

Environmental Cost Recovery Rider (ECR) MN, ND, SD Provides for the recovery of costs outside of a general rate case for investments in certain environmental improvement projects.

Renewable Resource Rider (RRR) MN, ND Provides for the recovery of costs outside of a general rate case for investments in certain new renewable energy projects.

Conservation Improvement Program (CIP) MN Under Minnesota law, OTP is required to save 1.75% of its gross retail energy revenues through the energy conservation and optimization program.

Recovery of these costs outside of a general rate case occurs through the CIP rider.

Energy Conservation and Optimization Rider (ECO)

MN Under Minnesota law, OTP is required to save 1.75% of its gross retail energy revenues through the energy conservation and optimization program.

Recovery of these costs outside of a general rate case occurs through the ECO rider.

Electric Utility Infrastructure Costs Rider (EUIC) MN Provides for the recovery of costs for investments made to replace or modify existing infrastructure if the replacement or modification conserves energy or uses energy more efficiently.

Advanced Meter and Distribution Technology Cost Recovery Rider (AMDT) ND Provides for the recovery of costs for advanced metering infrastructure, outage management systems and demand response projects.

Metering and Distribution Technology Cost Recovery Rider (MDT)

ND Provides for the recovery of costs for advanced metering infrastructure, outage management systems and demand response projects.

Generation Cost Recovery Rider (GCR) ND Provides for the recovery of costs outside of a general rate case for investments in new generation facilities.

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Phase-In Rider (PIR) SD Provides for the recovery of costs outside of a general rate case for investments in new generation facilities and advanced grid infrastructure.

Integrated Resource Plan

Under Minnesota law, utilities are required to submit for approval by the MPUC a 15-year advance IRP.

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Resource Planning

Under Minnesota law, utilities are required to submit for approval by the Minnesota Public Utilities Commission (MPUC) a 15-year advance Integrated Resource Plan (IRP).

An IRP is a set of resource options a utility could use to meet the service needs of its customers over the forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to which each resource option would be used to meet those service needs.

The MPUC’s findings of fact and conclusions regarding IRPs are considered to be prima facie evidence, subject to rebuttal, in future rate reviews and other proceedings.

Typically, IRPs are submitted every two years.

In 2021, the North Dakota Legislative Assembly enacted a provision requiring investor-owned electric utilities to submit an IRP to the NDPSC and granted the NDPSC the authority to adopt rules and regulations for the preparation and submission of IRPs.

In 2021, the North Dakota Legislative Assembly enacted a provision requiring investor-owned electric utilities to submit an IRP to the North Dakota Public Service Commission (NDPSC) and granted the NDPSC the authority to adopt rules and regulations for the preparation and submission of IRPs.

The NDPSC's rules and regulations were finalized and became effective on January 1, 2023.

Under the finalized regulation, utilities are required to submit, for approval by the NDPSC, a 15-year advance IRP every three years.

On September 1, 2021, OTP filed its 2022 IRP concurrently with regulators in Minnesota, North Dakota and South Dakota.

The 2022 IRP included OTP’s preferred plan for meeting customers’ anticipated capacity and energy needs while maintaining system reliability and affordable electric service rates, based on the information available at that time.

The preferred plan as outlined in the 2022 IRP included the addition of dual fuel capabilities at our Astoria natural gas plant, the addition of 150-megawatts of solar generation, the addition of 100-megawatts of wind generation, and the commencement of the process of withdrawing from our 35 percent ownership interest in Coyote Station, a jointly-owned, coal-fired generation plant, by December 31, 2028.

Subject to regulatory approval, the preferred plan proposed to create a regulatory asset as a vehicle to recover costs related to a future withdrawal from Coyote Station, including the net book value of the plant on the withdrawal date, anticipated decommissioning costs and any required costs incurred as a result of an early termination of the existing lignite sales agreement (LSA), under which Coyote Station acquires all of its lignite coal from a nearby mine.

As part of the filing, OTP developed an estimate of the reasonably foreseeable costs of withdrawing from Coyote Station at the end of 2028 of $68.5 million.

These costs may differ from actual results due to the uncertainty and timing of future events associated with the terms and conditions of a withdrawal.

On October 14, 2022, OTP submitted a supplemental filing to update its 2022 IRP, requesting the procedural schedule in Minnesota be amended to allow additional time to update our resource modeling given significant changes in the energy industry since the original 2022 IRP filing, while maintaining the original procedural schedule as it relates to adding dual fuel capability at Astoria.

Our original filing proposed fuel oil as the secondary on-site fuel at Astoria and our supplemental filing reflects revised cost estimates and proposes liquified natural gas as the most cost-effective secondary fuel source.

The primary changes and events which led to OTP's request include FERC’s approval of MISO’s new seasonal

resource adequacy construct, MISO’s proposal to significantly increase winter and spring planning reserve margins, and enactment of the IRA.

A notice of the request submitted to the MPUC was also provided to the NDPSC and SDPUC.

On November 1, 2022, the MPUC approved OTP's requested changes to the procedural schedule for the 2022 IRP.

OTP plans to file an updated resource plan in March 2023, pursuant to the amended schedule.

In conjunction with the updated resource plan, OTP's preferred plan could change based on the results of updated resource modeling incorporating the factors listed above, as well as other changes.

A change to the 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.

Under the finalized regulation, utilities are required to submit a 15-year advance IRP every three years.

Capital Structure Petition

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Once approved, OTP may issue securities without further petition or approval, provided the issuance is consistent with the purposes and amounts set forth in the approved petition.

OTP’s current capital structure approved by the MPUC on November 8, 2022, allows for an equity-to-total-capitalization ratio between 47.5% and 58.0%, with total capitalization not to exceed $1.8 billion.

OTP’s current capital structure approved by the MPUC on August 29, 2023, allows for an equity-to-total-capitalization ratio between 48.3% and 59.1%, with total capitalization not to exceed $1.958 billion.

Renewable Energy Standard

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For a public utility with between 50,000 and 200,000 retail electric customers, such as OTP, at least 10% of the 1.5% requirement must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less.

OTP plans to purchase Solar Renewable Energy Credits to meet its obligations until its Hoot Lake Solar and other solar projects are complete and operational.

Under certain circumstances, and after consideration of customers' utility costs and reliability issues, the MPUC may modify or delay implementation of the standards.

We are evaluating potential options for maintaining compliance and meeting the solar energy standard beyond 2022.

We met the current solar requirement with a combination of owned solar generation and solar renewable energy certificate (REC) purchases.

We plan to comply with the requirements of this standard in the future through a combination of our existing and projected renewable generation fleet and the purchase of RECs.

Minnesota Clean Energy Bill

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Carbon-free resources include wind, solar, hydropower, and nuclear generation.

To provide flexibility, the law allows electric utilities to use renewable energy credits (RECs) to offset carbon emissions and for the MPUC to consider whether a regulated utility's requirement to meet established standards should be delayed due to affordability or reliability impacts.

OTP is in the process of reviewing its plan for compliance with the newly enacted law.

To provide flexibility, the law allows electric utilities to use RECs to offset carbon emissions and for the MPUC to consider whether a regulated utility's requirement to meet established standards should be delayed due to affordability or reliability impacts.

We expect to meet these requirements based on our existing and projected renewable generation fleet and the purchase of RECs.

ENVIRONMENTAL REGULATION

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As it relates to our jointly owned facilities, we may determine it is necessary to transfer, sell or otherwise divest of our ownership, or the ownership group may determine the early closure or repurposing of a facility is necessary.

Financial Impacts

For the five-year period ended December 31, 2023, OTP invested approximately $6.6 million in environmental control facilities, including $1.4 million in 2023.

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The timing and amount of our expenditures may change as the regulatory environment changes.

Among current regulatory requirements, the federal Regional Haze Rule (RHR) could have the most significant impact on our operating results, financial condition and liquidity.

The Environmental Protection Agency (EPA) adopted the RHR in 1999 as an effort to improve visibility in national parks and wilderness areas.

The RHR requires states, in coordination with the EPA and other governmental agencies, to develop and implement state implementation plans (SIPs) which work towards achieving natural visibility conditions by the year 2064, to set goals to ensure reasonable progress is being made, and to periodically evaluate whether those goals and progress are on track or whether additional emission reductions are appropriate.

Emerging Regulation

The Environmental Protection Agency (EPA) adopted the Regional Haze Rule (RHR) in 1999 as an effort to improve visibility in national parks and wilderness areas.

The RHR requires states, in coordination with the EPA and other governmental agencies, to develop and implement state implementation plans (SIPs) that work towards achieving natural visibility conditions by the year 2064;

to set goals to ensure reasonable progress is being made;

and periodically evaluate whether those goals and progress are on track or whether additional emission reductions are appropriate.

The second RHR implementation period covers the years 2018-2028.

States are required to submit a state implementation plan to assess reasonable progress with the RHR and determine what additional emission reductions are appropriate, if any.

Coyote Station is subject to assessment in the second implementation period under the North Dakota SIP for the RHR.

The North Dakota Department of Environmental Quality (NDDEQ) submitted its proposed SIP to the EPA for approval in August 2022.

The North Dakota Department of Environmental Quality (NDDEQ) submitted its proposed RHR SIP to the EPA for approval in August 2022.

In its plan, the NDDEQ concluded it is not reasonable to require additional emission controls during this planning period.

The EPA submitted comments during the development of the SIP requesting NDDEQ to reassess its determination for Coyote Station.

The EPA is anticipated to take proposed action and potential final action on the SIP in 2023.

See Note 13 to our consolidated financial statements for additional information.

At this time we are unable to predict the ultimate impact, however, there could be a cost of compliance which could have a material impact on our operating results, financial condition and liquidity.

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In April 2023, the EPA released a proposal to tighten aspects of the Mercury and Air Toxics Standards, including the reduction of emissions limits for filterable particulate matter, and requiring the use of continuous emissions monitoring systems to demonstrate compliance.

Until the EPA takes final action on this rulemaking, we are unable to predict the ultimate impact, however, there could be a cost of compliance which could have a material impact on our operating results, financial condition and liquidity.

Climate Change and Greenhouse Gas Regulation

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The goal of the Paris Agreement is to limit the global temperature increase to well below 2° Celsius compared to pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5° Celsius.

The Biden Administration has announced the goal of reducing GHG emissions by 50 to 52 percent from 2005 levels in 2030 and to reach 100 percent carbon pollution-free electricity by 2035 as part of the U.S.

The Biden Administration set goals of reducing GHG emissions by 50% to 52% from 2005 levels in 2030 and reaching 100% carbon pollution-free electricity by 2035 as part of the U.S.

plan to achieve the goals under the Paris Agreement.

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Specific regulatory measures to address climate change continue to evolve.

In January 2021, the EPA's Affordable Clean Energy Rule (ACE Rule), which required states to develop plans for GHG emissions from coal-fired power plants, was vacated by the U.S.

Court of Appeals for the District of Columbia Circuit.

In October 2021, the U.S.

Supreme Court agreed to hear a consolidated challenge to the Court of Appeals decisions.

In June 2022, the U.S.

Supreme Court issued its opinion in the case of West Virginia v.

EPA, finding that in Section 111(d) of the Clean Air Act, Congress did not grant the EPA the authority to broadly regulate GHG emissions under the Clean Air Act, including the setting of emissions limits for existing power plants based on the power sector’s ability to shift to cleaner renewable energy sources (a process known as “generation shifting”).

The Supreme Court found that the authority to regulate issues that have broad economic or political consequences (known as the “major questions doctrine”) requires explicit Congressional authorization in law.

In the first half of 2023, the EPA is expected to issue a proposed rule under Clean Air Act section 111(d), replacing or revising the previously proposed ACE rule.

Although this future proposed rule is subject to the constraints of the Supreme Court’s West Virginia v.

EPA decision, the rule nevertheless has the potential to impact the emissions controls needed at OTP’s coal-fired power plants.

In May 2023, the EPA proposed new regulations under Section 111 of the Clean Air Act to regulate GHG emissions from existing and new fossil fuel-based electric generating units (EGU).

The proposal provides requirements for different types of fossil fuel-based EGUs with various compliance dates.

• For existing coal-fired steam generating units that were in operation before January 8, 2014 and that plan to operate past December 31, 2039, the proposal would (subject to certain exceptions) set emissions standards that reflect the use of carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions beginning in 2030.

• For existing coal-fired steam generating units that are scheduled to be retired between January 1, 2032 and December 31, 2039, the proposed rule would, in general, set emissions standards that reflect the use of co-firing 40% natural gas with coal beginning in 2030.

• For existing coal-fired steam generating units that will either (a) retire by January 1, 2032, or (b) retire between 2032 and December 21, 2034 and will operate at a 20% annual capacity factor limit in the meantime, the proposed rule would simply require routine maintenance and no increase in emission rate.

The proposal also includes emission standards for existing large (greater than 300 mega-watt), frequently used (those that operate at a capacity factor over 50%) natural gas combustion turbines, including which emission standard would reflect the use of CCS by 2035 or co-firing with low-GHG hydrogen at incremental portions in 2032 (30% of volume) and 2038 (96% of volume).

Under the proposed rule, each state must submit a plan to the EPA to implement standards that are at least as stringent as the EPA’s emission guidelines, unless states demonstrate that due to remaining useful life and other factors, a facility cannot reasonably achieve the standards.

The EPA is proposing to require states to submit their plans within 24 months of the effective date of the final regulation.

This proposed rule has the potential to impact the emissions controls needed at OTP’s coal-fired power plants, which could have an impact on our operating results, financial condition and liquidity.

While the future financial impact of any current, proposed, or pending litigation or regulation of GHG or other emissions is unknown at this time, any capital or operating costs incurred for additional pollution control equipment or emission reduction measures could materially adversely impact our future operating results, financial position, and liquidity unless such costs could be recovered through related rates and/or future market prices for energy.

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BTD Manufacturing, Inc.

(BTD), with headquarters located in Detroit Lakes, Minnesota, provides metal fabrication services for custom machine parts and metal components through metal stamping, tool and die, machining, tube bending, welding and assembly in its facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia.

(BTD), with facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia, provides metal fabrication services for custom machine parts and metal components through metal stamping, tool and die, machining, tube bending, welding and assembly.

Plastics, Inc.

Plastics) , with facilities in Otsego and Clearwater, Minnesota, manufactures extruded and thermoformed plastic products, including custom parts for customers in several industries and its own line of horticulture containers.

Examples of products produced include clamshell packing, blister packs, returnable pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts.

Plastics) , with facilities in Otsego and Clearwater, Minnesota, manufactures thermoformed plastics products, including its own line of horticulture containers and custom packaging products for the medical and industrial product markets.

Our metal fabrication business primarily serves Midwestern and Southeastern U.S.

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Our plastic products business serves primarily U.S.

customers in the horticulture, medical and life sciences, industrial, recreational and electronics industries.

customers in the

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horticulture, medical and life sciences, industrial, recreational and electronics industries.

The principal method of production distribution is by direct shipment to our customers through direct customer pick-up or common carrier ground transportation.

No single customer or product of our Manufacturing segment businesses accounted for 10% or more of our consolidated operating revenues in 2023.

However, the top three customers combined to account for 50% and 46% of our 2022 and 2021 Manufacturing segment operating revenues, respectively.

However, two customers combined to account for 30% of segment operating revenues for the year ended December 31, 2023 and 40% for the year ended December 31, 2022.

COMPETITIVE CONDITIONS

The various markets in which we compete are characterized by intense competition from both foreign and domestic manufacturers.

These markets have many established manufacturers with broader product lines, greater distribution capabilities, greater capital resources, excess capacity, labor advantages and larger marketing, research and development staffs and facilities than our own.

We compete in a highly fragmented market with competition from both domestic and international entities.

Our competitors vary in size, ranging from small companies focused on certain end markets or geographical area, to large companies with broad manufacturing capabilities and geographical reach.

Competition can be geographically regionalized as customers procure products locally to manage cost and minimize logistical complexities.

Certain competitors may have broader product lines, more manufacturing capacity, and greater distribution capabilities than we do.

We believe the principal competitive factors in our Manufacturing segment are product performance, quality, price, technical innovation, cost effectiveness, customer service and breadth of product line.

We intend to continue to compete based on high-performance products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.

We intend to continue to compete based on high quality products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.

RESOURCE MATERIALS

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Vinyltech Corporation (Vinyltech) , located in Phoenix, Arizona, manufactures and sells PVC pipe for municipal water, wastewater, water reclamation systems and other uses in the western, northwest and south-central regions of the United States.

PVC pipe is manufactured through a process known as extrusion.

During this process, PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe.

PVC pipe is manufactured through an extrusion process, during which PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe.

The newly extruded pipe is pulled through a series of water-cooling tanks, marked to identify the type of pipe and cut to finished lengths.

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No single customer of the PVC pipe companies accounted for 10% or more of our consolidated operating revenues in 2023.

However, two customers, both of which are distributors of PVC pipe, combined to account for 46% and 50% of our 2022 and 2021 Plastics segment operating revenues, respectively.

However, two customers, both of which are distributors of PVC pipe, combined to account for 36% of segment operating revenues for the year ended December 31, 2023 and 46% for the year ended December 31, 2022.

COMPETITIVE CONDITIONS

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Pricing pressure will continue to affect our operating margins in the future.

We will continue to compete based on our high-quality products, cost-effective production techniques and close customer relations and support.

We will continue to compete based on our high-quality products, cost-effective production techniques and close customer relations and support, including our responsiveness and reliability.

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RESOURCE MATERIALS

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There are four vendors from which we can source our PVC resin requirements.

In 2022 we sourced all of our PVC resin from two vendors.

In 2023 we sourced all of our PVC resin from three vendors.

Our contractual arrangements to acquire resin generally include estimated annual order quantities with no required minimum purchases, and include variable pricing based on market prices for resin.

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Our plastics businesses are subject to environmental, health and safety laws and regulations, including those governing discharges to air and water, the management and disposal of hazardous substances, the cleanup of contaminated sites and health and safety matters.

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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 1. Business