EDGAR 10-K Filing

Company CIK: 1466593
Filing Year: 2024
Filename: 1466593_10-K_2024_0001466593-24-000039.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
Otter Tail Corporation (OTC) has interests in diversified operations that include an electric utility and manufacturing and plastic pipe businesses with corporate offices located in Fergus Falls, Minnesota and Fargo, North Dakota.
We classify our five operating companies into three reportable segments consistent with our business strategy and management structure. The following table depicts our three segments and the subsidiary entities included within each segment:
ELECTRIC SEGMENT MANUFACTURING SEGMENT PLASTICS SEGMENT
Otter Tail Power Company (OTP) BTD Manufacturing, Inc. (BTD) Northern Pipe Products, Inc. (Northern Pipe)
T.O. Plastics, Inc. (T.O. Plastics) Vinyltech Corporation (Vinyltech)
Electric includes the generation, purchase, transmission, distribution and sale of electric energy in western Minnesota, eastern North Dakota and northeastern South Dakota. 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; metal parts stamping; fabrication and painting; and production of plastic thermoformed horticultural containers, life science and industrial packaging, material handling components and extruded raw material stock. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the western half of the United States and Canada.
Throughout the remainder of this report, we use the terms "Company", "us", "our", or "we" to refer to OTC and its subsidiaries collectively. We will also refer to our Electric, Manufacturing and Plastics segments and our individual subsidiaries as indicated above.
INVESTMENT AND GROWTH STRATEGY
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 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. 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. We will also evaluate opportunities to allocate capital to potential acquisitions. We are a committed long-term owner and do not acquire companies in pursuit of short-term gains. 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. The operating company should:
•Maintain a minimum level of net earnings and a return on invested capital in excess of the Company’s weighted-average cost of capital,
•Have a strategic differentiation from competitors and a sustainable cost advantage,
•Operate within a stable and growing industry and be able to quickly adapt to changing economic cycles, and
•Have a strong management team committed to operational and commercial excellence.
Our actual mix of earnings for the years ended December 31, 2023, 2022 and 2021 was as follows:
HUMAN CAPITAL
Our employees are a critical resource and an integral part of our success. 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, 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. In managing our business, we focus on the safety of our employees and have implemented safety programs and management practices to promote a culture of safety. Safety is also a metric used and evaluated in determining annual incentive compensation. 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 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. Our skill progression and technical training programs help to retain a stable and skilled workforce.
Workforce Stability - Recruiting, retaining and developing employees is an important factor in our continued success and growth. We regularly evaluate our recruiting programs, employee retention and turnover rates.
Employee Engagement - To enhance the effectiveness of our workforce and to help our companies continue to be places where our employees choose to work and thrive, we have undertaken a multi-year series of employee engagement surveys. 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. We hold every employee accountable for their behavior in maintaining a workplace free of discrimination and harassment. 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 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.
As of December 31, 2023, we employed 2,655 full-time employees as shown in the table below:
Segment/Organization Employees
Electric Segment
OTP (1)
Manufacturing Segment
BTD 1,458
T.O. Plastics 192
Segment Total 1,650
Plastics Segment
Northern Pipe 98
Vinyltech 80
Segment Total 178
Corporate 37
Total 2,655
(1) Includes all full-time employees of Otter Tail Power Company, including employees working at jointly owned facilities. Labor costs associated with employees working at jointly owned facilities are allocated to each of the co-owners based on their ownership interest.
At December 31, 2023, 378 employees of OTP were represented by local unions of the International Brotherhood of Electrical Workers under two separate collective bargaining agreements expiring on August 31, 2026 and October 31, 2026. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good. None of the employees of our other operating companies are represented by local unions.
The demographics of our workforce, including our Board of Directors, as of December 31, 2023 was as follows:
% Female % Racially and Ethnically Diverse
Board of Directors
36 % 9 %
CEO Direct Reports 33 % - %
Management 21 % 4 %
Non-Management Employees 15 % 15 %
ELECTRIC Contribution to Operating Revenues: 39% (2023), 38% (2022), 40% (2021)
OTP, headquartered in Fergus Falls, Minnesota, is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve its more than 133,000 residential, commercial and industrial customers in a service area encompassing approximately 70,000 square miles of western Minnesota, eastern North Dakota and northeastern South Dakota.
CUSTOMERS
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 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:
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.
COMPETITIVE CONDITIONS
Retail electric sales are made to customers in assigned service territories. As a result, most retail customers do not have the ability to choose their electric supplier. Competition is present in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and co-generators. Electricity also competes with other forms of energy.
Competition also arises from customers supplying their own power through distributed generation, which is the generation of electricity on-site or close to where it is needed in small facilities designed to meet local needs. Distributed energy resources can include combined heat and power, solar photovoltaic, wind, battery storage, thermal storage and demand-response technologies.
The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy and advances in technology. Irrespective of the competitive environment, we are focused on providing value to our customers and ensuring our retail rates remain among the lowest in the region and in the nation.
The following table presents our average retail rate per kilowatt-hour (kwh) by customer class and in total for the years ended December 31, 2023 and 2022:
Revenue per kwh 2023 2022
Residential 10.82 ¢ 10.99 ¢
Commercial & Industrial 7.02 ¢ 7.54 ¢
Total Retail 7.90 ¢ 8.41 ¢
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 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. Franchise rights generally require periodic renewal. No franchises are required to serve unincorporated communities in any of the three states OTP serves.
GENERATION AND PURCHASED POWER
OTP primarily relies on company-owned generation, supplemented by power purchase agreements, to supply the energy to meet our customer needs. Wholesale market purchases and sales of electricity are used as necessary to balance supply and demand. 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.
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:
Capacity /
Purchased Power
in kW
Owned Generation:
Baseload Plants
Big Stone Plant(1)
256,900
Coyote Station(2)
148,400
Total Baseload Plants 405,300
Combustion Turbine and Small Diesel Units
Astoria Station 249,700
All Other 102,800
Total Combustion Turbine and Small Diesel Units 352,500
Owned Wind Facilities (rated at nameplate)
Merricourt
150,000
Ashtabula III
62,400
Luverne
49,500
Ashtabula
48,000
Langdon
40,500
Total Owned Wind Facilities 350,400
Hoot Lake Solar
49,900
Hydroelectric Facilities 2,600
Total Owned Generation Capacity 1,160,700
Power Purchase Agreements:
Purchased Wind Power (rated at nameplate and greater than 2,000 kW)
Edgeley 21,000
Langdon 19,500
Total Purchased Wind 40,500
Total Generating Capacity 1,201,200
(1) Reflects OTP's 53.9% ownership percentage of jointly owned facility.
(2) Reflects OTP's 35.0% ownership percentage of jointly owned facility.
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 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.
The following charts summarize the percentage of retail kwh sold by source during the years ended December 31, 2023 and 2022:
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
OTP is committed to transitioning to a lower-carbon and increasingly clean energy future, while maintaining affordable and reliable electricity to serve our customers. We have developed the following goals in furtherance of our efforts to support the energy transition:
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.
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 (CO2) 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.
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:
RESOURCE MATERIALS
Coal is the principal fuel burned at our jointly owned Big Stone and Coyote Station generating plants. Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Big Stone Plant burns western subbituminous coal transported by rail. 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, 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 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. We procure natural gas from multiple vendors at spot prices in a liquid market primarily under firm delivery contracts.
TRANSMISSION AND DISTRIBUTION
Our transmission and distribution assets deliver energy from energy generation sources to our customers. 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, 2023, we were the sole or joint owner of approximately 14,000 miles of transmission and distribution lines.
Midcontinent Independent System Operator
MISO is an independent, non-profit organization that operates the transmission facilities owned by other entities, including OTP, within its regional jurisdiction and administers energy and generation capacity markets. MISO has operational control of our transmission facilities above 100 kilovolts (kV). 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.
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.
SEASONALITY
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. 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.
PUBLIC UTILITY REGULATION
OTP is subject to regulation of rates and other matters in each of the three states in which it operates and by the federal government for, among other matters, the interstate transmission of electricity. OTP operates under approved retail electric tariff rates in all three states it serves. Tariff rates are designed to recover plant investments, a return on those investments, and operating costs. In addition to determining rate tariffs, state regulatory commissions also authorize return on equity (ROE), capital structure, and depreciation rates of our plant investments. Decisions by our regulators significantly impact our operating results, financial position, and cash flows.
Below is a summary of the regulatory agencies with jurisdiction of electric rates over OTP covered by each regulatory agency:
Regulatory
Agency Areas of Regulation
Minnesota Public Utilities Commission
(MPUC)
Retail rates, issuance of securities, depreciation rates, capital structure, public utility services, construction of major facilities, establishment of exclusive assigned service areas, contracts with subsidiaries and other affiliated interests and other matters.
Selection or designation of sites for new generating plants (50,000 kW or more) and routes for transmission lines (100 kV or more).
Review and approval of fifteen-year Integrated Resource Plan.
North Dakota Public Service Commission
(NDPSC) Retail rates, certain issuances of securities, construction of major utility facilities and other matters.
Approval of site and routes for new electric generating facilities (>500 kW for wind generating facilities; >50,000 kW for non-wind generating facilities) and high voltage transmission lines (>115 kV).
Review of fifteen-year Integrated Resource Plan.
South Dakota Public Utilities Commission
(SDPUC) Retail rates, public utility services, construction of major facilities, establishment of assigned service areas and other matters.
Approval of sites and routes for new electric generating facilities (100,000 kW or more) and most transmission lines (115 kV or more).
Federal Energy Regulatory Commission
(FERC) Wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, hydroelectric licensing and accounting policies and practices.
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 our capital investments and operating expenses between rate cases. The following table summarizes these recovery mechanisms:
Recovery Mechanism Jurisdiction(s) Additional Information
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. 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.
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.
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.
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.
Energy Efficiency Plan (EEP) SD Provides for the recovery of costs from energy efficiency investments.
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.
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.
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 a 15-year advance IRP every three years.
Capital Structure Petition
Minnesota law requires an annual filing of a capital structure petition with the MPUC. In this filing the MPUC reviews and approves OTP's capital structure. 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 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
Minnesota has a renewable energy standard requiring utilities to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 25% by 2025 and 55% by 2035. Qualifying renewable sources are classified as wind, hydropower, hydrogen, and certain biomass generation. We met the current renewable sources requirements with a combination of owned renewable generation and purchases from renewable generation sources. Minnesota law also requires 1.5% of total Minnesota retail electric sales by public utilities to be supplied by solar energy. 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. 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
In February 2023, Minnesota enacted the Clean Energy Bill, which requires electric utilities to generate or procure sufficient electricity from carbon-free resources, to provide retail customers in Minnesota with at least the following percentages of carbon-free electric energy: 80% by 2030, 90% by 2035, and 100% by 2040. Carbon-free resources include wind, solar, hydropower, and nuclear generation. 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
OTP is subject to stringent federal and state environmental standards and regulations regarding, among other things, air, water and solid waste pollution. OTP's facilities have been designed, constructed and, as necessary, updated to operate in compliance with applicable environmental regulations. However, new or amended laws and regulations or changes in interpretations of current laws and regulations may require additional pollution control equipment or emission reduction measures, and there can be no assurance that our facilities will remain economic to operate. Prudent expenditures incurred to comply with environmental regulations are eligible to be recovered in rates authorized by regulators in jurisdictions in which we operate; however, there can be no assurance that future costs will be authorized for recovery. Alternatively, additional pollution control equipment or other emission reduction measures may prove to be uneconomic, potentially leading to the exiting of a facility earlier than originally planned. 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. Our construction budget for the next five years includes approximately $7.5 million of capital investments in environmental control equipment. The timing and amount of our expenditures may change as the regulatory environment changes.
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.
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 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. 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.
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
Global climate change presents a significant energy and environmental policy challenge. Combustion of fossil fuels for the generation of electricity is a considerable source of CO2 emissions, which is the primary GHG emitted by our utility operations. The federal government and many states are pursuing climate policies to regulate GHG emissions as part of a broad-based effort to limit global warming.
In February 2021, the U.S. rejoined the United Nations Framework Convention on Climate Change (the Paris Agreement), which is a legally binding international treaty on climate change adopted by over 190 countries. 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 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.
In February 2023, Minnesota enacted the Clean Energy Bill, which requires electric utilities to generate or procure sufficient electricity from carbon-free resources to provide retail customers in Minnesota with at least the following percentages of carbon-free electric energy: 80% by 2030, 90% by 2035, and 100% by 2040.
The implementation of climate change programs, such as the Paris Agreement, the Minnesota Clean Energy Bill, and other federal or state regulations targeting GHG emissions may have a significant impact on our utility business. Specific regulatory measures to address climate change continue to evolve.
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 CO2 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.
MANUFACTURING Contribution to Operating Revenues: 30% (2023), 27% (2022), 28% (2021)
Manufacturing consists of businesses engaged in the following activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components and extruded raw material stock. The following is a brief description of each of these businesses:
BTD Manufacturing, Inc. (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.
T.O. Plastics, Inc. (T.O. 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.
CUSTOMERS
Our metal fabrication business primarily serves Midwestern and Southeastern U.S. manufacturers in the recreational vehicle, lawn and garden, agricultural, construction, and industrial and energy equipment end markets. Our plastic products business serves primarily U.S. customers in the
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, 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
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 quality products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.
RESOURCE MATERIALS
We use raw materials in the products we manufacture, including, among others, steel, aluminum, and polystyrene and other plastics resins. Managing price volatility and ensuring raw material availability are important aspects of our business. We attempt to pass increases in the costs of these raw materials through to our customers. Increases in the costs of raw materials that cannot be passed on to customers could have a negative effect on profit margins. Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our Manufacturing segment as it reduces their ability to mitigate the costs associated with excess material.
ENVIRONMENTAL REGULATION
Our manufacturing 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.
PLASTICS Contribution to Operating Revenues: 31% (2023), 35% (2022), 32% (2021)
Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The following is a brief description of these businesses:
Northern Pipe Products, Inc. (Northern Pipe), located in Fargo, North Dakota, manufactures and sells PVC pipe for municipal water, rural water, wastewater, storm drainage systems and other uses in the northern, midwestern, south-central and western regions of the United States as well as central and western Canada.
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 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.
CUSTOMERS
PVC pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Customers for our PVC pipe products consist primarily of wholesalers and distributors, and the principal method for distribution of our products is by common carrier ground transportation. 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 36% of segment operating revenues for the year ended December 31, 2023 and 46% for the year ended December 31, 2022.
COMPETITIVE CONDITIONS
The plastic pipe industry is fragmented and competitive due to the number of producers, the small number of raw material suppliers and the fungible nature of the product. Due to shipping costs, competition is usually regional instead of national in scope. The principal factors of competition are price, customer service and product performance. We compete not only against other plastic pipe manufacturers, but also ductile iron, high-density polyethylene, steel and concrete pipe producers. 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, including our responsiveness and reliability.
RESOURCE MATERIALS
PVC resins are acquired in bulk and shipped to our facilities by rail. There are four vendors from which we can source our PVC resin requirements. 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. The supply of PVC resin may also be limited primarily due to manufacturing capacity and the limited availability of raw material components. Most U.S. resin production plants are located in the Gulf Coast region. These plants are subject to the risk of damage and production shutdowns because of exposure to hurricanes or other extreme weather events that occur in this part of the United States. The loss of a key vendor, or any interruption or delay in the supply of PVC resin could disrupt the ability of our Plastics segment businesses to manufacture products, cause customers to cancel orders or result in increased expenses for obtaining PVC resin from alternative sources, if such sources were available. We believe we have good relationships with our key raw material vendors.
Due to the commodity nature of PVC resin and PVC pipe and the dynamic supply and demand factors worldwide, historically the markets for both PVC resin and PVC pipe have been very cyclical with significant fluctuations in prices and gross margins.
In addition to PVC resin, we use certain other materials, such as stabilizers, gaskets and lumber, in the process of manufacturing and shipping our PVC pipe products. We generally source these materials from a limited number of suppliers, and supply chain constraints or disruptions related to these materials could disrupt our ability to manufacture or ship products and could result in increased costs.
SEASONALITY
Demand for our PVC pipe products can be impacted by seasonal weather differences, with generally lower sales volumes realized in the first quarter of the year when cold temperatures and frozen ground across the northern portion of our footprint can delay or prevent construction activity and consequently delay or prevent customer orders of PVC pipe.
ENVIRONMENTAL REGULATION
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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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
RISK FACTORS AND CAUTIONARY STATEMENTS
Our businesses are subject to various risks and uncertainties. Any of the risks described below or elsewhere in this report on Form 10-K or in our other SEC filings could materially adversely affect our business, operating results, financial condition and liquidity. Additional risks and uncertainties we are not presently aware of or that we currently consider immaterial may also affect our business, operating results, financial condition and liquidity.
OPERATIONAL RISKS
Our strategy includes large capital investments, which are subject to risks.
Our business strategy includes major capital investments at our operating companies. These capital projects are planned years in advance of their in-service dates and are subject to various risks including: adverse changes in regulatory treatment or public policy; changes in commodity pricing or construction costs; delivery of critical materials; obtaining necessary permits and licenses; and other adverse conditions. Capital investments in our Electric segment require regulatory approval and are subject to the risks of not being granted timely approval or allowed to be fully recovered. In addition, our ability to construct and own utility assets may be impacted by regulatory requirements to competitively bid such investments, which could impact the amount and timing of our capital investments. A lack of direct ownership, or the inability to complete capital projects on budget and in a timely manner could impact our ability to achieve our strategic financial goals and could adversely impact our operating results and financial condition.
Weather impacts, including seasonal fluctuations, could adversely affect our operating results.
Our Electric segment business is seasonal and weather patterns have had an impact on our financial performance in the past and may again in the future. Demand for electricity is normally greater in the winter and summer months. Unusually mild summers and winters could have an adverse effect on our financial condition and results of operations. Our Plastics segment businesses can be affected by seasonal weather prohibiting or delaying construction projects at any time of the year in any geography, but specifically times of the year when frozen ground and cold temperatures in many parts of the country can delay construction projects, all of which can result in reduced customer demand and could have an adverse effect on our financial condition, operating results and liquidity.
We are subject to physical and transition risks associated with climate change and extreme weather events.
Longer term shifts in climate patterns may impact our customers' demand for electricity, interrupt our business operations and damage our facilities; reduce the availability of natural resources, such as water; and cause disruptions in our supply chains.
Climate change may increase the frequency and severity of extreme weather events, such as prolonged periods of extreme cold or heat, and natural disasters, such as severe snow and ice storms, tornadoes, flooding and wildfires. These acute events could result in the interruption of our business operations and damage to our facilities. An extreme weather event within our utility service area could directly affect our capital assets, causing disruption in service to customers, and result in reduced operating revenues and repair or replacement costs, due to downed wires and poles or damage to other operating equipment.
In the past, severe weather events in the Gulf Coast region of the U.S. have disrupted the supply of PVC resin, the primary material input of our Plastics segment businesses. As most U.S. PVC resin production plants are located in the Gulf Coast region, an area prone to seasonal hurricane activity and other extreme weather events, our access to PVC resin may be impacted by the volume and magnitude of hurricane and storm activity in this region, which could impact our Plastics segment businesses.
Increased risk of natural disasters, such as wildfires, could have financial consequences, including limiting our ability to secure sufficient insurance coverage, or lead to increased insurance cost. While we carry liability insurance, given an extreme event, if we were found to be liable for damages, amounts that exceed our coverage limit could negatively impact our financial condition, operating results and liquidity.
These risks may also negatively impact our credit ratings, which may limit our access to capital markets and increase our borrowing costs. In addition, to the extent investors view climate change, fossil fuel combustion and GHG emissions as a financial risk, our stock price or our ability to access capital markets on favorable terms and conditions could be adversely impacted.
We may experience transition risks in moving towards low carbon generation and manufacturing. For example, we may face challenges with the adoption of new technologies, meeting changing customer expectations and committing to voluntary GHG emissions reduction goals, as well as complying with evolving local, state or federal regulatory requirements intended to reduce GHG emissions.
The loss of, or significant reduction in revenue from, any of our key customers could have an adverse effect on our operating results.
While no single customer provided more than 10% of our consolidated operating revenues, each of our segments have customers which accounted for over 10% of the segment’s operating revenues. In 2023, two customers accounted for 21% of Electric segment revenues, two customers combined to account for 30% of Manufacturing segment operating revenues and two customers combined to account for 36% of Plastics segment operating revenues. The loss of any one of these customers or a significant decline in sales to these customers, would have a significant negative impact on the segment's financial condition and operating results, and could have a significant negative impact on the Company’s consolidated financial condition, operating results and liquidity.
We are subject to counterparty credit risk.
We extend credit to our customers in the ordinary course of business in each of our operating segments. Our customers' ability to pay depends on a variety of factors including macroeconomic conditions, local economic conditions including unemployment rates, and industry conditions in which our customers operate. Increased customer delinquencies and bad debts could adversely impact our operating results and liquidity.
Our operations are subject to environmental, health and safety laws and regulations.
We are subject to numerous federal, state, and local environmental, health and safety laws and regulations governing, among other things, discharges to air and water, natural resources, hazardous waste and toxic substances, the cleanup of contaminated sites, and health and safety matters. Our failure to comply with applicable laws and regulations could result in civil or criminal fines or penalties, enforcement actions, and regulatory or judicial orders enjoining or curtailing operations or requiring corrective measures, which could materially and adversely affect our business. Compliance with these laws and regulations is a significant factor in our business. We have incurred and expect to continue to incur capital expenditures and operating costs to comply with applicable current and future laws and regulations.
Our businesses continue to be subject to additional and changing environmental, health and safety laws and regulations, and we could incur additional costs complying with requirements that are promulgated in the future. New laws or regulations or changes to existing laws and regulations in the future may result in disruptions to our business, changes in customer preferences, or changes in customer demand, which could adversely impact our financial condition, operating results and liquidity.
Recently, various federal and state agencies have heightened their scrutiny of per- and polyfluoroalkyl substances (PFAS), which are manufactured chemicals used in a variety of consumer and industrial products. Regulators have recently proposed additional chemicals be designated as hazardous substances, including a proposal to designate perfluorooctanesulfonic acid and perfluorooctanoic acid, two of the most common PFAS chemicals, as hazardous substances, which could have wide-ranging impacts on companies across various industries, including ours. We are investigating whether PFAS compounds are used in our manufacturing or operating processes that occur in our various businesses. At this time, we cannot predict the outcome or the severity of the impact, if any, of future laws or regulations enacted to address PFAS.
A cyber incident, security breach or system failure could adversely affect our business and operating results.
The operation of our business is dependent on the secure functioning of our computer hardware and software systems, as well as that of third-party service providers and vendors we use to electronically process certain of our business transactions. Information systems, both ours and those of third parties, are vulnerable to security breaches by computer hackers and cyber terrorists, and the negligent or intentional breach of established controls and procedures, or mismanagement of confidential information by employees. Cyber-attacks or other security breaches may also be perpetrated through the use of artificial intelligence, which could introduce additional complexity to such an attack or breach. While we employ a defense-in-depth strategy and regularly conduct cybersecurity assessments, we cannot be certain our information security systems and protocols and those of our vendors and other third parties are sufficient to withstand a cyber-attack or other security breach.
A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage, and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. For example, we may be subject to liability under various federal, state and international disclosure laws and data protection laws. These laws are subject to change and expansion and may require additional operational changes and costs to comply.
The misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant monetary damages, regulatory enforcement actions and breach notification and mitigation expenses, such as credit monitoring, and result in reputational damage affecting relations with shareholders, customers, regulators and others. In addition to property and casualty insurance, which may cover restoration of data, certain physical damage or third-party injuries, we have cybersecurity insurance related to a breach event. However, damage and claims arising from such incidents may not be covered or may exceed the amount of any available insurance.
The inability to attract and retain a qualified workforce could have an adverse effect on our operations.
The success of our business is heavily dependent on the leadership of our executive officers and key employees for implementation of our strategy. In addition, all of our businesses rely on a qualified workforce, including technical employees who possess certain specialized knowledge and skills. The inability to attract and retain a skilled and stable workforce at necessary staffing levels, whether due to decreases in hiring rates, increases in employee retirements, increases in terminations, or any combination thereof, may negatively affect our ability to service our customers, manufacture products or successfully manage our business and achieve our objectives.
Our acquisition or divestiture strategies are subject to risk and could adversely impact our financial position and operating results.
As part of our business strategy, we continually assess our mix of businesses and potential strategic acquisitions or divestitures. This investment strategy is subject to various risks, including the ability to identify appropriate acquisition candidates, or successfully negotiate and finance any acquisitions. In addition, difficulties in integrating the operations, services, products and personnel of the acquired business, and the potential loss of key employees, customers and suppliers of the acquired business could adversely impact our financial condition and operating results.
FINANCIAL RISKS
We are subject to capital market and interest rate risks.
We rely on access to debt and equity capital markets as a source of liquidity to fund our investment initiatives, including rate base growth investments in our Electric segment and opportunities for investment, including acquisitions, in our Manufacturing and Plastics segments. Capital markets are impacted by global and domestic economic conditions, monetary policy, commodity prices, geopolitical events and other factors. If we are unable to access capital on acceptable terms and at reasonable costs, our ability to implement our business plans may be adversely affected. In addition, higher market interest rates on outstanding variable-rate, short-term indebtedness could also impact our operating results. In 2023, rising market interest rates caused the applicable rate of interest on our short-term indebtedness to increase significantly. However, the impact to our operating results was not significant due to our low level of outstanding borrowings on our short-term indebtedness. Our operating results could be
impacted if we significantly increase our short-term borrowings or issue new long-term debt, and interest rates remain elevated or continue to increase.
A decrease in our credit ratings could increase our borrowing costs and result in additional contractual costs.
We rely on our investment grade credit ratings to provide acceptable costs for accessing the capital markets. A downgrade of our credit ratings could result in higher borrowing costs thereby negatively impacting our operating results and limiting our ability to access capital markets, which may negatively impact our ability to implement our business plans. In addition, OTP is a party to contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below certain levels.
Our pension and other postretirement benefit plans are subject to investment and interest rate risks.
The financial obligations and related costs of our pension and other postretirement benefit plans are affected by numerous factors. Assumptions related to future costs, investment returns, actuarial estimates and interest rates have a significant effect on our funding obligations and the cost recognized related to these plans. If our pension plan assets do not achieve our estimated long-term rate of return or if our other estimates prove to be inaccurate, our operating results, financial condition and liquidity may be adversely impacted. In addition, our funding requirements could be impacted by changes to the Pension Protection Act.
We rely on our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and pay dividends to our shareholders.
Otter Tail Corporation is a holding company with no significant operations of its own. The primary source of funds for payment of our financial obligations and dividends to our shareholders is from cash provided by our subsidiary companies. Our ability to meet our financial obligations and pay dividends on our common stock principally depends on the earnings, cash flows, capital requirements and general financial positions of our subsidiary companies. In addition, OTP is subject to federal and state regulations which may restrict its ability to pay dividends. Finally, we are also reliant on our subsidiary companies to maintain compliance with financial covenants under our various short- and long-term debt agreements. Our debt agreements include restrictions on the payment of cash dividends upon an event of default.
Changes in tax laws could materially affect our financial condition and operating results.
Our provision for income taxes and tax obligations are impacted by various tax laws and regulations, including the availability of various tax credits, IRS tax policies such as tax normalization and, at times, the ability to carryforward net operating losses and tax credits. Changes in tax laws, regulations and interpretations could have an adverse effect on our financial condition and operating results. Tax law changes that reduce or eliminate production or investment tax credits (ITCs), or the ability to transfer or sell these credits, may impact the economics of constructing certain electric generation resources, which may impact our planned investments, and could adversely affect our financial condition and operating results.
ELECTRIC SEGMENT RISKS
General economic and industry conditions impact our business.
Several factors, many of which are beyond our control, may contribute to reduced demand for energy from our customers or increase the cost of providing energy to our customers. These risks include economic growth or decline in our service areas, demographic changes in our customer base and changes in customer demand or load growth due to, among other items, proliferation of distributed generation, energy efficiency initiatives and technological advancements. In addition, customer demand could be impacted by increased competition in our service territories or the loss of a service territory or franchise. Other risks include increased transmission or interconnection costs, generation curtailment and changes in the manner in which wholesale power is purchased and sold. A decrease in revenues or an increase in expenses related to our electric operations could negatively impact our financial condition, operating results and liquidity.
Our utility business is significantly impacted by government legislation and regulation.
OTP is subject to federal and state legislation and comprehensive regulation by federal and state regulatory agencies, including the public utility commissions in each of the three states in which OTP operates, and by the FERC. State utility commissions regulate, among other matters, the establishment of assigned service areas, the siting and construction of major facilities, the capital structure of the utility business, and the allowed rates to charge customers for providing energy and utility service. Each state utility commission operates independent of one another; therefore, OTP is subject to and must adhere to the decisions of each independent state commission. The FERC regulates, among other matters, wholesale energy transactions, hydroelectric licensing, transmission and sale of electric energy in interstate commerce, and the interconnection of electric facilities.
Our financial condition, operating results and liquidity are significantly impacted by, and dependent upon, our ability to recover the costs associated with providing utility service and earn a return on our utility capital investments. There is no assurance that each state utility commission will judge our utility costs to have been prudently incurred or that rates will produce full recovery of such costs. In addition, changes in the federal or state regulatory framework could impair our ability to recover utility costs historically collected from our customers. Diverging public policy priorities across the jurisdictions we serve, and a lack of inter-jurisdictional consensus, may impact our ability to recover the cost of, and return on, our capital investments and our operating costs; it may impact our future capital investment opportunities; and may result in inefficiencies which could negatively impact our financial position, operating results and liquidity.
In addition to the recovery of our utility costs, our profitability is impacted by our authorized ROE, which can be impacted by macroeconomic factors such as interest rates. There can be no assurance that each state utility commission or the FERC will authorize a rate of return which allows us to achieve our financial goals. An adverse decision by one or more regulatory authorities or any prolonged delay in rendering a decision in a rate or other proceeding could adversely impact our financial condition, operating results and liquidity.
Inflationary cost pressures have increased the cost of constructing our utility assets and operating our utility business. There can be no assurance that our state regulatory commissions will authorize recovery of rising costs. Regulatory commissions may also limit future capital investments or the rate of return allowed on such investments in response to inflationary cost pressures and customer bill impacts. Such limitations could negatively impact our financial position, operating results and liquidity.
Our generating facilities are subject to risks that could result in early closure or the sale of our ownership interest.
Changes in operational or economic factors, environmental regulation or risks of litigation could result in the early closure or the sale of our interest in a generating facility. In the event of an early closure, a significant asset impairment charge could be required, and we would be obligated to pay for our share of the costs of closure of the generating facility, including costs associated with decommissioning, remediation, reclamation and restoration of the property, and any costs of terminating contracts associated with the generating facility, such as coal supply arrangements. In the event of a sale of our interest in a generating facility, we may not be able to negotiate the sale on favorable terms, which could result in the recognition of a loss on the sale and other potential liabilities. There can be no assurance that we would be authorized by any of our state utility commissions to recover any costs or losses associated with the early closure of or sale of our interest in a generating facility.
The loss of a major generating facility would require OTP to identify and obtain approval for other sources of generation for its customers, if available, and potentially expose us to higher purchased power costs. In addition, OTP may not be able to obtain timely regulatory approval for new generation resources to replace closed or sold facilities.
Our IRP, as revised in two supplemental filings in 2023, outlined our plan to withdraw from our 35% ownership interest in Coyote Station, a jointly owned coal-fired generation plant, in the event we are required to make a major, non-routine capital investment in the plant. In the event we were to withdraw from our ownership, we will seek to recover all costs related to the withdrawal from Coyote Station; however, there is a risk we may not be granted recovery of such costs. A full or partial denial of recovery of the costs of withdrawal could significantly impact our operating results, financial condition and liquidity.
Joint ownership of coal-fired generation facilities could impact our ability to manage changing regulations and economic conditions.
We own our coal-fired generation facilities jointly with other co-owners with varying ownership interests in such facilities. Our ability to make determinations on our IRP in order to best navigate changing environmental regulations and economic conditions may be impacted by our rights and obligations under the co-ownership agreements and related agreements, and our ability to reconcile a divergence in the interests of OTP and the co-owners of these generation facilities. Such a divergence could impair our ability to effectively manage these changing conditions to meet our strategic objectives and could adversely impact our financial condition, operating results and liquidity.
Federal and state environmental regulation could require us to incur substantial capital expenditures, increased operating costs or make it no longer economically viable to operate some of our facilities.
We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements may require us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.
Coyote Station, one of OTP's jointly owned coal-fired power plants, is subject to assessment under the second implementation period of RHR as part of the state of North Dakota's RHR SIP. We cannot predict with certainty the impact the SIP may have on our business until the plan has been approved or otherwise acted on by the EPA, including its potential implementation of an alternative federal implementation plan. However, significant emission control investments could be required. Alternatively, investments in emission control equipment may prove to be uneconomic and result in the early closure or the sale of, or withdrawal from, our interest in Coyote Station.
Existing environmental laws or regulations may be revised and new laws or regulations may be adopted or become applicable to us. The multiple jurisdictions that govern our electric utility business may not agree as to the appropriate resource mix, which may lead to costs incurred to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our financial condition, operating results and liquidity, making the operation of some of our facilities no longer economically viable.
Legislation, regulation, litigation or other actions related to climate change and greenhouse gas emissions could materially impact us.
Current and future federal, state, regional and international regulations to address global climate change and reduce GHG emissions, including measures such as mandated levels of renewable generation, mandatory reductions in CO2 emission levels, taxes on CO2 emissions, or cap-and-trade regimes, could require us to incur significant costs which could negatively impact our financial condition, operating results and liquidity if such costs cannot be recovered through rates granted by rate-making authorities or through increased market prices for electricity.
In 2021, the Biden Administration introduced new targets aimed at reducing economy-wide net GHG emissions by 50% to 52% from 2005 levels by 2030. In addition, the Administration set a goal to reach 100% carbon pollution-free electricity by 2035. As a part of achieving these targets, the EPA proposed new regulations in May 2023 under Section 111 of the Clean Air Act to regulate GHG emissions from existing and new fossil fuel-based EGUs. As detailed above, this proposal would require states to implement stringent emissions standards for most coal-fired steam generating units and certain larger natural gas combustion plants. Until the EPA takes final action on this rulemaking, we are unable to evaluate the precise impacts; however, the 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. The EPA may implement additional new regulations targeting power plants to
support its aforementioned economy-wide GHG reduction goals, which could impose substantial costs on and impact the operations of our utility business, which may materially impact our financial condition, operating results and liquidity.
In addition to complying with legislation and regulation, we could be subject to litigation related to climate change. In recent years, there has been an increase in litigation against electric utilities and fossil fuel producers. If OTP were subjected to such litigation, the costs of such litigation could be significant and an adverse outcome could require substantial capital expenditures, changes in operations and possible payment of penalties or damages which could affect our financial condition, operating results and liquidity if the costs are not recoverable in rates or covered by insurance.
Violations of extensive legal and regulatory compliance requirements could have a negative impact on our business and results of operations.
We are subject to an extensive legal and regulatory framework imposed under federal and state laws and regulatory agencies, including the FERC and the North American Electric Reliability Corporation (NERC). We could be subject to potential financial penalties for compliance violations. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. If a serious reliability incident were to occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance. We attempt to mitigate the risk of regulatory penalties through formal training. However, there is no guarantee our compliance program will be sufficient to ensure against violations.
In addition, energy policy initiatives at the state or federal level could increase incentives for distributed generation, or authorize municipal utility formation or acquisition of service territory, or local initiatives could introduce generation or distribution requirements that could change the current integrated utility model.
These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary approvals for our existing operations and that our business is conducted in accordance with applicable laws and regulatory requirements; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our financial condition, operating results and liquidity.
Our transmission and generation facilities could be vulnerable to cyber and physical attack.
OTP owns electric transmission and generation facilities subject to mandatory and enforceable standards advanced by the NERC. These bulk electric system facilities provide the framework for the electrical infrastructure of OTP’s service territory and interconnected systems, the operation of which is dependent on information technology systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber-attack.
In addition, OTP’s generation and transmission facilities are spread throughout a large service territory. These facilities could be subject to physical attack or vandalism that could disrupt OTP’s operations or conceivably the regional or U.S. bulk power system.
OTP is subject to mandatory cybersecurity and physical security regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and remains abreast of best practices within the business and the utility industry to protect its computers and computer-controlled systems from outside attack. We rely on industry-accepted security measures and technology to securely maintain confidential and proprietary information necessary for the operation of our systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls and disaster recovery plans designed to protect and preserve the confidentiality, integrity and availability of data and systems. We also take prudent and reasonable steps to protect the physical security of our generation and transmission facilities. However, all these measures and technology may not adequately prevent security breaches, ransomware attacks or other cyber-attacks, or enable us to recover effectively from such a breach or attack. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches or physical attack of our generation or transmission facilities could adversely affect our business and our financial condition, operating results and liquidity.
Our generation, transmission, and distribution facilities are subject to operational risks which include circumstances that could result in injuries, loss of life, property damage, and fires.
The operation of our generation, transmission, and distribution facilities involves many risks including equipment failures, accidents and workforce safety matters, environmental damage, property damage, operator error, and the occurrence of catastrophic events such as fires, explosions and floods. Diminished availability or performance of those facilities could result in facility shutdowns, reduced customer satisfaction, reputational harm, and regulatory inquiries and fines.
Accidents, fires, explosions, catastrophic failures, general system damage or dysfunction, intentional acts of destruction, and other unplanned events related to our infrastructure would increase repair costs and may expose us to liability for personal injury, loss of life, and property damage. Fires alleged to have been caused by our transmission, distribution, or generation infrastructure, or that allegedly result from our contractors’ operating or maintenance practices, could also expose us to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage, and environmental pollution, whether based on claims of negligence, trespass, or otherwise. We maintain insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover our ultimate liability. We may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms. If the amount of insurance is insufficient or otherwise unavailable, and if we are unable to fully recover in rates the costs of uninsured losses, our financial condition, operating results and liquidity could be materially affected.
We are subject to risks associated with the procurement and transportation of fuel to our coal and natural gas powered generation facilities.
We rely on a limited number of suppliers to provide coal and a limited number of service providers to transport coal and natural gas to our facilities. A counterparty's failure to perform their obligations may arise due to liquidity challenges or insolvency, operational deficiencies or other circumstances such as severe weather or natural disasters, which could impact our ability to provide service to our customers or require us to seek alternative sources for these products and services, if available. A prolonged failure to perform by one or more of our current suppliers or service providers could lead to increased costs or other consequences which could negatively impact our financial condition, operating results and liquidity.
We are subject to risks associated with energy markets.
Our electric business is subject to the risks associated with energy markets, including market supply and changing energy prices. If we are faced with shortages in market supply, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously anticipated costs. This could force us to obtain alternative energy or fuel supplies at higher costs, or suffer increased liabilities for unfulfilled contractual obligations. Any significantly higher than expected energy or fuel costs could negatively affect our financial condition, operating results and liquidity.
MANUFACTURING SEGMENT RISKS
The price and availability of raw materials could adversely impact our operating results.
The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture including, among others, steel, aluminum, and polystyrene and other plastics resins. The price and availability of the raw materials used in our manufacturing processes are based on global supply and demand conditions, which can create volatile pricing and supply disruptions as conditions change. Federal trade policies, including imposed tariffs, can also impact prices for these raw materials. If we are unable to pass cost increases through to our customers or are unable to procure adequate or timely raw material inputs for use in our manufacturing processes, our financial condition, operating results and liquidity could be negatively impacted.
Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes used by our manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our manufacturing companies as it reduces their ability to mitigate the cost associated with excess material.
Competition from domestic and foreign manufacturers could affect the revenues and earnings of our manufacturing businesses.
Our manufacturing businesses are subject to intense competition from domestic and foreign manufacturers, many of whom have broader product lines, greater distribution capabilities, greater capital resources, larger marketing, research and development personnel and facilities, and other capabilities. Our ability to compete on product performance, competitive pricing, technological innovation and customer service is critical to our ongoing success. If we are unable to compete in these and potentially other areas, our business and financial condition, operating results and liquidity could be adversely impacted.
Economic conditions in the end markets in which our customers operate could have an adverse impact on our operating results and liquidity.
Our manufacturing businesses derive a large amount of their revenues from customers in the following industry sectors: recreational vehicle/powersports, lawn and garden, construction, agriculture, energy and horticulture. Factors affecting any of these industries in general could adversely affect our operating results as growth in our operating revenues is largely dependent on the growth of our customers’ businesses in their respective industries. These factors include:
•seasonality of demand for our customers’ products which may cause our manufacturing capacity to be underutilized for periods of time;
•our customers’ failure to successfully market their products, gain or retain widespread commercial acceptance of their products or compete effectively in their industries;
•loss of market share for our customers’ products which may lead our customers to reduce or discontinue purchasing our products and components and to reduce prices, thereby exerting pricing pressure on us;
•economic conditions in the markets in which our customers operate, the United States in particular, including recessionary periods such as a global economic downturn;
•our customers’ decisions to bring the production of components in-house that have traditionally been outsourced to us; and
•product design changes or manufacturing process changes that may reduce or eliminate demand for the components we supply.
We expect future sales will continue to depend on the success of our customers. If economic conditions or demand for our customers’ products deteriorates, we may experience a material adverse effect on our financial condition, operating results and liquidity.
Our business may be adversely affected if we are not able to maintain our manufacturing, engineering and technological expertise.
The markets for our manufacturing businesses are characterized by changing technology and evolving process development. The continued success of our businesses will depend on our ability to:
•maintain technological leadership in our industry;
•implement new and expand on current robotics, automation and tooling technologies; and
•anticipate or respond to changes in manufacturing processes in a cost-effective and timely manner.
We may be unable to develop the capabilities required by our customers in the future. The emergence of new technologies, industry standards or customer requirements may render our equipment, inventory or processes obsolete or noncompetitive. We may be required to acquire new technologies and equipment to remain competitive. The acquisition and implementation of new technologies and equipment may require us to incur significant expense and capital investment, which could reduce our margins and affect our operating results. When we establish or acquire new facilities, we may not be able to maintain or develop our manufacturing, engineering and technological expertise due to a lack of trained
personnel, ineffective training of new staff or technical difficulties with machinery. Failure to anticipate and adapt to customers’ changing technological needs and requirements and to maintain manufacturing, engineering and technological expertise may have material adverse effects on our financial condition, operating results and liquidity.
PLASTICS SEGMENT RISKS
External factors beyond our control could cause fluctuations in demand for our PVC pipe products and changes in our prices and margins, which could adversely impact our operating results.
Our PVC pipe products, sold through distributors and wholesalers, are primarily used in municipal and rural water projects, wastewater projects, storm drainage systems and reclamation systems. External factors beyond our control can cause volatility in demand for our products and sales prices impacting our operating margins. These factors can magnify the impact of economic cycles on our business and results of operations. Examples of external factors include:
•general economic conditions including housing and construction markets which can be cyclical;
•increases in interest rates;
•severe weather and natural disasters;
•governmental regulation in the United States; and
•funding shortages for municipal water and wastewater projects.
Extraordinary industry supply and demand dynamics beginning in 2021 and continuing through 2023 led to a rapid and significant increase in sales prices for PVC pipe and led to a significant expansion in our operating margins. As industry conditions normalize, sales prices for PVC pipe are expected to moderate from current levels resulting in decreased operating margins prospectively. The pace and magnitude of the decline in product pricing could materially impact our operating results.
Changes in PVC resin prices could negatively affect our plastics business.
The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices were rising or stable, margins and sales volumes were higher and when resin prices were falling, sales volumes and margins were lower. Changes in PVC resin prices can negatively affect PVC pipe prices, profit margins on PVC pipe sales and the value of our finished goods inventory.
Our plastics operations are highly dependent on a limited number of vendors and a limited supply of PVC resin and other materials.
We rely on a limited number of vendors to supply the PVC resin used in our plastics businesses. In 2023, we sourced all of our PVC resin needs from three vendors. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. Most U.S. resin production plants are located in the Gulf Coast region. This could increase the risk of a shortage of resin in the event of a hurricane, other extreme weather events and other natural disasters in that region. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources were available.
Although PVC resin is the most significant raw material input in our PVC pipe manufacturing process, we also use certain other materials, such as stabilizers, gaskets, lumber, banding and others in the process of manufacturing and shipping our PVC pipe products. We generally source these materials from a limited number of suppliers and any significant supply chain constraints or disruptions related to these materials could also disrupt our ability to manufacture or ship products and could result in increased costs.
We compete against many other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish our products from those of our competitors.
The plastic pipe industry is fragmented and competitive due to the number of producers and the fungible nature of the product. We compete not only against other plastic pipe manufacturers, but also against ductile iron, steel and concrete pipe manufacturers. Due to shipping costs, competition is usually regional instead of national in scope and the principal areas of competition are a combination of price, service, warranty and product performance. Our inability to compete effectively in each of these areas and to distinguish our plastic pipe products from competing products may adversely affect the financial performance of our plastics businesses.
GENERAL RISK FACTORS
Economic conditions could negatively impact our businesses.
Our businesses are affected by local, national and worldwide economic conditions, including the impact of inflation, tightening of credit in financial markets, economic recessions or other changes in economic conditions. Our businesses may be adversely affected by decreases in the general level of economic activity, such as decreases in business and consumer spending. A decline in the level of economic activity and uncertainty regarding energy and commodity prices could adversely affect our results of operations and our future growth. Inflationary pressures may lead to rising material and commodity costs and increased labor costs. Our operating results and liquidity would be adversely impacted if we were unable to recover these increased costs from our customers. Tightening of credit in financial markets could adversely affect the ability of customers to finance purchases of our goods and services, resulting in decreased orders, cancelled or deferred orders, slower payment cycles, and increased bad debt and customer bankruptcies.
If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.
We expect much of our growth in the next few years will come from major capital investments at existing companies. To achieve the organic growth we expect, we must have access to the capital markets, be successful with capital expansion programs related to organic growth, develop new products and services, expand our markets and increase efficiencies in our businesses. Competitive and economic factors could adversely
affect our ability to do this. If we are unable to achieve and sustain consistent organic growth, we will be less likely to meet our earnings growth targets, which may adversely affect the market price of our common shares.
The effects of a major public health crisis, such as an epidemic or pandemic, and measures taken to reduce and slow the spread of the disease could adversely impact our business.
A future widespread outbreak of an infectious disease, which affects a large percentage of the population regionally, nationally, or globally could impact our business operations, including our employees, customers, construction contractors, suppliers and vendors, and could impact our operating results, financial condition and liquidity.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
The following provides a summary of our properties which are material to our operations, by segment, as of December 31, 2023.
ELECTRIC SEGMENT
The following reflects our wholly or jointly owned material electric generation facilities as of December 31, 2023:
Description Location Year
Placed in Service Fuel Type Capacity - kW
(Nameplate Rating)
Big Stone Plant(1)
Big Stone City, SD 1975 Subbituminous Coal 223,146
Coyote Station(2)
Beulah, ND 1981 Lignite Coal 144,900
Jamestown Combustion Turbines
Jamestown, ND 1975 Fuel Oil 48,108
Lake Preston Combustion Turbine Lake Preston, SD 1978 Fuel Oil 24,100
Solway Combustion Turbine Solway, MN 2003 Natural Gas/Fuel Oil 44,500
Astoria Station Astoria, SD 2021 Natural Gas 245,000
Langdon Wind Energy Center
Cavalier County, ND 2007 Wind 40,500
Ashtabula Wind Energy Center
Barnes County, ND 2008 Wind 48,000
Luverne Wind Energy Center
Griggs and Steele Counties, ND 2009 Wind 49,500
Merricourt Wind Energy Center McIntosh and Dickey Counties, ND
2020 Wind 150,000
Ashtabula III Wind Energy Center
Barnes County, ND
2023(3)
Wind
62,400
Hoot Lake Solar
Otter Tail County, MN
2023 Solar
49,900
(1) OTP holds a 53.9% joint ownership interest in this jointly owned facility. The nameplate capacity indicated reflects OTP's ownership percentage.
(2) OTP holds a 35.0% joint ownership interest in this jointly owned facility. The nameplate capacity indicated reflects OTP's ownership percentage.
(3) Originally placed in service in 2010 and owned by an unrelated third party. OTP acquired this facility in 2023.
In addition to our generation facilities, we wholly or jointly own transmission and distribution lines as of December 31, 2023 as follows:
Miles
Transmission
345 kV(3)
230 kV(4)
115 kV 961
Less than 115 kV 4,005
Distribution
Less than 115 kV 7,998
(3) As of December 31, 2023, OTP held a 14.2% ownership interest of 242 miles, a 4.8% ownership interest of 250 miles, and a 50.0% ownership interest of 234 miles of the 345 kV transmission lines, with the remaining miles being wholly owned.
(4) As of December 31, 2023, OTP held a 14.8% ownership interest of 70 miles of the 230 kV transmission lines, with the remaining miles being wholly owned.
MANUFACTURING AND PLASTICS SEGMENTS
The following reflects the material properties of our Manufacturing and Plastic segments as of December 31, 2023:
Segment/Location Owned/Leased Facility Type/Use Approximate
Square Feet
Manufacturing Segment
Washington, IL Leased Office/Manufacturing/Warehouse 217,508
Detroit Lakes, MN Owned Office/Manufacturing/Warehouse 353,812
Lakeville, MN Leased Office/Manufacturing/Warehouse 413,000
Dawsonville, GA Owned Office/Manufacturing/Warehouse 172,000
Buford, GA Leased Warehouse 71,357
Clearwater, MN Owned Office/Manufacturing/Warehouse 203,840
Otsego, MN Leased Manufacturing/Warehouse 86,400
Plastics Segment
Fargo, ND Owned Office/Manufacturing/Warehouse 122,441
Phoenix, AZ Owned Office/Manufacturing/Warehouse 87,336
We are currently undertaking an expansion project at our Georgia location which will add approximately 162,000 square feet of manufacturing and warehouse space, and will replace the warehouse facility that is currently being leased. We anticipate the project will be completed in 2025. We are also undertaking an expansion project at our Arizona location which will add approximately 65,000 square feet of manufacturing, warehouse, and office space. We anticipate the project will be completed in 2024.
We believe the facilities described above, along with the planned expansions, are adequate for our present business.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We are the subject of various legal and regulatory proceedings in the ordinary course of our business. See Note 13, Commitments and Contingencies, to the consolidated financial statements, and Management's Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Matters, which information is incorporated herein by reference, for discussion of certain legal, environmental and other regulatory proceedings to which we are a party.
ITEM 3A. INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Set forth below is a summary of the principal occupations and business experience during the past five years of the executive officers as defined by rules of the SEC. Each of the executive officers has been employed by the Company for more than five years in an executive or management position either with the Company or its wholly owned subsidiary, Otter Tail Power Company.
Name and Age Date Elected to Office Current Position
Charles S. MacFarlane (59)
04/13/15 President and Chief Executive Officer
Todd R. Wahlund (53)
01/01/24 Vice President, Chief Financial Officer
Timothy J. Rogelstad (57)
04/14/14 Senior Vice President, Electric Platform
John S. Abbott (65)
02/11/15 Senior Vice President, Manufacturing Platform
Jennifer O. Smestad (53)
01/01/18 Vice President, General Counsel and Corporate Secretary
Chuck MacFarlane has served as the Company’s President and Chief Executive Officer and as a member of the Company’s Board of Directors since April 13, 2015.
Todd Wahlund was appointed to succeed Kevin Moug, Chief Financial Officer and Senior Vice President, subsequent to Mr. Moug's retirement on December 31, 2023. Mr. Wahlund has served as Chief Financial Officer and Vice President since January 1, 2024, and previously served as Chief Financial Officer and Vice President, Finance for OTP from May 1, 2018 to December 31, 2023.
Timothy Rogelstad has served as President of OTP and Senior Vice President, Electric Platform of the Company since April 14, 2014.
John Abbott has served as Senior Vice President, Manufacturing Platform, since February 11, 2015.
Jennifer Smestad has served as Vice President, General Counsel and Corporate Secretary of the Company, since January 1, 2018. Ms. Smestad has also served as General Counsel for OTP since March 1, 2013.
The term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the board of directors at any time during the term. There are no family relationships between any of the executive officers or directors.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the Nasdaq Global Select Market under the Nasdaq symbol “OTTR”. As of December 31, 2023, there were 10,650 holders of record of our common stock.
We do not have a publicly announced stock repurchase program and we did not repurchase any equity securities during the quarter ended December 31, 2023.
PERFORMANCE GRAPH COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
This graph compares the cumulative total shareholder return on our common shares for the last five years with the cumulative return of the Nasdaq Stock Market Index and the Edison Electric Institute (EEI) Index over the same period (assuming the investment of $100 in each vehicle on December 31, 2018, and reinvestment of all dividends).
2018 2019 2020 2021 2022 2023
OTTR $ 100.00 $ 105.64 $ 90.88 $ 156.27 $ 133.22 $ 197.24
EEI $ 100.00 $ 125.79 $ 124.33 $ 145.61 $ 147.29 $ 134.47
Nasdaq $ 100.00 $ 131.17 $ 159.07 $ 200.26 $ 160.75 $ 203.23

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
OVERVIEW
Otter Tail Corporation and its subsidiaries form a diverse group of businesses with operations classified into three segments: Electric, Manufacturing and Plastics. Our Electric business is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve our customers in western Minnesota, eastern North Dakota and northeastern South Dakota. Our Manufacturing segment provides metal fabrication for custom machine parts and metal components, and manufactures extruded and thermoformed plastic products. Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater and water reclamation projects.
Our strategy includes investing in rate base growth opportunities in our Electric segment and capitalizing on organic growth opportunities in our Manufacturing and Plastics segments. Investments in our Electric segment are expected to produce increased earnings and cash flows, lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund our dividend. Our Electric segment is complemented by our Manufacturing and Plastics segment businesses, which we expect to contribute to earnings growth by capitalizing
on market expansion opportunities and increasing utilization of existing capacities, along with planned investments to create additional capacity and increased efficiencies. Collectively, our mix of businesses is expected to contribute to the achievement of our long-term targeted annual growth in earnings per share of 5 - 7%.
2023 FINANCIAL RESULTS
In 2023, our diversified business model generated record financial results, producing net income of $294.2 million, or $7.00 per diluted share, an increase of 4% from $284.2 million, or $6.78 per diluted share, in 2022. Our financial results for the year were driven by earnings growth in our Electric and Manufacturing segments, as well as lower corporate costs, as we benefited from returns on our short-term investments funded by the significant cash flows our businesses have generated over the last three years. Our Plastics segment again produced extraordinary financial results as we continued to capitalize on favorable industry dynamics; however, earnings in this segment did decline modestly from the record level achieved in 2022. In 2023, we paid an annual dividend of $1.75 per share, or $73.1 million, completing our 85th consecutive year of dividend payments to our shareholders.
Our Electric segment produced earnings growth of 6% in 2023, from $80.0 million in 2022 to $84.4 million in 2023, primarily due to increased rider revenue, increased commercial and industrial sales, and lower pension and other postretirement benefit costs, partially offset by increased operating and maintenance expenses and the impact of unfavorable weather.
Our Manufacturing segment produced earnings growth of 2% in 2023, from $21.0 million in 2022 to $21.5 million in 2023, primarily due to increased sales volumes at our metal fabrication business driven by strong end market demand across several markets we serve, and incremental volumes from additional work with existing customers. Increased sales volumes at our metal fabrication business were partially offset by increased labor and overhead costs, as well as decreased horticulture product sales volumes at our plastic thermoforming business.
Our Plastics segment earnings declined 4%, from $195.4 million in 2022 to $187.7 million in 2023. We experienced an unprecedented level of earnings in 2022, resulting from extraordinary industry supply and demand dynamics. Industry dynamics have begun to moderate, but at a modest pace, as further described below. Our Plastics segment businesses continued to capitalize on these industry conditions in 2023, producing earnings significantly in excess of pre-2021 levels.
Our earnings mix in 2023 was 29% from our Electric segment and 71% from the combination of our Manufacturing and Plastics segments excluding unallocated corporate costs. Electric segment earnings as a percentage of our total earnings were less than our long-term target of 65% due to the unique market conditions occurring in the plastics industry.
PVC PIPE SUPPLY AND DEMAND CONDITIONS
Extraordinary supply and demand conditions in the PVC industry beginning in 2021 have led to a significant expansion in operating margins and elevated earnings in our Plastics segment over the past three years. Periodic disruptions in the supply of resin, the primary material input used in the manufacturing of PVC pipe, coupled with robust demand for resin, led to a significant increase in the cost of resin beginning in 2021. Low industry volumes of PVC pipe and robust end market demand for the product led to a rapid and significant increase in sales prices for PVC pipe, significantly outpacing the increase in resin input costs, leading to increased operating margins within our Plastics segment.
Demand for PVC pipe began to soften in the second half of 2022, as distributors and contractors reduced purchase volumes in response to uncertain and competitive market conditions. Softening demand continued through the first half of 2023, but sales volumes in the second half of the year exceeded those in the previous year. Resin prices have declined from the previous year and although sales prices for PVC pipe have also declined, they have declined at a slower pace than resin prices, continuing to produce expanded operating margins from those experienced in 2022.
The unique market dynamics impacting our Plastics segment resulted in a significant increase in earnings in the last three years compared to historical levels. We expect these market conditions to gradually normalize over the course of 2024 and into 2025. The marketplace dynamics impacting our Plastics segments are fluid and subject to change and may impact our operating results prospectively.
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.
Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
OTP generally bases its forecasted kwh sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast, and on period-to-period results.
Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency. In general, rate base consists of the value of property used by the utility in providing service. Rate base can also include cash, working capital, materials and supplies, construction work in progress, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and, in some cases, accumulated deferred ITCs. We present actual and forecasted levels of utility rate base to provide an indication of expected investments on which we expect to earn future returns.
RESULTS OF OPERATIONS
For a comparison of fiscal year 2022 to 2021, 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, 2022, filed with the SEC on February 15, 2023.
Provided below is a summary and discussion of our operating results on a consolidated basis followed by a discussion of the operating results of each of our segments, Electric, Manufacturing and Plastics. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment, but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated statements of income.
CONSOLIDATED RESULTS
The following table summarizes our consolidated results of operations for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022 $ change % change
Operating Revenues $ 1,349,166 $ 1,460,209 $ (111,043) (7.6) %
Operating Expenses 971,247 1,069,770 (98,523) (9.2)
Operating Income 377,919 390,439 (12,520) (3.2)
Interest Expense
(37,677) (36,016) (1,661) 4.6
Nonservice Components of Postretirement Benefits
10,597 1,075 9,522 n/m
Other Income 12,650 2,037 10,613 n/m
Income Before Income Taxes 363,489 357,535 5,954 1.7
Income Tax Expense 69,298 73,351 (4,053) (5.5)
Net Income $ 294,191 $ 284,184 $ 10,007 3.5 %
Operating Revenues decreased $111.0 million on a consolidated basis in 2023. Electric segment operating revenues decreased 4% primarily due to decreased fuel recovery and wholesale revenues and the impact of unfavorable weather, partially offset by increased rider revenues and increased commercial and industrial sales. Manufacturing segment operating revenues increased 1% primarily due to higher sales volumes in our metal fabrication business. Plastics segment operating revenues decreased 18% due to a combination of decreased sales volumes and sales prices. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses decreased $98.5 million in 2023. Electric segment operating expenses decreased primarily due to decreased purchased power costs resulting from lower market energy prices and lower fuel costs due to decreased natural gas prices. Operating expenses in our Manufacturing segment increased primarily due to increased sales volumes in our metal fabrication business and an increase in certain variable compensation costs. Operating expenses in our Plastics segment decreased primarily due to lower sales volumes and decreased PVC resin costs. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Expense increased $1.7 million in 2023 due to an increase in our average short-term borrowings, primarily used to fund capital investments in our Electric segment, and increased interest rates on our short-term borrowings.
Nonservice Components of Postretirement Benefits improved by $9.5 million in 2023, having a positive impact on net income, primarily due to a change in actuarial assumptions used to measure our pension benefit and postretirement benefit obligations, including an increase in the discount rate applied and an increase in the expected return on assets assumption.
Other Income increased $10.6 million in 2023 primarily due to an increase in investment income earned on our short-term cash equivalent investments and investment gains from our corporate-owned life insurance policies compared to investment losses in the previous year.
Income Tax Expense decreased $4.1 million in 2023 primarily due to an increase in PTCs produced by our wind and solar generation assets. Our effective tax rate was 19.1% in 2023 and 20.5% in 2022. See Note 12 to our consolidated financial statements included in this report on Form 10-K for additional information regarding factors impacting our effective tax rate.
ELECTRIC SEGMENT RESULTS
The following table summarizes the operating results of our Electric segment for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022 $ change % change
Retail Sales Revenue $ 455,840 $ 470,300 $ (14,460) (3.1) %
Transmission Services Revenues 52,555 52,213 342 0.7
Wholesale Revenues 12,459 18,539 (6,080) (32.8)
Other Electric Revenues 7,505 8,647 (1,142) (13.2)
Total Operating Revenue 528,359 549,699 (21,340) (3.9)
Production Fuel 60,339 65,110 (4,771) (7.3)
Purchased Power 78,292 100,281 (21,989) (21.9)
Operating and Maintenance Expenses 191,263 181,378 9,885 5.4
Depreciation and Amortization 75,330 72,050 3,280 4.6
Property Taxes 16,614 17,742 (1,128) (6.4)
Operating Income $ 106,521 $ 113,138 $ (6,617) (5.8) %
Electric kwh Sales (in thousands)
Retail kwh Sales 5,772,215 5,592,368 179,847 3.2 %
Wholesale kwh Sales 351,729 267,184 84,545 31.6
Heating Degree Days 6,259 7,122 (863) (12.1)
Cooling Degree Days 590 531 59 11.1
Our Electric segment operating results are impacted by fluctuations in weather conditions and the resulting demand for electricity for heating and cooling. The following table presents heating and cooling degree days as a percent of normal for the years ended December 31, 2023 and 2022:
2023 2022
Heating Degree Days 98.4 % 112.5 %
Cooling Degree Days 127.2 % 113.5 %
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail sales under actual weather conditions and expected retail sales under normal weather conditions for the years ended December 31, 2023 and 2022, and between years:
2023 vs Normal 2023 vs 2022 2022 vs Normal
Effect on Diluted Earnings Per Share $ 0.02 $ (0.09) $ 0.11
Retail Revenues decreased $14.5 million primarily due to the following:
•A $26.2 million decrease in fuel recovery revenues, primarily due to lower purchased power and fuel costs arising from decreased market energy costs and natural gas prices, as described below.
•A $5.2 million decrease in revenues from the unfavorable impact of weather compared to last year.
•Our Minnesota rate case, which was finalized in 2022, included a determination of the final interim rate refund and resulted in an additional $4.1 million of retail revenue last year.
The decreases in retail revenues described above were partially offset by the following:
• A $10.5 million increase in retail revenues from increased sales volumes from commercial and industrial customers, including the impact of a new commercial customer load in North Dakota added during 2022.
• A $9.6 million increase in rider revenues, including recovery of our investment in the Ashtabula III wind farm, which we acquired in January 2023, and the recovery of our investment in Hoot Lake Solar, which was completed during the year, as well as operating costs associated with these facilities.
Wholesale Revenues decreased $6.1 million primarily due to a 49% decrease in wholesale electric prices driven by decreased fuel costs.
Production Fuel costs decreased $4.8 million due to a 17% decrease in fuel cost per kwh resulting from decreases in natural gas prices, partially offset by an increase in kwhs generated from our natural gas-burning plants.
Purchased Power costs to serve retail customers decreased $22.0 million due to a 14% decrease in the price of purchased power per kwh, primarily due to decreased market energy costs, as well as decreased purchase volumes due to the acquisition of the Ashtabula III wind farm and completion of our Hoot Lake Solar project in the current year. Prior to the acquisition of Ashtabula III, OTP purchased the wind generated electricity from the facility under the terms of a power purchase agreement.
Operating and Maintenance Expense increased $9.9 million primarily due to:
•A $3.9 million increase in labor and benefit costs partially due to increased health insurance costs, wage increases, and increased headcount.
•A $2.2 million increase in vegetative maintenance costs.
•A $1.9 million increase in insurance expense due in part to the addition of Ashtabula III and Hoot Lake Solar to our generation fleet during the year.
•A $1.3 million increase in maintenance related to the addition and operation of Ashtabula III.
These expense increases were partially offset by, among other items, decreased outage-related costs and travel costs compared to the previous year.
Depreciation and Amortization expense increased $3.3 million primarily due to the acquisition of Ashtabula III and continued investment in distribution facilities during the year.
MANUFACTURING SEGMENT RESULTS
The following table summarizes the operating results of our Manufacturing segment for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022 $ change % change
Operating Revenues $ 402,781 $ 397,983 $ 4,798 1.2 %
Cost of Products Sold (excluding depreciation)
310,601 315,375 (4,774) (1.5)
Selling, General, and Administrative Expenses
44,545 37,341 7,204 19.3
Depreciation and Amortization 18,495 16,202 2,293 14.2
Operating Income $ 29,140 $ 29,065 $ 75 0.3 %
Operating Revenues increased $4.8 million primarily due to the combination of the following:
•At BTD, operating revenues increased $12.5 million primarily due to a combination of higher sales volumes and increased pricing. Sales volumes increased 12% compared to the previous year due to strong end market demand in several segments, including the construction, industrial, and agricultural segments, and incremental volumes from additional work with existing customers. Sales price increases were implemented during the year in response to labor and non-steel material cost inflation. Sales price increases and sales volume growth were partially offset by decreased steel prices, resulting in an 11% decrease in material costs, which are passed through to customers.
•At T.O. Plastics, operating revenues decreased $7.7 million primarily due to lower sales volumes. Sales volumes decreased 19% primarily due to decreased sales of horticulture products, as order and delivery lead times for these products have normalized after volatility experienced in the previous year, and customers reduced their inventory levels and are beginning to return to normal seasonal buying patterns.
Cost of Products Sold decreased $4.8 million primarily due to the combination of the following:
•Cost of products sold at BTD increased $0.8 million primarily due to higher sales volumes, as discussed above. Cost of products sold also increased due to lower productivity and inflationary cost pressures which resulted in higher non-steel material, labor and overhead costs. The increase in labor costs and lower level of productivity was partially attributable to increased shift incentives and overtime wages combined with increased staffing levels to meet higher production volumes and the time required for new employees to achieve peak productivity. The impacts of higher sales volumes and increased labor and overhead costs were largely offset by decreased material costs, as discussed above.
•Cost of products sold at T.O. Plastics decreased $5.6 million primarily due to lower sales volumes of horticulture products, as discussed above.
Selling, General, and Administrative Expenses increased $7.2 million primarily due to increased employee compensation from an increase in headcount, inflationary cost pressure and variable compensation driven by current year financial performance.
Depreciation and Amortization increased $2.3 million due to capital expenditures during the year, which included investments in facility improvements and purchases of equipment.
PLASTICS SEGMENT RESULTS
The following table summarizes the operating results for our Plastics segment for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022 $ change % change
Operating Revenues $ 418,026 $ 512,527 $ (94,501) (18.4) %
Cost of Products Sold (excluding depreciation)
143,521 227,569 (84,048) (36.9)
Selling, General, and Administrative Expenses
16,076 16,175 (99) (0.6)
Depreciation and Amortization 4,027 4,205 (178) (4.2)
Operating Income $ 254,402 $ 264,578 $ (10,176) (3.8) %
Operating Revenues decreased $94.5 million primarily due to a 14% decrease in sales volumes. Sales volume decreases were attributable to softer end market demand coupled with distributor inventory management, as these customers reduced their inventory levels during the first half of the year after previously building higher inventory levels in response to market uncertainty and supply chain challenges. Operating revenue decreases were also the result of a 5% decrease in sales prices, as prices in 2023 decreased from record highs in 2022.
Cost of Products Sold decreased $84.0 million due to a 26% decrease in the cost per pound of PVC pipe sold, primarily due to lower resin costs, as well as the 14% decrease in sales volumes discussed above.
CORPORATE
The following table summarizes Corporate results of operations for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022 $ change % change
Selling, General, and Administrative Expenses
$ 12,042 $ 16,202 $ (4,160) (25.7) %
Depreciation and Amortization 102 140 (38) (27.1)
Operating Loss $ 12,144 $ 16,342 $ (4,198) (25.7) %
Selling, General, and Administrative Expenses decreased $4.2 million primarily due to lower health care costs related to our self-funded health insurance program in 2023 compared to higher claim costs in 2022.
REGULATORY MATTERS
The following provides a summary of OTP's current and recent rate case filings, rate rider filings, and other regulatory filings that have or are expected to have a material impact on our operating results, financial position, or cash flows.
RATE CASES
The following includes a summary of electric rate cases as determined in OTP's most recent general rate case in each state:
Revenue Allowed
Implementation Requirement Return on Return Equity
Jurisdiction Date (in millions) Rate Base on Equity Ratio
Minnesota 07/01/22 $ 209.0 7.18 % 9.48 % 52.50 %
North Dakota 02/01/19 153.1 7.64 9.77 52.50
South Dakota(1)
08/01/19 35.5 7.09 8.75 52.92
(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 50% of any weather-normalized revenue creating annual earnings in excess of the authorized ROE up to a maximum of 9.50% be returned to customers and 100% returns of revenue creating annual earnings above 9.50%.
North Dakota Rate Case: On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of return on equity of 10.6% on an equity ratio of 53.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost and investment recovery, with recovery moving from riders into base rates. The filing also includes a proposal to implement a sales adjustment mechanism to address potential significant load additions or losses. The filing included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023, and interim rates went into effect on January 1, 2024. These interim rate revenues, when collected, are subject to potential refund until the finalization of the rate case.
RATE RIDERS
The following table includes a summary of substantial pending and recently concluded rate rider proceedings:
Recovery Filing Amount Effective
Mechanism Jurisdiction Status Date (in millions) Date Notes
RRR - 2023
MN Approved
11/01/22 $17.5 07/01/23 Recovery of Hoot Lake Solar costs, Ashtabula III costs, and true up for PTCs from Merricourt.
ECO - 2023
MN Approved 04/03/23 9.7 10/01/23 Recovery of energy conservation improvement costs as well as a demand side management financial incentive.
RRR - 2024
MN
Requested
12/04/23 8.0 07/01/24 Recovery of Hoot Lake Solar costs, Ashtabula III costs, wind upgrade project costs at our four owned wind facilities, and true up of PTCs for Merricourt.
RRR - 2023 ND Approved 12/30/22 12.2 05/01/23 Recovery of Merricourt, Ashtabula III and other costs.
RRR - 2022 ND Approved 01/05/22 7.8 04/01/22 Recovery of Merricourt costs, Ashtabula III costs, and deferred taxes and PTCs.
TCR - 2023
ND Approved 09/15/22 7.5 01/01/23 Recovery of transmission project costs.
TCR - 2024 ND Approved
11/02/23 4.5 01/01/24 Recovery of transmission project costs.
GCR - 2022 ND Approved 03/01/22 3.3 07/01/22 Annual update to generation cost recovery rider.
MDT - 2023
ND Approved 07/08/22 3.1 01/01/23 Recovery of advanced metering infrastructure, outage management system and demand response projects.
PIR - 2022 SD Approved 06/01/22 3.0 09/01/22 Recovery of Ashtabula III, Merricourt, Astoria Station, Advanced Grid Infrastructure project costs, and impact of load growth credits.
TCR - 2023
SD Approved
11/01/22 3.0 03/01/23 Recovery of transmission project costs.
RESOURCE PLANNING
On March 31, 2023, OTP submitted a supplemental resource plan filing to the MPUC, the NDPSC, and the South Dakota Public Utilities Commission (SDPUC). The supplemental filing updated OTP’s original 2022 Integrated Resource Plan (2022 IRP), which was filed on September 1, 2021. In the supplemental filing, OTP outlined its updated plan for meeting all customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates in light of several changes that had occurred since the original filing, including significant winter and spring reserve planning margins adopted by MISO, tax credits made available for renewable energy projects under the Inflation Reduction Act, the enactment of the Clean Energy Bill in Minnesota, and volatility experienced in energy and capacity markets.
On December 15, 2023, OTP submitted a second supplemental resource plan filing to the MPUC outlining an updated plan specifically for meeting Minnesota customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates. Based on feedback received on the preferred plan outlined in the March 31, 2023 supplemental filing and the inability to reach a consensus on certain aspects of the plan, the second supplemental filing includes a proposal to bifurcate OTP's resource planning by jurisdiction.
Under bifurcated resource planning, it is anticipated that OTP would develop two separate resource plans, one plan developed for Minnesota and a second developed for North Dakota and South Dakota. Each plan would be developed incorporating the assumption that all existing generation resources, except Hoot Lake Solar, would continue to be allocated to all jurisdictions using established jurisdictional allocators. Hoot Lake Solar is currently directly allocated to only Minnesota. As new generation resources are needed for each plan, those generation resources would be allocated to the jurisdiction that is needing the resource. To the extent a common generation resource is needed for both plans, that resource would be allocated using established jurisdictional allocators. This method of resource planning would diverge from OTP’s historical practice of planning on an integrated basis for all jurisdictions served.
With the proposal of bifurcated resource planning, the supplemental filing outlines OTP’s preferred plan for Minnesota only. The preferred plan in this supplemental filing includes:
•repowering four of our existing wind facilities in 2025;
•the addition of approximately 200 megawatts of solar generation in 2025;
•the addition of approximately 100 megawatts of wind generation in 2026;
•the addition of on-site liquefied natural gas fuel storage at our Astoria Station natural gas plant in 2027;
•the designation of Coyote Station, a jointly owned coal-fired generation plant, as an Available Maximum Emergency (AME) Resource beginning in 2029 and annually thereafter;
•a withdrawal from our 35 percent ownership interest in Coyote Station in the event we are required to make a major, non-routine capital investment in the plant; and
•the addition of approximately 50 megawatts of wind generation in 2032.
The preferred plan requests the MPUC issue an order requiring the Minnesota’s jurisdictionally allocated share of the generation from Coyote Station be designated as an AME Resource beginning March 1, 2029, subject to additional analysis to be performed by OTP. AME Resources are
resources called on only in the event of a maximum generation event, such as in the cases of extreme heat, cold, or other extreme events. Designating Coyote Station as an AME Resource would allow us to retain Coyote Station’s capacity, thereby providing an important reliability benefit. This also helps ensure we remain compliant with market monitoring regulations and our contractual obligations to the co-owners of Coyote Station while advancing our compliance with Minnesota's carbon-free standard. The supplemental filing requests Minnesota customer rates continue to include the recovery of an allocated share of OTP’s costs associated with owning the plant, and a return on those costs, as well as the fixed costs of operating the plant. The variable cost of operating the plant, which consists primarily of variable fuel costs, would not be attributed to Minnesota customers, except when the plant is called upon to serve Minnesota customers in emergency situations.
The supplemental IRP filing made December 15, 2023 outlines our proposed resource plan for Minnesota. We anticipate filing future resource plans on a bifurcated basis in North Dakota and South Dakota.
LIQUIDITY
LIQUIDITY OVERVIEW
We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets, and borrowing ability, because of investment-grade credit ratings, when taken together, provide us ample liquidity to conduct business operations and fund our capital expenditure program. Our liquidity, including our operating cash flows and access to capital markets, could be impacted by macroeconomic factors outside of our control. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of December 31, 2023, we were in compliance with all debt covenants (see the Financial Covenant section under Capital Resources below).
The following table presents the status of our lines of credit as of December 31, 2023 and 2022:
2023 2022
(in thousands) Line Limit Amount Outstanding Letters
of Credit Amount Available Amount Available
OTC Credit Agreement
$ 170,000 $ - $ - $ 170,000 $ 170,000
OTP Credit Agreement 170,000 81,422 9,132 79,446 152,223
Total $ 340,000 $ 81,422 $ 9,132 $ 249,446 $ 322,223
OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. Should additional liquidity be needed, the OTC Credit Agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.
As of December 31, 2023, we had $249.4 million of available liquidity under our credit facilities and $230.4 million of available cash and cash equivalents, resulting in total available liquidity of $479.8 million, compared to total available liquidity of $441.2 million as of December 31, 2022.
CASH FLOWS
The following is a discussion of our cash flows for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022
Net Cash Provided by Operating Activities $ 404,499 $ 389,309
Net Cash Provided by Operating Activities increased $15.2 million primarily due to an increase in net income, the absence of any pension contribution in 2023 due to the plan's funded status, and the timing of customer collections of forecasted fuel costs, partially offset by increased working capital. Working capital increased primarily due to an increase in receivables in our Plastics segment, due to increased sales volumes in the fourth quarter of the current year, and a decrease in payables due to the timing of capital investment spending in our Electric segment and inventory purchases in our Plastics segment compared to last year.
Unique market dynamics experienced by our Plastics segment businesses in 2023 and 2022 resulted in a significant increase in our overall cash from operations compared to prior periods, and we do not expect cash from operations at these levels to continue in future years.
(in thousands) 2023 2022
Net Cash Used in Investing Activities $ 289,287 $ 175,071
Net Cash Used in Investment Activities increased $114.2 million primarily due to a higher amount of Electric segment capital investment compared to last year, including the purchase of the Ashtabula III wind farm, investments in our Hoot Lake Solar facility and several wind repowering projects, transmission and distribution asset investments, and investments in new technology. Capital expenditures in our Manufacturing and Plastics segments increased $23.1 million as a result of investments in additional equipment and facility expansion projects at our Plastics segment facility in Arizona and our Manufacturing segment facility in Georgia.
(in thousands) 2023 2022
Net Cash Used in Financing Activities $ 3,835 $ 96,779
Net Cash Used in Financing Activities decreased $92.9 million primarily due to increased short-term borrowings on our OTP credit facility, which were primarily used to fund capital expenditures in our Electric segment, including the acquisition of the Ashtabula III wind farm. Our financing activities in 2023 included net short-term borrowings of $73.2 million compared to net short-term repayments of $83.0 million in 2022. There was no change in our long-term debt in 2023. In 2022, OTP issued $60.0 million of long-term debt, net of retirements, which was primarily used to fund the repayment of short-term credit facility borrowings and fund capital expenditures. In 2023, we made dividend payments of $73.1 million compared to $68.8 million in 2022.
CAPITAL REQUIREMENTS
CAPITAL EXPENDITURES
Our capital expenditure plan includes investments in electric generation facilities, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. Our capital expenditure plan is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our financial condition.
The following provides a summary of capital expenditures for the years ended December 31, 2023 and 2022 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2024 through 2028:
(in millions) 2022 2023 2024 2025 2026 2027 2028 Total
Electric Segment:
Renewables
$ 118 $ 93 $ 33 $ 113 $ 129 $ 486
Transmission
51 85 111 98 100 445
Distribution
38 39 36 38 39 190
Other 67 37 30 27 25 186
Total Electric Segment 148 241 274 254 210 276 293 1,307
Manufacturing and Plastics Segments 23 46 79 35 27 25 26 192
Total Capital Expenditures $ 171 $ 287 $ 353 $ 289 $ 237 $ 301 $ 319 $ 1,499
CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at December 31, 2023 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.
(in millions) Total Less than
1 Year 1-3
Years 3-5
Years More than
5 Years
Debt Obligations $ 908 $ 81 $ 80 $ 42 $ 705
Interest on Debt Obligations 602 35 70 62 435
Coal Contracts 485 24 49 52 360
Capacity and Energy Requirements 4 - - - 4
Postretirement Benefit Obligations 66 5 11 11 39
Other Purchase Obligations (including land easements) 79 6 9 5 59
Operating Lease Obligations 17 6 8 3 -
Total Contractual Cash Obligations $ 2,161 $ 157 $ 227 $ 175 $ 1,602
Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company (CCMC) under the Lignite Sales Agreement (LSA) that ends in 2040. Postretirement benefit obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan (ESSRP), but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make any contributions to that plan.
COMMON STOCK DIVIDENDS
We paid dividends to our shareholders totaling $73.1 million, or $1.75 per share, in 2023. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, level of earnings and cash flows from operations, our capital expenditure plan and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC subsidiaries to OTC. These intercompany distributions serve as the primary source of funding for dividends paid to our shareholders. See Note 14 to our consolidated financial statements included in this report on Form 10-K for additional information. The decision to declare a dividend is reviewed quarterly by our Board of Directors. On February 5, 2024, our Board of Directors increased the quarterly dividend from $0.4375 to $0.4675 per common share.
CAPITAL RESOURCES
Financial flexibility is provided by operating cash flows, borrowing capacity under our lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing. Debt financing will be required in the five-year period from 2024 through 2028 to refinance maturing debt and to finance our capital investments within our Electric segment. Our financing plans are subject to change and are impacted by our planned level of capital investments, a decision to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes.
REGISTRATION STATEMENTS
On May 3, 2021, we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement expires in May 2024, at which time we anticipate filing a new shelf registration statement. No shares were issued pursuant to the registration statement in 2023.
On May 3, 2021, we filed a second registration statement with the SEC for the issuance of up to 1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends or making optional cash investments. Shares purchased under the plan may be new issue common shares or common shares purchased on the open market. The registration statement expires in May 2024, at which time we plan to file a new registration statement. In 2023, we issued 105,663 shares under the plan. All shares issued under the plan to date have been open market purchases and there have been no new issue shares, resulting in no proceeds received by the Company. As of December 31, 2023, 1,145,330 shares remained available for purchase or issuance under the plan.
SHORT-TERM DEBT
The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit. The agreements generally bear interest at the Secured Overnight Financing Rate (SOFR) plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the issuer. The weighted-average interest rate on all outstanding borrowings as of December 31, 2023 and 2022 was 6.70% and 5.61%.
The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2023:
(in thousands, except interest rates) OTC Credit Agreement OTP Credit Agreement
Borrowing Limit $ 170,000 $ 170,000
Borrowing Limit if Accordion Exercised1
290,000 250,000
Amount Restricted Due to Outstanding Letters of Credit at Year-End - 9,132
Amount Outstanding at Year-End - 81,422
Average Amount Outstanding During Year - 50,883
Maximum Amount Outstanding During the Year - 87,788
Interest Rate at Year-End 6.85 % 6.70 %
Expiration Date October 29, 2027 October 29, 2027
1Each facility includes an accordion feature allowing the borrower to increase the borrowing limit if certain terms and conditions are met.
LONG-TERM DEBT
At December 31, 2023, we had $827.0 million of principal outstanding under long-term debt arrangements. Note 9 to our consolidated financial statements included in this report on Form 10-K includes information regarding these instruments. The agreements generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2026 to 2052.
Financial Covenants
Certain of our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2023, we were in compliance with these financial covenants as further described below:
OTC, under its financial covenants, may not permit its ratio of Interest-Bearing Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Indebtedness to exceed 10% of our Total Capitalization. As of December 31, 2023, our Interest-Bearing Debt to Total Capitalization was 0.39 to 1.00, our Interest and Dividend Coverage Ratio was 10.85 to 1.00 and we had no Priority Indebtedness outstanding.
OTP, under its financial covenants, may not permit its ratio of Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Debt to exceed 20% of its Total Capitalization. As of December 31, 2023, OTP's Interest-Bearing Debt to Total Capitalization was 0.46 to 1.00, its Interest and Dividend Coverage Ratio was 3.54 to 1.00 and it had no Priority Indebtedness outstanding.
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.
Credit Ratings
The credit ratings of OTC and OTP as of December 31, 2023 are summarized below:
Otter Tail Corporation Otter Tail Power Company
Moody's Fitch S&P Moody's Fitch S&P
Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB
BBB A3 BBB+
BBB+
Senior Unsecured Debt n/a BBB
n/a n/a A-
n/a
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. The following critical accounting policies affect the most significant judgments and estimates used in the preparation of our consolidated financial statements.
REGULATORY ACCOUNTING
Our utility business is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. Accordingly, our utility business must adhere to the accounting requirements of regulated operations, which requires the recognition of regulatory assets and regulatory liabilities for amounts that otherwise would impact the statement of income or comprehensive income when it is probable that such amounts will be collected from customers or credited to customers through the rate-making process. This guidance also provides recognition criteria for adjustments to rates outside of a general rate case proceeding which are provided to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. Regulatory assets generally represent costs that have been incurred but have been deferred because future recovery from customers, as established through the rate-making process, is probable. Regulatory liabilities generally represent amounts to be refunded to customers or amounts currently collected from customers for future costs.
We assess the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Our probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which we operate and the impact these incurred costs may have on our customers. Changes in our assessments regarding the likelihood of recovery or settlement of our regulatory assets and liabilities may have a material impact on our operating results and financial position. Further, if we determine that all or a portion of our utility business no longer meets the criteria for continued application of regulatory accounting, or our regulators disallow recovery of a previously incurred cost or eliminate a regulatory liability, we would be required to remove the associated regulatory assets and liabilities from our consolidated balance sheets and recognize those amounts in the consolidated statement of income as an expense or income item, or in the consolidated statement of comprehensive income as a loss or gain item, in the period in which this accounting treatment is no longer applicable.
As of December 31, 2023 and 2022, we had regulatory assets of $111.8 million and $119.7 million and regulatory liabilities of $302.0 million and $261.8 million. If future recovery of amounts recorded as regulatory assets was no longer probable we would be required to recognize an expense or loss in the period in which recovery was deemed to no longer be probable.
PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS
Pension and postretirement benefit liabilities and expenses are determined by actuaries using assumptions about the discount rate, expected return on plan assets, rate of compensation increase and healthcare cost-trend rates. See Note 10 to our consolidated financial statements included in this report on Form 10-K for additional information on our pension and postretirement benefit plans and related assumptions.
These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 30 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Likewise, compensation decreases and healthcare cost decreases or an increase in the discount rate applied from one year to the next can significantly decrease our benefit expenses in the year of the change. Also, a change in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well above or below assumed rates of return or a change in the anticipated life expectancy of plan participants could result in significant increases or decreases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.
We estimate the discount rate through the use of a hypothetical bond portfolio method, which incorporates yields on a collection of high credit quality bonds that produce cash flows similar to our anticipated future benefit payments.
We estimate the assumed long-term rate of return on plan assets based on asset category studies using historical market returns achieved by our asset portfolio allocation over long-term periods, as well as long-term projected return levels.
Pension plan assets are invested in a portfolio according to our return, liquidity and diversification objectives to provide a source of funding for plan obligations and manage contributions to the plan. The principal process for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.
At December 31, 2023, we set the discount rate used to measure our pension plan obligations at 5.57% and at 5.53% to measure postretirement healthcare obligations, a six and one basis point increase, respectively, from the estimates used at December 31, 2022. Our estimates used to determine benefit cost for 2023 included a discount rate of 5.51% for pension benefits and 5.52% for postretirement healthcare costs, a 248 and 251 basis point increase, respectively, from 2022 estimates. The 5.52% discount rate for postretirement healthcare costs was adjusted to 6.06% effective September 30, 2023, in connection with a remeasurement of our plan liability due to an amendment to the plan. The adjustment to 6.06% was a 305 basis point increase from the 2022 estimate. In addition, we estimated our assumed rate of return on pension assets to be 7.00% for 2023, a 70 basis point increase from our 2022 estimate.
The following table summarizes the impact on 2023 pension and postretirement costs for a 25 basis point increase or decrease, holding all other variables constant, on certain key assumptions:
(in thousands) +0.25 -0.25
Pension Plan:
Discount Rate $ 65 $ (72)
Rate of Increase in Future Compensation 259 245
Long-Term Return on Plan Assets (926) 926
Other Postretirement Benefits:
Discount Rate 13 3
For 2024, we expect pension and other postretirement benefit income to be $8.5 million compared to $9.5 million of income in 2023, due to the impacts of updated actuarial assumptions. See additional information at footnote 10 of the consolidated financial statements.
Subsequent increases or decreases in actual rates of return on plan assets over assumed rates, increases or decreases in the discount rate, increases in future compensation levels, and increases in retiree healthcare cost inflation rates could significantly change projected costs.
We believe the estimates made for our pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are subject to change.
GOODWILL IMPAIRMENT
Goodwill is required to be evaluated annually for impairment and more frequently as events or circumstances require. Goodwill is tested for impairment at the reporting unit level. We have identified two reporting units which carry a material amount of goodwill.
The goodwill impairment test is a single-step quantitative assessment which compares the estimated fair value of the reporting unit to its carrying value. An impairment charge is recognized if the carrying amount exceeds the estimated fair value in an amount that is equal to the excess but limited to the amount of recorded goodwill of the reporting unit. An optional qualitative impairment assessment may be performed prior to and may eliminate the need to perform the quantitative assessment.
Estimating the fair value of a reporting unit under the quantitative impairment method requires significant judgments and estimates. We estimate the fair value of our reporting units primarily using an income approach, which includes a discounted cash flow methodology to arrive at a fair value estimate by determining the present value of projected future cash flows over a specified period plus a terminal value to reflect cash flows beyond the projection period. The discount rate applied to the estimated future cash flows reflects our estimate of the weighted-average cost of capital of comparable entities. To supplement our income approach, we reference various market indications of fair value, where available, and include fair value estimates using multiples derived from comparable enterprise values to earnings before interest, taxes, depreciation, and amortization (EBITDA), and, if available, comparable sales transactions for comparative peer companies.
Our discounted cash flow methodology incorporates significant estimates, which include assumptions of future operating results and cash flows, which are impacted by economic and industry conditions, the amount and timing of estimated capital expenditures, an estimated terminal growth rate and the selection of an appropriate weighted-average cost of capital, among others.
Our goodwill impairment testing performed in the fourth quarter of 2023 indicated no impairment was present for either reporting unit and the estimated fair value of each reporting unit substantially exceeded the respective carrying value. As part of our testing, we perform various sensitivity analyses to understand if our conclusions are sensitive to changes in certain assumptions. A 1% decrease in projected operating revenues, a one hundred basis point decrease in projected gross profit margins and a twenty five basis point increase in the discount rate would not lead to a goodwill impairment charge for either reporting unit.
We believe the estimates and assumptions used in our impairment assessments are reasonable and based on the best information available. However, these estimates and assumptions include an inherent degree of uncertainty. Significant adverse changes in our expectations for any of these estimates could result in an impairment charge in a future period which may materially impact our operating results and financial position.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the potential loss arising from adverse changes in market rates and prices. We are primarily exposed to interest rate and commodity price risk.
Commodity Price Risk
Our Electric segment business is exposed to market risk arising from changes in commodity prices for wholesale energy and natural gas. OTP purchases energy in the wholesale market to supplement its own electricity generation and to respond to changes in demand and variability in generating plant output. In addition, OTP procures natural gas as a fuel source for its combustion turbine peaking facilities. OTP's exposure to price risk for these commodities is largely mitigated by the current ratemaking process and regulatory framework, which generally allows recovery of purchased power and fuel costs from our electric customers.
OTP, where prudent, seeks to further manage its exposure to commodity price variability and reduce volatility in prices for its retail customers through the use of derivative instruments, primarily financial swap agreements. OTP does not engage in derivative and hedging activities for trading purposes. As of December 31, 2023, OTP was party to financial swap agreements with an aggregate notional amount of 187,400 megawatt-hours of electricity with various settlement dates throughout 2024. As of December 31, 2023, the aggregate fair value of these instruments was $4.2 million, reflected as a liability on our consolidated balance sheets. Holding other variables constant, a ten percent change in energy prices would have had an approximate $0.7 million impact on the fair value of these instruments.
Our Manufacturing segment businesses are exposed to market risk arising from changes in commodity prices for certain raw material inputs, including steel, aluminum, and polystyrene and other plastics resins. We manage commodity price risk by passing changes in the cost of these input materials through to our customers. If our efforts to manage commodity price risk are unsuccessful, the operating revenues and earnings of our Manufacturing segment could be impacted.
Our Plastics segment businesses are exposed to market risk arising from changes in prices for PVC resin, the primary raw material commodity used to manufacture PVC pipe. The PVC pipe industry as a whole is highly sensitive to volatility in PVC resin prices, with frequent adjustments to PVC pipe sale prices to reflect volatility in PVC resin costs. Historically, when resin prices are rising or stable, sales volumes have been higher. In contrast, when resin prices are falling, sales volumes have been lower. Due to the commodity nature of PVC resin and dynamic supply and demand factors worldwide, gross profit margins can fluctuate significantly from period to period.
We do not engage in any hedging activities within our Manufacturing and Plastics segments to manage our commodity price risk.
Interest Rate Risk
Our exposure to interest rate risk arises from our outstanding short-term debt which is subject to variable rates of interest based on benchmark interest rates, primarily SOFR, and our cash equivalent investments, which earn income at a rate that fluctuates daily, based on changes in U.S. treasury rates. As of December 31, 2023 and 2022, we had $81.4 million and $8.2 million of short-term debt outstanding. Holding other variables constant, a 100 basis point change in interest rates during 2023 would have had an approximate $0.5 million impact to interest expense in 2023 based on our average outstanding short-term debt during the year. As of December 31, 2023 and 2022, we had $219.7 million and $105.8 million invested in cash equivalent investments. Holding other variables constant, a 100 basis point change in the average interest rates during 2023 would have had an approximate $1.5 million impact to our investment income in 2023 based on our average outstanding investment balance during the year.
All of our outstanding long-term debt obligations as of December 31, 2023 and 2022 had fixed interest rates and were not subject to material interest rate risk. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, by limiting the amount of variable interest rate debt and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.
We have not used hedging instruments to manage interest risk arising from our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Otter Tail Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Otter Tail Corporation and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report Regarding Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters-Impact of Rate Regulation on the Financial Statements-Refer to Notes 1 and 5 to the financial statements.
Critical Audit Matter Description
The Company’s regulated Electric segment accounts for the financial effects of regulation in accordance with ASC 980, Regulated Operations. This guidance allows for the recording of a regulatory asset or liability for certain costs or credits which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the cost will be recovered or returned in future rates. This guidance also provides for adjustments to rates outside of a general rate case proceeding to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations.
The Company is subject to regulation of rates and other matters by state and federal regulatory agencies (collectively, the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Minnesota, North Dakota and South Dakota. The Company assesses the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which the Company operates, and the impact that incurred costs may have on customers.
There is a risk that the Commissions will not approve full recovery of the costs of providing utility service or full recovery of all amounts invested in the utility business and a reasonable return on that investment. As a result, we identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include the recording of regulatory assets for certain costs which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the costs will be recovered in future rates and the recording of regulatory liabilities for certain credits which would otherwise be recognized in the statement of income or comprehensive income based on an expectation that the amount will be returned to customers in future rates. Given that management’s accounting judgements are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities, the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates, and the related disclosures in the notes to the financial statements.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 14, 2024
We have served as the Company's auditor since 1944.
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
(in thousands, except share data) 2023 2022
Assets
Current Assets
Cash and Cash Equivalents $ 230,373 $ 118,996
Receivables, net of allowance for credit losses 157,143 144,393
Inventories 149,701 145,952
Regulatory Assets 16,127 24,999
Other Current Assets 16,826 18,412
Total Current Assets 570,170 452,752
Noncurrent Assets
Investments 62,516 54,845
Property, Plant and Equipment, net of accumulated depreciation 2,418,375 2,212,717
Regulatory Assets 95,715 94,655
Intangible Assets, net of accumulated amortization 6,843 7,943
Goodwill 37,572 37,572
Other Noncurrent Assets 51,377 41,177
Total Noncurrent Assets 2,672,398 2,448,909
Total Assets $ 3,242,568 $ 2,901,661
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Debt $ 81,422 $ 8,204
Accounts Payable 94,428 104,400
Accrued Salaries and Wages 38,134 32,327
Accrued Taxes 26,590 19,340
Regulatory Liabilities 25,408 17,300
Other Current Liabilities 43,775 56,065
Total Current Liabilities 309,757 237,636
Noncurrent Liabilities and Deferred Credits
Pension Benefit Liability
33,101 33,210
Other Postretirement Benefits Liability 27,676 46,977
Regulatory Liabilities 276,547 244,497
Deferred Income Taxes 237,273 221,302
Deferred Tax Credits 15,172 15,916
Other Noncurrent Liabilities 75,977 60,985
Total Noncurrent Liabilities and Deferred Credits 665,746 622,887
Commitments and Contingencies (Note 13)
Capitalization
Long-Term Debt
824,059 823,821
Shareholders' Equity
Common Stock: 50,000,000 shares authorized of $5 par value; 41,710,521 and 41,631,113 outstanding
at December 31, 2023 and 2022
208,553 208,156
Additional Paid-In Capital 426,963 423,034
Retained Earnings 806,342 585,212
Accumulated Other Comprehensive Income
1,148 915
Total Shareholders' Equity 1,443,006 1,217,317
Total Capitalization 2,267,065 2,041,138
Total Liabilities and Shareholders' Equity $ 3,242,568 $ 2,901,661
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
(in thousands, except per-share amounts) 2023 2022 2021
Operating Revenues
Electric $ 528,359 $ 549,699 $ 480,321
Product Sales 820,807 910,510 716,523
Total Operating Revenues 1,349,166 1,460,209 1,196,844
Operating Expenses
Electric Production Fuel 60,339 65,110 59,327
Electric Purchased Power 78,292 100,281 65,409
Electric Operating and Maintenance Expenses 191,263 181,378 159,669
Cost of Products Sold (excluding depreciation) 454,122 542,944 488,370
Nonelectric Selling, General, and Administrative Expenses
72,663 69,718 65,394
Depreciation and Amortization 97,954 92,597 91,358
Electric Property Taxes 16,614 17,742 17,609
Total Operating Expenses 971,247 1,069,770 947,136
Operating Income 377,919 390,439 249,708
Other Income and Expense
Interest Expense
(37,677) (36,016) (37,771)
Nonservice Cost Components of Postretirement Benefits 10,597 1,075 (2,016)
Other Income (Expense), net 12,650 2,037 2,900
Income Before Income Taxes 363,489 357,535 212,821
Income Tax Expense 69,298 73,351 36,052
Net Income $ 294,191 $ 284,184 $ 176,769
Weighted-Average Common Shares Outstanding:
Basic 41,668 41,586 41,491
Diluted 42,039 41,931 41,818
Earnings Per Share:
Basic $ 7.06 $ 6.83 $ 4.26
Diluted $ 7.00 $ 6.78 $ 4.23
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31,
(in thousands) 2023 2022 2021
Net Income $ 294,191 $ 284,184 $ 176,769
Other Comprehensive Income (Loss):
Unrealized Gain (Loss) on Available-for-Sale Securities, net of tax (expense) benefit of $(51), $115 and $52
192 (432) (196)
Pension and Other Postretirement Benefit Plan, net of tax expense of $14, $2,769 and $766
41 7,871 2,179
Total Other Comprehensive Income
233 7,439 1,983
Total Comprehensive Income $ 294,424 $ 291,623 $ 178,752
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands, except common stock outstanding) Common
Stock
Outstanding Par Value,
Common
Stock Additional Paid-In Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total Shareholders' Equity
Balance, December 31, 2020 41,469,879 $ 207,349 $ 414,246 $ 257,878 $ (8,507) $ 870,966
Stock Issued Under Dividend Reinvestment and Stock Purchase Plans, Net of Expenses 11,540 58 446 - - 504
Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes 70,105 351 (1,840) - - (1,489)
Net Income - - - 176,769 - 176,769
Other Comprehensive Income
- - - - 1,983 1,983
Stock Compensation Expense - - 6,908 - - 6,908
Common Dividends ($1.56 per share)
- - - (64,864) - (64,864)
Balance, December 31, 2021 41,551,524 $ 207,758 $ 419,760 $ 369,783 $ (6,524) $ 990,777
Employee Stock Purchase Plan Expenses
- - (219) - - (219)
Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes 79,589 398 (3,321) - - (2,923)
Net Income - - - 284,184 - 284,184
Other Comprehensive Income - - - - 7,439 7,439
Stock Compensation Expense - - 6,814 - - 6,814
Common Dividends ($1.65 per share)
- - - (68,755) - (68,755)
Balance, December 31, 2022 41,631,113 $ 208,156 $ 423,034 $ 585,212 $ 915 $ 1,217,317
Employee Stock Purchase Plan Expenses - - (339) - - (339)
Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes 79,408 397 (3,485) - - (3,088)
Net Income - - - 294,191 - 294,191
Other Comprehensive Income - - - - 233 233
Stock Compensation Expense - - 7,753 - - 7,753
Common Dividends ($1.75 per share)
- - - (73,061) - (73,061)
Balance, December 31, 2023 41,710,521 $ 208,553 $ 426,963 $ 806,342 $ 1,148 $ 1,443,006
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
(in thousands) 2023 2022 2021
Operating Activities
Net Income $ 294,191 $ 284,184 $ 176,769
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization 97,954 92,597 91,358
Deferred Tax Credits (744) (745) (744)
Deferred Income Taxes 13,508 32,424 28,896
Discretionary Contribution to Pension Plan - (20,000) (10,000)
Investment (Gains) Losses
(7,222) 3,296 (4,524)
Stock Compensation Expense 7,753 6,814 6,908
Other, net (423) (1,473) 667
Changes in Operating Assets and Liabilities:
Receivables (12,750) 30,560 (60,994)
Inventories (2,450) 5,339 (54,313)
Regulatory Assets 12,479 (2,464) (4,803)
Other Assets 2,817 (368) (14,146)
Accounts Payable (9,988) (29,763) 38,734
Accrued and Other Liabilities 6 (5,490) 28,386
Regulatory Liabilities 20,973 (6,846) 1,948
Pension and Other Postretirement Benefits (11,605) 1,244 7,101
Net Cash Provided by Operating Activities 404,499 389,309 231,243
Investing Activities
Capital Expenditures (287,134) (171,134) (171,829)
Proceeds from Disposal of Noncurrent Assets 6,225 4,346 9,702
Purchases of Investments and Other Assets (8,378) (8,283) (9,383)
Net Cash Used in Investing Activities (289,287) (175,071) (171,510)
Financing Activities
Net Borrowings (Repayments) on Short-Term Debt 73,218 (82,959) 10,166
Proceeds from Issuance of Common Stock - - 696
Proceeds from Issuance of Long-Term Debt - 90,000 140,000
Payments for Retirement of Long-Term Debt - (30,000) (140,169)
Dividends Paid (73,061) (68,755) (64,864)
Payments for Shares Withheld for Employee Tax Obligations (3,088) (2,942) (1,507)
Other, net (904) (2,123) (3,681)
Net Cash Used in Financing Activities
(3,835) (96,779) (59,359)
Net Change in Cash and Cash Equivalents 111,377 117,459 374
Cash and Cash Equivalents at Beginning of Period 118,996 1,537 1,163
Cash and Cash Equivalents at End of Period $ 230,373 $ 118,996 $ 1,537
Supplemental Disclosures of Cash Flow Information
Cash Paid During the Year for:
Interest, net of amount capitalized $ 36,956 $ 35,699 $ 36,881
Income Taxes $ 46,284 $ 43,411 $ 8,445
Supplemental Disclosure of Noncash Investing Activities
Accrued Property, Plant and Equipment Additions $ 13,001 $ 12,420 $ 12,081
See accompanying notes to consolidated financial statements
OTTER TAIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Overview
Otter Tail Corporation (OTC) and its subsidiaries (collectively, the "Company", "us", "our" or "we") form a diverse, multi-platform business consisting of a vertically integrated, regulated utility with generation, transmission and distribution facilities complemented by manufacturing businesses providing metal fabrication for custom machine parts and metal components, manufacturing of extruded and thermoformed plastic products, and manufacturing of PVC pipe products. We classify our business into three segments: Electric, Manufacturing and Plastics. Note 2 includes an additional description of the segments and financial information regarding each segment.
Principles of Consolidation
These consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles and include the accounts of OTC and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation except, as applicable, profits on sales to our regulated electric utility company from our nonregulated businesses, which is in accordance with the accounting requirements of regulated operations.
Use of Estimates
We use estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available, or actual amounts are known, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain reclassifications of amounts previously reported have been made to the accompanying consolidated statements of cash flows to maintain consistency and comparability between periods presented. Other, net operating cash flows previously reported for the years ended December 31, 2022 and 2021, included $3.3 million of investment losses and $4.5 million of investment gains, respectively, which are presented separately in the current year, and excluded $1.7 million and $0.8 million of allowance for equity funds used during construction (AFUDC), which were previously presented separately. The reclassifications had no impact on previously reported net cash provided by operating activities, net cash used in investing activities, net cash used in financing activities, or cash and cash equivalents. Certain prior period amounts related to deferred tax assets and deferred tax liabilities included in footnote 12 have been reclassified to conform to the current year presentation.
Regulatory Accounting
Our regulated electric utility company, Otter Tail Power Company (OTP), is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. OTP accounts for the financial effects of regulation in accordance with accounting guidance for regulated operations. This guidance allows for the recording of a regulatory asset for certain costs which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the cost will be recovered in future rates. This guidance also requires the recording of a regulatory liability for certain credits which would otherwise be recognized in the statement of income or comprehensive income based on an expectation that the amount will be returned to customers in future rates. Amounts recorded as regulatory assets and regulatory liabilities are generally recognized in the statements of income at the time they are reflected in customer rates. In the event OTP ceases to meet the criteria to apply the guidance for regulated operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheets and included in the consolidated statement of income as an expense or income item, or in the consolidated statement of comprehensive income as a loss or gain item, in the period in which the application of this guidance ceases.
Cash Equivalents
We consider all highly liquid investments purchased with maturity dates of 90 days or less to be cash equivalents.
Concentration of Deposits
We hold deposits with financial institutions which potentially subject us to a concentration risk. These deposits are guaranteed by the Federal Deposit Insurance Corporation up to an insurance limit of $250,000. Currently, our cash deposits exceed federally insured levels.
Revenue from Contracts with Customers
Due to our diverse business operations, the recognition of revenue from contracts with customers depends on the product produced and sold or service performed. We recognize revenue from contracts with customers at prices that are fixed or determinable as evidenced by an agreement with the customer, when we have met our performance obligation under the contract and it is probable that we will collect the amount to which we are entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, we recognize revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment discounts, and volume-based variable pricing incentives are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. We include revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of products sold. Sales or other taxes collected from customers are excluded from operating revenues.
Electric Segment Revenues. Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by state regulatory commissions. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the FERC. A third source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the amount of energy delivered to the customer.
Manufacturing Segment Revenues. Our Manufacturing segment businesses earn revenue predominantly from the production and delivery of custom-made or standardized parts and products to customers across several industries and from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, we have met our performance obligation and recognize revenue at the point in time when the product is shipped. At this point we have no further obligation to provide services related to such products. The shipping terms used in these transactions are free on board (FOB) shipping point.
Plastics Segment Revenues. Our Plastics segment businesses earn revenue predominantly from the sale and delivery of standardized PVC pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped as there is no further obligation to provide services related to such products and the shipping terms are FOB shipping point. We have one customer within our Plastics segment for which we produce and store a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, we recognize revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations we expect the customer will earn and applicable early payment discounts we expect the customer will take. Ownership of the pipe transfers to the customer prior to delivery and we are paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is recognized over time as the pipe is stored.
Alternative Revenue
In addition to recognizing revenue from contracts with customers, our Electric segment business also records revenue under alternative revenue program (ARP) requirements. Certain rate rider mechanisms qualify as ARP revenues as they provide for adjustments to rates outside of a general rate case proceeding to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested.
We accrue ARP revenue on the basis of cost incurred, investments made and returns on those investments that qualify for recovery through established riders. ARP revenue is disclosed separately from revenue from contracts with customers and we have elected to report ARP revenue on a net basis, whereby amounts initially recorded as ARP revenue in a period are presented net of the reversal of amounts previously recognized as ARP revenue that are reclassified and recorded as revenue from contracts with customers when such amounts are included in the price of electricity to customers.
Receivables and Allowance for Credit Losses
We grant credit to our customers in the normal course of business with repayment terms generally ranging from 30 to 90 days after the invoice date. Late fees are assessed on certain receivables once they are 30 days past due. Unbilled receivables represent estimates of energy delivered to customers but not yet billed.
Receivables are stated at the billed or estimated unbilled amount less an allowance for estimated credit losses. An allowance for credit losses is established based on losses expected to occur over the contractual life of the receivable. We estimate an allowance for credit losses on our trade and unbilled receivables by evaluating historical aging and write-off history, adjusted for current and forecasted economic conditions, for groups of receivables that share similar economic characteristics. Other receivables are evaluated by reviewing individual accounts, considering aging, financial condition of the debtor, recent payment history and other relevant factors. Account balances are written-off in the period they are deemed to be uncollectible.
Inventories
Inventories are valued at the lower of cost or net realizable value. Costs for fuel, material and supply inventories of our Electric segment are determined on an average cost basis. Costs for raw material, work in process and finished goods inventories of our Manufacturing and Plastics segments are determined on a first-in first-out (FIFO) basis.
Inventories consist of the following as of December 31, 2023 and 2022:
(in thousands) 2023 2022
Finished Goods $ 47,614 $ 43,812
Work in Process 26,354 31,766
Raw Material, Fuel and Supplies 75,733 70,374
Total Inventories $ 149,701 $ 145,952
Investments
We invest in and hold, through rabbi trusts, corporate-owned life insurance policies to provide future funding for obligations under our supplemental pension plan and a nonqualified deferred compensation plan. The polices are recorded at cash surrender value and there are no restrictions on our ability to surrender the policies.
We hold debt, mutual fund, and money market fund investments either as investments within our captive insurance entity or to provide future funding for obligations under nonqualified deferred compensation plans. These investments are recorded at fair value. Debt securities are deemed to be available-for-sale securities, accordingly unrealized gains and losses are generally excluded from earnings and recognized in accumulated other comprehensive income. We evaluate whether declines in fair value of debt securities below the cost basis are other-than-temporary. Declines in fair value deemed to be other-than-temporary result in the recognition of unrealized losses, or a portion thereof, in earnings. Unrealized gains and losses on mutual and money market funds are recognized in earnings immediately.
The following is a summary of our investments at December 31, 2023 and 2022:
(in thousands) 2023 2022
Corporate-Owned Life Insurance Policies $ 42,287 $ 38,991
Corporate and Government Debt Securities
9,303 8,761
Mutual Funds 7,771 5,503
Money Market Funds 3,125 1,560
Other Investments 30 30
Total Investments $ 62,516 $ 54,845
The amount of unrealized gains and losses on debt securities as of December 31, 2023 and 2022 is not material and no unrealized losses were deemed to be other-than-temporary. In addition, the amount of unrealized gains and losses on marketable equity securities still held as of December 31, 2023 and 2022 is not material.
Property, Plant and Equipment
Electric plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and AFUDC. The amount of interest capitalized to electric plant was $1.9 million in 2023, $0.9 million in 2022 and $0.6 million in 2021. The cost of depreciable units of property retired less salvage is charged to accumulated depreciation. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Removal costs, when incurred, are charged against the regulatory liability. Maintenance, repairs and replacement of minor items are charged to operating expenses as incurred. The provisions for utility depreciation for financial reporting purposes are made on the straight-line method based on the estimated remaining service lives of the properties. Gains or losses on group asset dispositions are recorded to accumulated depreciation and impact current and future depreciation rates.
Property, plant and equipment of nonelectric operations are carried at historical cost and are depreciated on a straight-line basis over the assets’ estimated useful lives. The cost of additions includes contracted work, direct labor and materials, allocable overheads and capitalized interest. No interest was capitalized in 2023, 2022 or 2021. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.
The estimated service lives for rate-regulated electric assets and nonelectric assets are included below:
Service Life Range
(years) Low High
Electric Assets:
Production Plant 21 114
Transmission Plant 51 75
Distribution Plant 10 70
General Plant 5 56
Nonelectric Assets:
Equipment 2 20
Buildings and Leasehold Improvements 2 40
Jointly Owned Facilities
OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in five major transmission lines. OTP's interest in each jointly owned facility is reflected in the consolidated balance sheets on a pro-rata basis and OTP's share of direct revenue and expenses are included in operating revenues and expenses in the consolidated statements of income. Each participant in the jointly owned facilities finances their own investments.
Goodwill and Other Intangible Assets
Goodwill is recognized and initially measured as any excess of the acquisition-date consideration transferred in a business combination over amounts recognized for the net identifiable assets acquired. Goodwill is not amortized, but is tested for impairment annually, or more frequently if
an event occurs or circumstances change that would more likely than not result in an impairment of goodwill. Impairment testing is performed at the reporting unit level, which is defined as an operating segment or one level below an operating segment. We perform our impairment testing in the fourth quarter of each year and have identified three reporting units that carry a goodwill balance.
Our impairment testing includes both an optional qualitative assessment and the quantitative impairment assessment. Our qualitative assessment includes an analysis of relevant events and circumstances to determine if it is more likely than not that the fair value of the reporting unit exceeds its book value. If, after this assessment, we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, no additional analysis is necessary. In contrast, if after the assessment we determine it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or if we elect to skip the optional qualitative assessment, the quantitative impairment assessment is performed. The quantitative assessment is a single-step test that identifies both the existence of impairment and the amount of impairment loss by comparing the estimated fair value of a reporting unit to its carrying value, with any excess carrying value over the fair value being recognized as an impairment loss.
Intangible assets with finite lives, which primarily consist of customer relationships, are carried at estimated fair value at the time of acquisition less accumulated amortization. The costs of the intangible assets are amortized over their estimated useful lives, which generally range from 15 to 20 years.
Cloud Computing Costs
We capitalize implementation costs incurred in cloud computing arrangements that are service contracts consistent with capitalized implementation costs incurred to develop or obtain internal-use software. Costs are amortized on a straight-line basis over the life of the associated contract. Capitalized implementation costs are amortized over periods up to ten years. Capitalized costs and related accumulated amortization are included in other noncurrent assets on the consolidated balance sheets. Below are the amounts of capitalized cost and related accumulated amortization as of December 31, 2023 and 2022:
(in thousands) 2023 2022
Cloud Computing Costs
$ 12,782 $ 9,024
Accumulated Amortization
$ (1,505) $ (897)
Cloud Computing Costs, net
$ 11,277 $ 8,127
Amortization expense of capitalized implementation costs for each of the years ended December 31, 2023, 2022 and 2021 totaled $1.3 million, $1.4 million, and $0.5 million.
Leases
We recognize right-of-use lease assets and a corresponding lease liability at the lease commencement date. The length of our lease agreements varies from less than one year to approximately ten years. We have elected to not record lease assets and liabilities for leases with a lease term at commencement of 12 months or less; such leases are expensed on a straight-line basis over the lease term. If a lease contains an option to extend the lease term and there is reasonable certainty the option will be exercised, the option is considered in the lease term at inception. We have elected to not separate non-lease components (e.g., common area maintenance) from lease components on real estate leases, accordingly the recognized lease asset and lease liability incorporate in their measurement payments for non-lease components. Certain leases include variable lease payments as the amounts are subject to change over the lease term. We are unable to determine the interest rate implicit in our leases thus we apply our incremental borrowing rate to capitalize the right-of-use asset and lease liability. We estimate our incremental borrowing rate by incorporating considerations of lease term and lessee entity.
Recoverability of Long-Lived Assets
We review our long-lived assets including, among other assets, property, plant and equipment, amortizing intangible assets and right-of-use lease assets, whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. We determine potential impairment by comparing the carrying amount of the assets with the net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, an impairment loss would be recognized. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset.
Asset Retirement Obligations
Legal obligations related to the future retirement of long-lived assets are recognized as asset retirement obligations (ARO). An ARO is recognized in the period in which the legal obligation is incurred and the amount of the obligation can be reasonably estimated, with an offsetting increase to the associated long-lived asset. AROs are initially recognized at fair value and increased with the passage of time (accretion). ARO estimates are revised periodically with any adjustment reflected in the ARO and associated long-lived asset.
Income Taxes
We use the asset and liability method to account for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of all temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. Deferred tax assets are reduced by a valuation allowance when it is more likely than not that a portion or all of the deferred tax assets will not be realized. The realizability of deferred tax assets is determined by taking into consideration forecasts of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies. Changes in valuation allowances are included in the provision for income taxes in the period of the changes.
We recognize the tax effects of all tax positions that are more-likely-than-not to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. Changes in the recognition or measurement of such positions are recognized in the provision for income taxes in the period of the changes. We classify interest and penalties on tax uncertainties as components of the provision for income taxes.
We have elected to account for transferable tax credits as a component of our income tax provision. We recognize the benefit of PTCs as a reduction of income tax expense in the period the credit is generated, which corresponds to the period the energy production occurs. We apply the deferral method of accounting for ITCs and state wind energy credits. Under this method, ITCs and state wind energy credits are amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.
Deferred Compensation Plans
The Company sponsors two nonqualified deferred compensation plans for the benefit of executive officers and other select employees. Each plan allows participants to defer a specified amount or percentage of base wages or incentive compensation into the plan, subject to certain limitations. The Company, at its discretion, may make employer contributions to either plan during any annual period. Participant and employer deferred amounts are segregated into one or more accounts chosen by the participant. Participants earn a return on deferred amounts based on notional investments in the segregated accounts. Participants can elect lump sum distributions or annual installments of deferred balances during the participant's employment or upon retirement. As of December 31, 2023 and 2022, our liability to participants under these deferred compensation plans was $24.6 million and $20.6 million. Company contributions to these plans were $1.2 million, $0.9 million and $1.1 million for the years ended December 31, 2023, 2022 and 2021. Gains or (losses) recognized due to changes in our payment obligations in connection with these plans amounted to ($3.3 million), $3.1 million, and ($2.2 million) for the years ended December 31, 2023, 2022 and 2021.
Stock-Based Compensation
Stock-based compensation awards are measured at the grant-date fair value of the award and compensation expense is recognized on a straight-line basis over the applicable service or performance period. The service period may be limited to the period until such time that a recipient is retirement eligible as determined under the award agreement. Awards granted to employees eligible for retirement on the date of grant are expensed in the period of grant. We recognize the effects of award forfeitures as they occur.
Fair Value Measurements
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. Three levels of inputs may be used to measure fair value:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.
Level 2 - Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
Level 3 - Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
In instances where the determination of the fair value measurement is based on inputs from different levels within the hierarchy, the level in the hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety.
Related Parties
The Otter Tail Corporation Foundation and Otter Tail Power Company Foundation are independent not-for-profit charitable entities affiliated with the Company and are not included in the consolidated financial statements of Otter Tail Corporation. Contribution obligations to the two foundations totaling $5.5 million and $4.3 million were recognized as of December 31, 2023 and 2022. Cash contributions paid to the two foundations during the years ended December 31, 2023, 2022 and 2021 were $4.3 million, $4.5 million, and $3.8 million.
Variable Interest Entity
In October 2012, the Coyote Station owners, including OTP, entered into an LSA with Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed upon profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are required to buy certain assets of CCMC at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC because the Coyote Station owners are required to buy the membership interests of CCMC at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered the primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.
If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC, the owners will satisfy or, if permitted by CCMC’s applicable lenders, assume all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated prior to the end of the term due to certain events, OTP’s maximum loss exposure, as a result of its involvement with CCMC, could be as high as $40 million, or OTP’s 35% share of CCMC’s unrecovered costs as of December 31, 2023, if recovery of such a loss is denied by regulatory authorities.
Recent Accounting Pronouncements
Segment Reporting. In November 2023, the Financial Accounting Standards Board (FASB) issued amended authoritative guidance codified in Accounting Standards Codification (ASC) 280, Segment Reporting. The amended guidance expands annual and interim disclosure requirements for reportable segments, primarily through expanded disclosures about significant segment expenses. The updated standard is effective for our annual periods beginning in 2024 and interim periods beginning in the first quarter of fiscal 2025. Adoption of the amended guidance must be applied retrospectively to all prior periods presented in the financial statements. We are currently evaluating the impact that the updated standard will have on our financial statement disclosures.
Income Taxes. In December 2023, the FASB issued amended authoritative guidance codified in ASC 740, Income Taxes. The amended guidance requires additional disaggregated information in effective tax rate reconciliation disclosures and additional disaggregated information about income taxes paid. The updated standard is effective for our annual periods beginning in 2025. The amended guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. We are currently evaluating the impact that the updated standard will have on our financial statement disclosures.
2. Segment Information
We classify our business into three segments, Electric, Manufacturing and Plastics, consistent with our business strategy, organizational structure and our internal reporting and review processes used by our chief operating decision maker to make decisions regarding allocation of resources, to assess operating performance and to make strategic decisions.
Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the MISO markets. OTP’s operations have been our primary business since 1907.
Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the western half of the United States and Canada.
Certain assets, income and expenses are not allocated to our operating segments. Corporate operating results include items such as corporate staff and overhead costs, the results of our captive insurance company, gains or losses on our investments and returns on our cash equivalent investments. These items and others are excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, investments, prepaid expenses, and fixed assets. Corporate is not an operating segment, rather it is added to operating segment totals to reconcile to consolidated amounts.
Information for each segment and our unallocated corporate costs for the years ended December 31, 2023, 2022 and 2021 are as follows:
(in thousands) 2023 2022 2021
Operating Revenue
Electric $ 528,359 $ 549,699 $ 480,321
Manufacturing 402,781 397,983 336,294
Plastics 418,026 512,527 380,229
Total 1,349,166 1,460,209 1,196,844
Depreciation and Amortization
Electric 75,330 72,050 71,343
Manufacturing 18,495 16,202 15,436
Plastics 4,027 4,205 4,354
Corporate 102 140 225
Total 97,954 92,597 91,358
Operating Income (Loss)
Electric 106,521 113,138 106,964
Manufacturing 29,140 29,065 24,114
Plastics 254,402 264,578 132,760
Corporate (12,144) (16,342) (14,130)
Total 377,919 390,439 249,708
Interest Expense
Electric 33,864 31,950 33,043
Manufacturing 2,295 2,796 2,239
Plastics 602 585 587
Corporate 916 685 1,902
Total 37,677 36,016 37,771
Income Tax Expense (Benefit)
Electric 1,648 5,065 1,663
Manufacturing 5,390 5,321 4,704
Plastics 66,066 68,688 34,374
Corporate (3,806) (5,723) (4,689)
Total 69,298 73,351 36,052
Net Income (Loss)
Electric 84,424 79,974 72,458
Manufacturing 21,454 20,950 17,186
Plastics 187,748 195,374 97,823
Corporate 565 (12,114) (10,698)
Total 294,191 284,184 176,769
Capital Expenditures
Electric 240,695 147,869 140,031
Manufacturing 23,284 17,954 20,690
Plastics 23,029 5,245 11,040
Corporate 126 66 68
Total $ 287,134 $ 171,134 $ 171,829
The following provides the identifiable assets by segment and corporate assets as of December 31, 2023 and 2022:
(in thousands) 2023 2022
Identifiable Assets
Electric $ 2,533,831 $ 2,351,961
Manufacturing 251,343 245,869
Plastics 164,179 126,318
Corporate 293,215 177,513
Total $ 3,242,568 $ 2,901,661
Concentrations
Our Plastics segment businesses use PVC resin as a critical component within their PVC pipe manufacturing process. There are a limited number of PVC resin suppliers in the U.S., and in 2023, we sourced all of our PVC resin needs from three vendors. Although there are a limited number of PVC resin suppliers, we believe that other suppliers could provide PVC resin on comparable terms. Additionally, most U.S. resin production plants are located in the Gulf Coast region. These plants are subject to the risk of damage and production shutdowns because of exposure to hurricanes or other extreme weather events that occur in this region. The loss of a key vendor, or any interruption or delay in the supply of PVC resin could cause production delays, a possible loss of sales, or result in increased costs to secure resin, all of which would adversely affect our operating results.
Entity-Wide Information
No single customer accounted for over 10% of our consolidated operating revenues for the years ended December 31, 2023, 2022 and 2021. All of our long-lived assets are located within the United States and substantially all of our operating revenues are from customers located within the United States.
3. Revenue
We present our operating revenues from external customers, in total and by amounts arising from contracts with customers and ARP arrangements, disaggregated by revenue source and segment for the years ended December 31, 2023, 2022 and 2021:
(in thousands) 2023 2022 2021
Operating Revenues
Electric Segment
Retail: Residential $ 135,570 $ 143,888 $ 135,361
Retail: Commercial and Industrial 312,551 318,494 262,408
Retail: Other 7,719 7,918 7,715
Total Retail 455,840 470,300 405,484
Transmission 52,555 52,213 48,835
Wholesale 12,459 18,539 17,936
Other 7,505 8,647 8,066
Total Electric Segment 528,359 549,699 480,321
Manufacturing Segment
Metal Parts and Tooling 351,267 338,865 283,527
Plastic Products and Tooling 41,395 49,080 40,231
Scrap Metal 10,119 10,038 12,536
Total Manufacturing Segment 402,781 397,983 336,294
Plastics Segment
PVC Pipe 418,026 512,527 380,229
Total Operating Revenue 1,349,166 1,460,209 1,196,844
Less: Noncontract Revenues Included Above
Electric Segment - ARP Revenues (4,310) (9,266) (791)
Total Operating Revenues from Contracts with Customers $ 1,353,476 $ 1,469,475 $ 1,197,635
4. Receivables
Receivables as of December 31, 2023 and 2022 are as follows:
(in thousands) 2023 2022
Receivables
Trade $ 129,257 $ 112,126
Other 9,084 9,983
Unbilled Receivables 21,324 23,932
Total Receivables 159,665 146,041
Less Allowance for Credit Losses 2,522 1,648
Receivables, net of allowance for credit losses $ 157,143 $ 144,393
The following is a summary of activity in the allowance for credit losses for the years ended December 31, 2023 and 2022:
(in thousands) 2023 2022
Beginning Balance $ 1,648 $ 1,836
Additions Charged to Expense 2,014 909
Reductions for Amounts Written Off, Net of Recoveries
(1,140) (1,097)
Ending Balance $ 2,522 $ 1,648
5. Regulatory Matters
Regulatory Assets and Liabilities
The following presents our current and long-term regulatory assets and liabilities as of December 31, 2023 and 2022 and the period we expect to recover or refund such amounts:
Period of 2023 2022
(in thousands) Recovery/Refund Current Long-Term Current Long-Term
Regulatory Assets
Pension and Other Postretirement Benefit Plans1
See below $ 154 $ 86,134 $ - $ 88,354
Alternative Revenue Program Riders2
Up to 2 years
3,719 158 5,679 2,508
Asset Retirement Obligations1
Asset lives - 87 - 1,467
Deferred Income Taxes Asset lives - 6,940 - -
Fuel Clause Adjustments1
Up to 1 year
7,294 - 10,893 -
Derivative Instruments1
Up to 1 year
4,210 - 7,130 -
Other1
Various 750 2,396 1,297 2,326
Total Regulatory Assets 16,127 95,715 24,999 94,655
Regulatory Liabilities
Deferred Income Taxes Asset lives - 136,022 - 131,480
Plant Removal Obligations Asset lives - 117,030 8,509 105,733
Fuel Clause Adjustments Up to 1 year
11,350 - 365 -
Alternative Revenue Program Riders Up to 1 year
6,885 - 2,504 -
North Dakota PTC Refunds
Asset lives - 12,011 - 7,136
Pension and Other Postretirement Benefit Plans See below 6,138 11,307 5,589 -
Other Various 1,035 177 333 148
Total Regulatory Liabilities $ 25,408 $ 276,547 $ 17,300 $ 244,497
1Costs subject to recovery without a rate of return.
2Amount eligible for recovery includes an incentive or rate of return.
Pension and Other Postretirement Benefit Plans represent benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed or amortized. These unrecognized benefit costs and actuarial losses and gains are eligible for treatment as regulatory assets or liabilities based on their probable inclusion in future electric rates.
Alternative Revenue Program Riders regulatory assets and liabilities are revenues not yet collected from customers or amounts subject to refund, respectively, primarily due to investments in qualifying transmission, conservation, renewable resource, environmental and other generation assets, and the impact of decoupling.
Asset Retirement Obligations represent the difference in timing of recognition of expense arising from these obligations and the amount recovered from customers.
Fuel Clause Adjustments represent the under- or over-collection of fuel costs relative to the estimated cost of fuel included in customer rates, which will be collected from or returned to customers.
Derivative Instruments represent unrealized gains and losses recognized on derivative instruments. On final settlement of such instruments, any realized gains or losses are paid to or recovered from customers.
Deferred Income Taxes represent the revaluation of accumulated deferred income taxes arising from the change in the federal income tax rate in 2017. This amount is being refunded to customers over the estimated lives of the property assets from which the deferred income taxes originated.
Plant Removal Obligations represent amounts collected from customers to be used to cover actual removal costs as incurred.
North Dakota PTC Refunds represent PTCs earned from the Merricourt Wind Energy Center. These amounts are being allocated to customers over the life of the asset.
Other regulatory assets and liabilities include other amounts that we expect to recover from, or return to, customers in future periods, such as
the cost of abandoned projects, costs incurred in connection with recent rate cases, and other items.
North Dakota Rate Case
On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of return on equity of 10.6% on an equity ratio of 53.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost and investment recovery, with recovery moving from riders into base rates. The filing also includes a proposal to implement a sales adjustment mechanism to address potential significant load additions or losses. The filing included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023, and interim rates went into effect on January 1, 2024. These interim rate revenues, when collected, are subject to potential refund until the finalization of the rate case.
6. Property, Plant and Equipment
Major classes of property, plant and equipment as of December 31, 2023 and 2022 include:
(in thousands) 2023 2022
Electric Plant in Service
Production $ 1,412,826 $ 1,343,097
Transmission 777,613 756,848
Distribution 654,704 612,716
General 144,738 131,718
Electric Plant in Service 2,989,881 2,844,379
Construction Work in Progress 137,212 113,932
Total Gross Electric Plant 3,127,093 2,958,311
Less Accumulated Depreciation and Amortization 851,148 859,988
Net Electric Plant 2,275,945 2,098,323
Nonelectric Property, Plant and Equipment
Equipment 233,571 218,770
Buildings and Leasehold Improvements 64,753 61,506
Land 13,600 13,652
Nonelectric Property, Plant and Equipment 311,924 293,928
Construction Work in Progress 38,062 15,170
Total Gross Nonelectric Property, Plant and Equipment 349,986 309,098
Less Accumulated Depreciation and Amortization 207,556 194,704
Net Nonelectric Property, Plant and Equipment 142,430 114,394
Net Property, Plant and Equipment $ 2,418,375 $ 2,212,717
Depreciation expense for the years ended December 31, 2023, 2022 and 2021 totaled $90.8 million, $84.4 million and $85.8 million.
The following table provides OTP’s ownership percentages and amounts included in the December 31, 2023 and 2022 consolidated balance sheets for OTP’s share of each of these jointly owned facilities:
(dollars in thousands) Ownership
Percentage Electric Plant
in Service Construction
Work in
Progress Accumulated
Depreciation Net Plant
December 31, 2023
Big Stone Plant 53.9 % $ 341,683 $ 820 $ (126,904) $ 215,599
Coyote Station 35.0 % 188,656 104 (115,306) 73,454
Big Stone South-Ellendale 345 kV line 50.0 % 106,185 - (7,181) 99,004
Fargo-Monticello 345 kV line 14.2 % 78,184 - (11,238) 66,946
Big Stone South-Brookings 345 kV line 50.0 % 53,170 - (5,207) 47,963
Brookings-Southeast Twin Cities 345 kV line 4.8 % 26,409 83 (3,617) 22,875
Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 - (3,568) 12,763
Jamestown- Ellendale 345 kV line 50.0 % - 1,121 - 1,121
Big Stone South-Alexandria 345 kV line 40.0 % - 555 - 555
Alexandria-Big Oaks 345 kV line
14.2 % - 343 - 343
December 31, 2022
Big Stone Plant 53.9 % $ 338,411 $ 557 $ (118,044) $ 220,924
Coyote Station 35.0 % 183,461 2,315 (111,666) 74,110
Big Stone South-Ellendale 345 kV line 50.0 % 106,185 - (5,587) 100,598
Fargo-Monticello 345 kV line 14.2 % 78,184 - (10,095) 68,089
Big Stone South-Brookings 345 kV line 50.0 % 53,041 - (4,406) 48,635
Brookings-Southeast Twin Cities 345 kV line 4.8 % 26,291 - (3,211) 23,080
Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 - (3,318) 13,013
7. Intangible Assets
The following table summarizes our goodwill by segment as of December 31, 2023 and 2022:
(in thousands) 2023 2022
Manufacturing $ 18,270 $ 18,270
Plastics 19,302 19,302
Total Goodwill $ 37,572 $ 37,572
Our annual goodwill impairment testing, performed in the fourth quarters of 2023 and 2022, indicated no impairment existed as of the test date.
The following table summarizes the components of our intangible assets at December 31, 2023 and 2022:
(in thousands) Gross
Amount Accumulated
Amortization Net Carrying
Amount
December 31, 2023
Customer Relationships $ 22,491 $ 15,667 $ 6,824
Other 26 7 19
Total 22,517 15,674 6,843
December 31, 2022
Customer Relationships 22,491 14,568 7,923
Other 26 6 20
Total $ 22,517 $ 14,574 $ 7,943
Amortization expense for these intangible assets for each of the years ended December 31, 2023, 2022 and 2021 totaled $1.1 million.
Annual amortization expense for these intangible assets for the next five years is:
(in thousands) 2024 2025 2026 2027 2028
Amortization Expense $ 1,100 $ 1,100 $ 1,092 $ 1,090 $ 554
8. Leases
We lease rail cars, warehouse and office space, land, and certain office, manufacturing, material handling, and other equipment under varying terms and conditions. All leases are classified as operating leases.
The components of lease cost and lease cash flows for the years ended December 31, 2023, 2022, and 2021 are as follows:
(in thousands) 2023 2022 2021
Lease Cost
Operating Lease Cost $ 6,309 $ 5,606 $ 5,298
Variable Lease Cost 1,433 1,386 1,020
Short-Term Lease Cost 2,525 1,517 1,465
Total Lease Cost 10,267 8,509 7,783
Lease Cash Flows
Operating Cash Flows from Operating Leases $ 6,424 $ 5,592 $ 5,642
A summary of operating lease right-of-use lease assets and lease liabilities as of December 31, 2023 and 2022 is as follows:
(in thousands) 2023 2022
Right of Use Lease Assets1
$ 16,788 $ 18,610
Lease Liabilities
Current2
5,756 5,071
Long-Term3
11,258 13,876
Total Lease Liabilities $ 17,014 $ 18,947
1Included in Other Noncurrent Assets in the consolidated balance sheets.
2Included in Other Current Liabilities in the consolidated balance sheets.
3Included in Other Noncurrent Liabilities in the consolidated balance sheets.
Operating lease assets obtained in exchange for new operating liabilities amounted to $3.6 million and $3.7 million for the years ended December 31, 2023 and 2022.
Maturities of lease liabilities as of December 31, 2023 for each of the next five years and in the aggregate thereafter are as follows:
(in thousands) Operating Leases
2024 $ 6,473
2025 5,357
2026 3,068
2027 2,196
2028 1,059
Thereafter 368
Total Lease Payments 18,521
Less: Interest 1,507
Present Value of Lease Liabilities $ 17,014
The weighted-average remaining lease term and the weighted-average discount rate as of December 31, 2023 and 2022 are as follows:
2023 2022
Weighted-Average Remaining Lease Term (in years) 3.4 4.2
Weighted-Average Discount Rate 5.40 % 4.73 %
9. Short-Term and Long-Term Borrowings
The following is a summary of our outstanding short- and long-term borrowings by borrower, OTC or OTP, as of December 31, 2023 and 2022:
2023 2022
(in thousands) OTC OTP Total OTC OTP Total
Short-Term Debt $ - $ 81,422 $ 81,422 $ - $ 8,204 $ 8,204
Current Maturities of Long-Term Debt - - - - - -
Long-Term Debt, net of current maturities 79,849 744,210 824,059 79,798 744,023 823,821
Total $ 79,849 $ 825,632 $ 905,481 $ 79,798 $ 752,227 $ 832,025
Short-Term Debt
The following is a summary of our lines of credit as of December 31, 2023 and 2022:
2023 2022
(in thousands) Line Limit Amount Outstanding Letters
of Credit Amount Available Amount Available
OTC Credit Agreement $ 170,000 $ - $ - $ 170,000 $ 170,000
OTP Credit Agreement 170,000 81,422 9,132 79,446 152,223
Total $ 340,000 $ 81,422 $ 9,132 $ 249,446 $ 322,223
OTC is party to a Fifth Amended and Restated Credit Agreement (the OTC Credit Agreement) and OTP is party to a Fourth Amended and Restated Credit Agreement (the OTP Credit Agreement). The agreements both provide for $170.0 million unsecured revolving lines of credit to support operations, fund capital expenditures, refinance certain indebtedness and provide for the issuance of letters of credit in an aggregate amount not to exceed $40.0 million under the OTC Credit Agreement and $50.0 million under the OTP Credit Agreement. Each credit facility includes an accordion provision allowing the borrower to increase the borrowing capacity under the facility, subject to certain conditions, up to $290.0 million and $250.0 million under the OTC Credit Agreement and OTP Credit Agreement, respectively.
Borrowings under each credit facility are subject to a variable rate of interest on outstanding balances and a commitment fee is charged based on the average unused amount available to be drawn under the respective facility. The variable rate of interest to be charged is based on a benchmark interest rate, either SOFR or a Base Rate, as defined in the credit agreements, selected by the borrower at the time of an advance, subject to the conditions of each agreement, plus an applicable credit spread. The credit spread ranges from zero to 2.00%, depending on the benchmark interest rate selected, and is subject to adjustment based on the credit ratings of the relevant borrower. The weighted-average interest rate on all outstanding borrowings as of December 31, 2023 and 2022 was 6.70% and 5.61%.
Each credit facility contains a number of restrictions on the borrower, including restrictions on the ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The agreements also require the borrower to maintain various financial covenants, as further described below. Each credit facility expires on October 29, 2027.
Long-Term Debt
The following is a summary of outstanding long-term debt by borrower as of December 31, 2023 and 2022:
(in thousands)
Entity Debt Instrument Rate Maturity 2023 2022
OTC Guaranteed Senior Notes 3.55% 12/15/26 $ 80,000 $ 80,000
OTP Series 2007C Senior Unsecured Notes 6.37% 08/02/27 42,000 42,000
OTP Series 2013A Senior Unsecured Notes 4.68% 02/27/29 60,000 60,000
OTP Series 2019A Senior Unsecured Notes 3.07% 10/10/29 10,000 10,000
OTP Series 2020A Senior Unsecured Notes 3.22% 02/25/30 10,000 10,000
OTP Series 2020B Senior Unsecured Notes 3.22% 08/20/30 40,000 40,000
OTP Series 2021A Senior Unsecured Notes 2.74% 11/29/31 40,000 40,000
OTP Series 2007D Senior Unsecured Notes 6.47% 08/20/37 50,000 50,000
OTP Series 2019B Senior Unsecured Notes 3.52% 10/10/39 26,000 26,000
OTP Series 2020C Senior Unsecured Notes 3.62% 02/25/40 10,000 10,000
OTP Series 2013B Senior Unsecured Notes 5.47% 02/27/44 90,000 90,000
OTP Series 2018A Senior Unsecured Notes 4.07% 02/07/48 100,000 100,000
OTP Series 2019C Senior Unsecured Notes 3.82% 10/10/49 64,000 64,000
OTP Series 2020D Senior Unsecured Notes 3.92% 02/25/50 15,000 15,000
OTP Series 2021B Senior Unsecured Notes 3.69% 11/29/51 100,000 100,000
OTP Series 2022A Senior Unsecured Notes 3.77% 05/20/52 90,000 90,000
Total 827,000 827,000
Less: Unamortized Long-Term Debt Issuance Costs 2,941 3,179
Total Long-Term Debt Net of Unamortized Debt Issuance Costs $ 824,059 $ 823,821
Our guaranteed and unsecured notes require the borrower to maintain various financial covenants, as further described below. These notes provide for prepayment options allowing for a full or partial prepayment at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount, as defined. These notes also include restrictions on the borrower, including its ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties.
Aggregate maturities of long-term debt obligations at December 31, 2023 for each of the next five years are as follows:
(in thousands) 2024 2025 2026 2027 2028
Debt Maturities $ - $ - $ 80,000 $ 42,000 $ -
Financial Covenants
Certain of OTC's and OTP's short-term and long-term debt agreements require the borrower, whether OTC or OTP, to maintain certain financial covenants, including a maximum debt to total capitalization of 0.60 to 1.00, a minimum interest and dividend coverage ratio of 1.50 to 1.00, and a maximum level of priority indebtedness. As of December 31, 2023, OTC and OTP were in compliance with these financial covenants.
Guaranties
OTC's obligations under the terms of its Guaranteed Senior Notes are unconditionally and irrevocably guaranteed by its subsidiaries, Varistar Corporation, BTD Manufacturing, Inc., Northern Pipe Products, Inc., and Vinyltech Corporation.
10. Employee Postretirement Benefits
Pension Plan and Other Postretirement Benefits
The Company sponsors a noncontributory funded pension plan (the Pension Plan), an unfunded, nonqualified Executive Survivor and Supplemental Retirement Plan (ESSRP), both accounted for as defined benefit pension plans, and a postretirement healthcare plan accounted for as an other postretirement benefit plan.
The Pension Plan, which previously covered substantially all corporate and OTP employees, was closed to new employees in 2013. The plan provides retirement compensation to all covered employees at age 65, with reduced compensation in cases of retirement prior to age 62. Participants are fully vested after completing five years of vesting service. The plan assets consist of equity funds, fixed income funds, cash and cash equivalents and alternative investments. None of the plan assets are invested in common stock or debt securities of the Company.
The ESSRP, an unfunded plan, provides for defined benefit payments to executive officers and certain key management employees on their retirement for life, or to their beneficiaries on their death. The ESSRP was amended and restated in 2019 to i) freeze the participation in the
restoration retirement benefit component of the plan and ii) freeze benefit accruals under the restoration retirement benefit component of the plan for all participants of the plan except any participants deemed to be grandfathered participants.
The postretirement healthcare plan, closed to new participants in 2010, provides a portion of health insurance benefits for retired and covered corporate and OTP employees. To be eligible for retiree health insurance benefits, the employee must be 55 years of age with a minimum of 10 years of service. The plan is an unfunded plan and accordingly holds no plan assets.
Pension Plan Assets. We have established a Retirement Plans Administration Committee to develop and monitor our investment strategy for our Pension Plan assets. Our investment strategy includes the following objectives:
•The assets of the plan will be invested in accordance with all applicable laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards of 1974 (ERISA) (if applicable). Specifically:
◦The safeguards and diversity that a prudent investor would adhere to must be present in the investment program.
◦All transactions undertaken on behalf of the Pension Plan must be in the best interest of plan participants and their beneficiaries.
•The primary objective is to provide a source of retirement income for its participants and beneficiaries.
•The near-term primary financial objective is to improve and protect the funded status of the plan.
•A secondary financial objective is to minimize pension funding and expense volatility where possible.
We have developed an asset allocation target, measured at investment market value, to provide guideline percentages of investment mix. This investment mix is intended to achieve the financial objectives of the plan. The permitted range is a guide and will at times not reflect the actual asset allocation due to market conditions, actions of our investment managers and required cash flows to and from the Pension Plan.
The following table presents our target asset allocation permitted range along with the actual asset allocation as of December 31, 2023 and 2022:
Permitted Actual Allocation
Asset Class Range 2023 2022
Return Enhancement 35 - 60% 48 % 48 %
Risk Management 40 - 80% 51 51
Alternatives 0 - 20% 1 1
Total 100 % 100 %
Return Enhancement investments are those that seek to provide equity-like, long-term capital appreciation. Examples include equity securities, including dynamic asset allocation funds, and higher yielding fixed income securities, such as high yield bonds and emerging market debt.
Risk Management investments seek to decrease downside risk or act as a hedge against plan liabilities. Examples are cash and fixed income instruments.
Alternative investments seek to either provide return enhancement through long-term appreciation or risk management through decreased downside risk. The defining characteristic of these asset types is uncorrelated source of returns, less liquidity and private market access. Examples include investments in the SEI Energy Debt Collective Fund.
The following presents the fair value inputs classified within the fair value hierarchy used to measure Pension Plan assets at December 31, 2023 and 2022 and assets measured using the net asset value (NAV) practical expedient:
(in thousands) Level 1 Level 2 Level 3 NAV Total
December 31, 2023
Equity Funds $ 127,159 $ - $ - $ - $ 127,159
Fixed Income Funds 167,604 - - - 167,604
Hybrid Funds 10,980 - - - 10,980
U.S. Treasury Securities 23,218 - - - 23,218
SEI Energy Debt Collective Fund - - - 1,518 1,518
Total 328,961 - - 1,518 330,479
December 31, 2022
Equity Funds 124,327 - - - 124,327
Fixed Income Funds 156,424 - - - 156,424
Hybrid Funds 9,756 - - - 9,756
U.S. Treasury Securities 19,587 - - - 19,587
SEI Energy Debt Collective Fund - - - 3,703 3,703
Total $ 310,094 $ - $ - $ 3,703 $ 313,797
The investments held by the SEI Energy Debt Collective Fund on December 31, 2023 and 2022 consist mainly of below investment grade high yield bonds and loans of U.S. energy companies which trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice
period, subject to fund director consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on subscriptions. The fund’s assets are valued in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent third-party sources, although SEI in its discretion may use other valuation methods, subject to compliance with ERISA, as applicable. On an annual basis, as determined by the investment manager in its sole discretion, an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of the fund.
Funded Status. The following table provides a reconciliation of the changes in the fair value of plan assets and the actuarially computed benefit obligation for the years ended December 31, 2023 and 2022 and the funded status of the plans as of December 31, 2023 and 2022:
Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits
(in thousands) 2023 2022 2023 2022 2023 2022
Change in Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1 $ 313,797 $ 387,212 $ - $ - $ - $ -
Actual Return on Plan Assets 34,196 (76,485) - - - -
Company Contributions - 20,000 2,197 2,205 3,167 2,294
Benefit Payments (17,514) (16,930) (2,197) (2,205) (8,900) (8,173)
Participant Premium Payments - - - - 5,733 5,879
Fair Value of Plan Assets at December 31 330,479 313,797 - - - -
Change in Benefit Obligation:
Benefit Obligation at January 1 308,055 416,697 35,624 46,840 49,947 69,311
Service Cost 3,698 6,576 72 195 565 1,338
Interest Cost 16,436 12,344 1,889 1,341 2,416 2,041
Benefit Payments (17,514) (16,930) (2,197) (2,205) (8,900) (8,172)
Participant Premium Payments - - - - 5,733 5,879
Plan Amendments - - - - (17,493) -
Actuarial (Gain) Loss
8,126 (110,632) 392 (10,547) (2,123) (20,450)
Benefit Obligation at December 31 318,801 308,055 35,780 35,624 30,145 49,947
Funded Status $ 11,678 $ 5,742 $ (35,780) $ (35,624) $ (30,145) $ (49,947)
Amounts Recognized in Consolidated Balance Sheets at December 31:
Noncurrent Assets $ 11,678 $ 5,742 $ - $ - $ - $ -
Current Liabilities - - (2,679) (2,414) (2,469) (2,970)
Noncurrent Liabilities and Deferred Credits - - (33,101) (33,210) (27,676) (46,977)
Net Asset (Liability) $ 11,678 $ 5,742 $ (35,780) $ (35,624) $ (30,145) $ (49,947)
The accumulated benefit obligation of our Pension Plan was $288.8 million and $283.2 million as of December 31, 2023 and 2022. The accumulated benefit obligation of our ESSRP was $35.8 million and $35.6 million as of December 31, 2023 and 2022.
In 2023, the Company amended its postretirement healthcare plan to eliminate, for Medicare-eligible participants, the employer-sponsored group waiver medical plan and instead allow participants to select an individual medical plan through a private marketplace exchange. The Company now provides these plan participants with an annual reimbursement to subsidize their medical premiums. The effect of the plan amendment reduced the Company’s projected benefit obligation by $20.1 million. The reduced benefit obligation included a $2.6 million reduction attributable to an increase in the discount rate used to measure the plan liability, which was 6.06% at the time of the amendment, compared to 5.52% used at December 31, 2022. The $17.5 million of savings attributable to the plan change is being recognized as a reduction to expense over 4.8 years, the expected remaining service period to retirement-age eligibility for active participants.
The following assumptions were used to determine benefit obligations as of December 31, 2023 and 2022:
Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits
2023 2022 2023 2022 2023 2022
Discount Rate 5.57 % 5.51 % 5.53 % 5.51 % 5.53 % 5.52 %
Long-Term Rate of Compensation Increase
n/a n/a 3.00 % 3.00 % n/a n/a
Participants up to Age 39(1)
4.50 % 4.50 % n/a n/a n/a n/a
Participants Ages 40 to 49(2)
4.50 % 3.50 % n/a n/a n/a n/a
Participants Age 50 and Older(3)
3.75 % 2.75 % n/a n/a n/a n/a
Healthcare Cost Immediate Trend Rate n/a n/a n/a n/a 6.97 % 7.50 %
Healthcare Cost Ultimate Trend Rate n/a n/a n/a n/a 4.00 % 4.00 %
Year the Rate Reaches the Ultimate Trend Rate n/a n/a n/a n/a 2048 2048
(1) Amount reflects rate of compensation increases for both union and non-union employees.
(2) Amount reflects rate of compensation increases for union employees. The rate of compensation increases for non-union employees is 3.50%.
(3) Amount reflects rate of compensation increases for union employees. The rate of compensation increases for non-union employees is 3.00%.
The measurement of the plan asset or benefit obligation recognized for our Pension Plan, ESSRP and postretirement healthcare benefit plan included the following significant actuarial adjustments:
•For the Pension Plan, an increase in the discount rate in 2023 and 2022 reduced our obligation by $2.2 million and $117.1 million. Changes in retirement rate, percentage married, spouse age, benefit election, benefit commencement age and wage assumptions increased our benefit obligation in 2023 by $7.9 million. Changes in plan participant census data increased our benefit obligation by $3.1 million in 2023. Actual returns on Pension Plan assets in 2023 were $34.2 million, compared to an expected return of $25.9 million, impacting our obligation by $8.3 million.
•For the ESSRP, an increase in the discount rate in 2023 and 2022 reduced our obligation by $0.1 million and $10.2 million.
•For the postretirement healthcare plan, a plan amendment during 2023, as described above, decreased our benefit obligation by $17.5 million. An increase in the discount rate in 2023 and 2022 reduced our obligation by $1.3 million and $17.9 million. Revised estimates of healthcare cost trends and participant contribution assumptions increased the benefit obligation by $1.1 million in 2023.
Net Periodic Benefit Cost. A portion of service cost may be capitalized as a cost of self-constructed property, plant and equipment. When recognized in the consolidated statements of income, service cost is recognized within one of the components of operating expenses. Nonservice cost components of net periodic benefit cost may be deferred and recognized as a regulatory asset under the accounting guidance for regulated operations. When recognized in the consolidated statements of income, nonservice cost components are recognized as nonservice cost components of postretirement benefits.
The following table lists the components of net periodic benefit cost of our defined benefit pension plans and other postretirement benefits for the years ended December 31, 2023, 2022 and 2021:
Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits
(in thousands) 2023 2022 2021 2023 2022 2021 2023 2022 2021
Service Cost $ 3,698 $ 6,576 $ 7,462 $ 72 $ 195 $ 187 $ 565 $ 1,338 $ 1,722
Interest Cost 16,436 12,344 11,660 1,889 1,341 1,228 2,416 2,041 1,891
Expected Return on Assets (25,914) (23,684) (22,359) - - - - - -
Amortization of Prior Service Cost - - - - - - (6,649) (5,733) (5,733)
Amortization of Net Actuarial Loss - 7,865 10,914 - 567 620 - 3,063 3,774
Net Periodic Benefit Cost $ (5,780) $ 3,101 $ 7,677 $ 1,961 $ 2,103 $ 2,035 $ (3,668) $ 709 $ 1,654
The following table includes the impact of regulation on the recognition of periodic benefit cost arising from pension and other postretirement benefits for the years ended December 31, 2023, 2022 and 2021:
(in thousands) 2023 2022 2021
Net Periodic Benefit Cost $ (7,487) $ 5,913 $ 11,366
Net Amount Amortized Due to the Effect of Regulation
1,225 1,121 21
Net Periodic Benefit Cost Recognized $ (6,262) $ 7,034 $ 11,387
The following assumptions were used to determine net periodic benefit cost for the years ended December 31, 2023, 2022 and 2021:
Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits
2023 2022 2021 2023 2022 2021 2023 2022 2021
Discount Rate 5.51 % 3.03 % 2.78 % 5.51 % 2.93 % 2.61 % 5.52 % 3.01 % 2.75 %
Long-Term Rate of Return on Plan Assets 7.00 % 6.30 % 6.51 % n/a n/a n/a n/a n/a n/a
Long-Term Rate of Compensation Increase n/a n/a n/a 3.00 % 3.00 % 3.00 % n/a n/a n/a
Participants to Age 39 4.50 % 4.50 % 4.50 % n/a n/a n/a n/a n/a n/a
Participants Ages 40 to 49 3.50 % 3.50 % 3.50 % n/a n/a n/a n/a n/a n/a
Participants Age 50 and Older 2.75 % 2.75 % 2.75 % n/a n/a n/a n/a n/a n/a
We develop our estimated discount rate through the use of a hypothetical bond portfolio method. This method derives the discount rate from the average yield of a collection of high credit quality bonds which produce cash flows similar to our anticipated future benefit payments. We estimate the assumed long-term rate of return on plan assets based primarily on asset category studies using historical market return and volatility data with forward-looking estimates based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market indices are incorporated into the return projections based on the actively managed structure of the investment programs and their records of achieving such returns historically.
The following table presents the amounts not yet recognized as components of net periodic benefit cost as of December 31, 2023 and 2022:
Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits
(in thousands) 2023 2022 2023 2022 2023 2022
Regulatory Assets (Liabilities):
Unrecognized Prior Service Cost
$ - $ - $ - $ - $ (18,845) $ (8,400)
Unrecognized Actuarial Loss 85,227 85,367 1,061 979 1,759 3,993
Net Regulatory Assets (Liabilities) 85,227 85,367 1,061 979 (17,086) (4,407)
Accumulated Other Comprehensive Income (Loss):
Unrecognized Prior Service Cost
- - - - 498 99
Unrecognized Actuarial Gain (Loss)
1,994 1,978 (1,403) (1,093) 707 818
Total Accumulated Other Comprehensive Income (Loss) $ 1,994 $ 1,978 $ (1,403) $ (1,093) $ 1,205 $ 917
Cash Flows. We did not make any contributions to our Pension Plan in 2023. We made discretionary contributions of $20.0 million and $10.0 million in 2022 and 2021. As of December 31, 2023, we had no minimum funding requirements for our Pension Plan. Contributions to our ESSRP and postretirement healthcare plan are equal to the benefits paid to plan participants.
The following reflects anticipated benefit payments to be paid in each of the next five years and in the aggregate for the five year period thereafter under our pension plans and postretirement healthcare plan:
(in thousands) 2024 2025 2026 2027 2028 2029-2033
Projected Pension Plan Benefit Payments $ 18,851 $ 19,274 $ 19,828 $ 20,318 $ 20,882 $ 110,291
Projected ESSRP Benefit Payments 2,747 2,697 2,823 2,994 2,938 14,437
Projected Postretirement Benefit Payments 2,469 2,497 2,544 2,547 2,476 12,045
Total $ 24,067 $ 24,468 $ 25,195 $ 25,859 $ 26,296 $ 136,773
401K Plan
We sponsor a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans totaled $7.8 million for 2023, $6.7 million for 2022 and $6.5 million for 2021.
11. Asset Retirement Obligations
We have recognized Asset Retirement Obligations (AROs) related to our coal-fired generation plants, natural gas combustion turbines, solar facility, and wind turbines. The cost of AROs include items such as site restoration, closure of ash pits, and removal of certain structures, generators, asbestos and storage tanks. We have other legal obligations associated with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement costs are individually and collectively immaterial. We have no assets legally restricted for the settlement of any AROs. As of December 31, 2023 and 2022, $0.1 million and $2.7 million, respectively, was included in other current liabilities and $36.4 million and $22.5 million, respectively, was included in other noncurrent liabilities in the consolidated balance sheets related to AROs.
A reconciliation of the carrying amounts of AROs for the years ended December 31, 2023 and 2022 is as follows:
(in thousands) 2023 2022
Beginning Balance $ 25,182 $ 24,191
New Obligations Recognized 4,506 -
Adjustments Due to Revisions in Cash Flow Estimates 8,394 -
Accrued Accretion 1,191 991
Settlements (2,796) -
Ending Balance $ 36,477 $ 25,182
12. Income Taxes
Income before income taxes for the years ended December 31, 2023, 2022 and 2021 consists entirely of domestic earnings.
The provision for income taxes charged to income for the years ended December 31, 2023, 2022 and 2021 consisted of the following:
(in thousands) 2023 2022 2021
Current
Federal Income Taxes $ 41,253 $ 31,949 $ 6,806
State Income Taxes 15,126 9,568 939
Deferred
Federal Income Taxes 9,832 22,480 18,180
State Income Taxes 3,676 9,943 10,716
Tax Credits
North Dakota Wind Tax Credit Amortization, Net of Federal Tax (586) (586) (586)
Investment Tax Credit Amortization (3) (3) (3)
Total $ 69,298 $ 73,351 $ 36,052
The reconciliation of the statutory federal income tax rate to our effective tax rate for each of the years ended December 31, 2023, 2022 and 2021 is as follows:
2023 2022 2021
Income Taxes at Federal Statutory Rate $ 76,332 21.0 % $ 75,082 21.0 % $ 44,692 21.0 %
Increases (Decreases) in Tax from:
State Taxes on Income, Net of Federal Tax 14,429 4.0 15,049 4.2 9,962 4.7
Production Tax Credits (PTCs) (17,394) (4.8) (14,985) (4.2) (12,503) (5.9)
Amortization of Excess Deferred Income Taxes (2,205) (0.6) (1,625) (0.5) (4,262) (2.0)
North Dakota Wind Tax Credit Amortization, Net of Federal Tax (586) (0.2) (586) (0.2) (586) (0.3)
Other, Net (1,278) (0.3) 416 0.2 (1,251) (0.6)
Income Taxes at Effective Tax Rate $ 69,298 19.1 % $ 73,351 20.5 % $ 36,052 16.9 %
PTCs, North Dakota wind tax credits, and excess deferred income taxes related to the federal tax rate reduction in the 2017 Tax Cuts and Jobs Act are returned to customers as a reduction of the rates they are charged and result in a reduction of operating revenues.
Deferred tax assets and liabilities were composed of the following on December 31, 2023 and 2022:
(in thousands) 2023 2022
Deferred Tax Assets
Employee Benefits $ 39,959 $ 39,216
Regulatory Liabilities 56,479 57,353
Tax Credit Carryforwards
21,836 20,209
Cost of Removal 32,993 37,360
Asset Retirement Obligations
9,494 6,557
Net Operating Loss Carryforward
2,336 1,853
Other 11,310 5,550
Total Deferred Tax Assets 174,407 168,098
Deferred Tax Liabilities
Differences Related to Property (347,885) (334,201)
Retirement Benefits Regulatory Asset (22,458) (22,789)
Pension Expense (24,875) (24,269)
Other (16,462) (8,141)
Total Deferred Tax Liabilities (411,680) (389,400)
Deferred Income Taxes $ (237,273) $ (221,302)
The following is a schedule of tax credits and tax net operating losses available as of December 31, 2023 and the respective periods of expiration:
(in thousands) Amount 2024-2029 2030-2037 2038-2043
State Net Operating Losses $ 2,336 $ 211 $ 2,125 $ -
State Tax Credits 21,836 - - 21,836
The following table summarizes the activity for unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:
(in thousands) 2023 2022 2021
Balance on January 1 $ 923 $ 827 $ 771
Increases for tax positions taken during a prior period
596 44 11
Increases for tax positions taken during the current period 163 260 189
Decreases due to settlements with taxing authorities - - -
Decreases as a result of a lapse of applicable statutes of limitations (193) (208) (144)
Balance on December 31 $ 1,489 $ 923 $ 827
The balance of unrecognized tax benefits as of December 31, 2023 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2023 is not expected to change significantly within the next 12 months. We classify interest and penalties on tax uncertainties as components of the provision for income taxes in the consolidated statements of income.
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2023, with limited exceptions, we are no longer subject to examinations by taxing authorities for tax years prior to 2020 for federal and North Dakota income taxes and prior to 2019 for Minnesota state income taxes.
13. Commitments and Contingencies
Commitments
Construction and Other Commitments. As of December 31, 2023, we had commitments under contracts for construction project materials, equipment, plant maintenance, and other services extending into 2046 which totaled approximately $17.1 million.
Electric Utility Capacity and Energy Requirements. OTP has commitments for the purchase of capacity and energy requirements under contractual agreements, including wind power purchase agreements extending into 2048. Generally, the terms of OTP's wind power purchase agreements require OTP to purchase all of the electricity generated by a particular wind farm and do not include fixed or minimum payments. The required payments are variable and the amounts due are determined based upon the amount of electricity generated. Capacity and energy requirement costs under these agreements totaled $5.6 million, $13.1 million and $11.5 million for the years ended December 31, 2023, 2022 and 2021.
Coal Purchase Commitments. OTP has contracts providing for the purchase and delivery of its coal requirements. OTP’s current coal purchase agreement with CCMC for Coyote Station expires December 31, 2040. All of Coyote Station’s coal requirements for the period covered must be purchased under this agreement. The agreement is structured so that the price of the coal covers all of CCMC's operating, financing, and future
mine reclamation costs. In the table below we have estimated the future payments to be made under the terms of the agreement until its maturity. OTP has an agreement for the purchase of Big Stone Plant’s coal requirements through December 31, 2024. There is no fixed minimum purchase requirement, and no amounts for this agreement have been included in the table below; however, under this agreement all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement. Coal purchase costs under these two agreements totaled $43.7 million, $45.1 million and $40.4 million for the years ended December 31, 2023, 2022 and 2021.
Land Easement Payments. OTP has commitments to make payments for land easements not classified as leases. The contractual terms of these easements are generally 99 years or do not have a stated maturity date, however, per the terms of the agreements, our requirement to make payment ends once we cease use of the land. As such, in the table below, we have included payments under these easements through the estimated useful lives of the facilities associated with the easement. The commitments under these arrangements extend into 2055 and total approximately $62.4 million. Land easement costs under these agreements totaled $1.8 million, $1.4 million and $1.3 million for the years ended December 31, 2023, 2022 and 2021.
Our future commitments as of December 31, 2023 were as follows:
(in thousands) Construction Program
and Other Commitments Capacity and Energy
Requirements Coal Purchase
Commitments Land
Easement
Payments
2024 $ 4,374 $ 245 $ 24,691 $ 1,804
2025 4,051 217 24,593 1,840
2026 1,377 197 25,374 1,845
2027 594 197 25,786 1,882
2028 550 197 25,344 1,921
Beyond 2028 6,165 3,939 359,610 53,107
Total $ 17,111 $ 4,992 $ 485,398 $ 62,399
Contingencies
FERC ROE. In November 2013 and February 2015, customers filed complaints with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO tariff rate. FERC's most recent order, issued on November 19, 2020, adopted a revised ROE methodology and set the base ROE at 10.02% (10.52% with an adder) effective for the fifteen-month period from November 2013 to February 2015 and on a prospective basis beginning in September 2016. The order also dismissed any complaints covering the period from February 2015 to May 2016. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated the FERC order citing a lack of reasoned explanation by FERC in its adoption of its revised ROE methodology as outlined in its November 2020 order. The U.S. Court of Appeals remanded the matter to FERC to reopen the proceedings.
Significant uncertainty exists as to how FERC will proceed on remand and there is no prescribed timeline under which FERC must act. We have deferred recognition and recorded a refund liability of $2.8 million as of December 31, 2023. This refund liability reflects our best estimate of amounts previously collected from customers under the MISO tariff rate that may be required to be refunded to customers once all regulatory and judicial proceedings are complete and a final ROE is established for the periods outlined above.
Regional Haze Rule (RHR). The RHR was adopted in 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 plans to achieve natural visibility conditions. The second RHR implementation period covers the years 2018-2028. States are required to submit a state implementation plan (SIP) to assess reasonable progress with the RHR and determine what additional emission reductions are appropriate, if any.
Coyote Station, OTP's jointly owned coal-fired power plant in North Dakota, is subject to assessment in the second implementation period under the North Dakota SIP. The NDDEQ submitted its 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 has previously expressed disagreement with the NDDEQ's recommendation to forgo additional emission controls and has indicated that such a plan is not likely to be accepted.
We cannot predict with certainty the impact the SIP may have on our business until the SIP has been approved or otherwise acted on by the EPA. However, significant emission control investments could be required and the recovery of such costs from customers would require regulatory approval. Alternatively, investments in emission control equipment may prove to be uneconomic and result in the early retirement or the sale of our interest in Coyote Station, subject to regulatory approval. We cannot estimate the ultimate financial effects such a retirement or sale may have on our consolidated operating results, financial position or cash flows, but such amounts could be material and the recovery of such costs in rates would be subject to regulatory approval.
Self-Funding of Transmission Upgrades. The FERC has granted transmission owners within MISO the unilateral authority to determine the funding mechanism for interconnection transmission upgrades that are necessary to accommodate new generation facilities connecting to the electrical grid. Under existing FERC orders, transmission owners can unilaterally determine whether the generator pays the transmission owner in advance for the transmission upgrade or, alternatively, the transmission owner can elect to fund the upgrade and recover over time from the generator the cost of and a return on the upgrade investment (a self-funding). FERC’s orders granting transmission owners this unilateral funding authority has been judicially contested on the basis that transmission owners may be motivated to discriminate among generators in making
funding determinations. In the most recent judicial hearing, the petitioners argued to the U.S. Court of Appeals for the District of Columbia that FERC did not comply with a previous judicial order to fully develop a record regarding the risk of discrimination and the financial risk absorbed by transmission owners for generator-funded upgrades. On December 2, 2022, the Court of Appeals ruled in favor of the petitioners remanding the matter to FERC, instructing the agency to adequately explain the basis of its orders. The Court of Appeals decision did not vacate transmission owners’ unilateral funding authority.
OTP, as a transmission owner in MISO, has exercised its authority and elected to self-fund previous transmission upgrades necessary to accommodate new system generation. Under such an election, OTP is recovering the cost of the transmission upgrade and a return on that investment from the generator over a contractual period of time. Should FERC, on remand from the Court of Appeals, eliminate transmission owners’ unilateral funding authority, on either a prospective or retrospective basis, our financial results would be impacted. We cannot at this time reasonably predict the outcome of this matter given the uncertainty as to how and when FERC may respond to the judicial remand.
Other Contingencies. We are party to litigation and regulatory enforcement matters arising in the normal course of business. We regularly analyze relevant information and, as necessary, estimate and record accrued liabilities for matters in which a loss is probable of occurring and can be reasonably estimated. We believe the effect on our consolidated operating results, financial position and cash flows, if any, for the disposition of all matters pending as of December 31, 2023 will not be material.
14. Stockholders' Equity
Capital Structure
In addition to authorized and outstanding common stock, the Company has 1,500,000 authorized no par value cumulative preferred shares and 1,000,000 authorized no par value cumulative preference shares. No cumulative preferred or cumulative preference shares were outstanding at December 31, 2023 or 2022.
Shelf Registrations
On May 3, 2021, upon the expiration of a prior shelf registration, we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement expires in May 2024. No shares were issued pursuant to the shelf registration in 2023.
On May 3, 2021, upon the expiration of a prior shelf registration, we filed a registration statement with the SEC for the issuance of up to 1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends and/or making optional cash investments. Shares purchased under the plan may be new issue common shares or common shares purchased on the open market. In 2023, we issued 105,663 common shares under this program and no proceeds were received, as all shares issued were purchased on the open market. As of December 31, 2023, 1,145,330 shares remained available for purchase or issuance under the plan. The shelf registration for the plan expires in May 2024.
Dividend Restrictions
OTC is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to our shareholders is from intercompany distributions made by OTC's subsidiaries to OTC. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC's subsidiaries. Both the OTC Credit Agreement and OTP Credit Agreement contain restrictions on the payment of cash dividends upon a default or event of default, including failure to maintain certain financial covenants. As of December 31, 2023, we were in compliance with these financial covenants.
Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act and the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as i) the source of the dividends is clearly disclosed, ii) the dividend is not excessive and iii) there is no self-dealing on the part of corporate officials.
The MPUC indirectly limits the amount of dividends OTP can pay to OTC by requiring an equity-to-total-capitalization ratio between 48.3% and 59.1%, with total capitalization not to exceed $2.0 billion based on OTP’s capital structure requirements as of December 31, 2023. As of December 31, 2023, OTP’s equity-to-total-capitalization ratio including short-term debt was 54.2% and its net assets restricted from distribution totaled approximately $771.3 million.
15. Accumulated Other Comprehensive Income (Loss)
The Company's other comprehensive income (loss) consists of unamortized actuarial losses and prior service costs related to pension and other postretirement benefits and unrealized gains and losses on marketable securities classified as available-for-sale. The income tax expense or benefit associated with amounts reclassified from accumulated other comprehensive income (loss) and reflected in the consolidated statement of income are recognized in the same period as the amounts are reclassified.
The following table shows the changes in accumulated other comprehensive Income (loss) for the years ended December 31, 2023, 2022 and 2021:
(in thousands) Pension and Other Postretirement Benefits Net Unrealized Gain (Losses) on Available-for-Sale Securities Total
Balance, December 31, 2020
$ (8,716) $ 209 $ (8,507)
Other Comprehensive Income (Loss) Before Reclassifications, net of tax
1,638 (132) 1,506
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 541 (1)
(64) (2)
Total Other Comprehensive Income (Loss) 2,179 (196) 1,983
Balance, December 31, 2021
(6,537) 13 (6,524)
Other Comprehensive Income (Loss) Before Reclassifications, net of tax 7,331 (433) 6,898
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 540 (1)
1 (2)
Total Other Comprehensive Income (Loss) 7,871 (432) 7,439
Balance, December 31, 2022
1,334 (419) 915
Other Comprehensive Income Before Reclassifications, net of tax
59 180 239
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (18) (1)
12 (2)
(6)
Total Other Comprehensive Income
41 192 233
Balance, December 31, 2023
$ 1,375 $ (227) $ 1,148
(1) Included in the computation of net periodic pension and other postretirement benefit costs. See Note 10 for further information.
(2) Included in other income (expense), net on the accompanying consolidated statements of income.
16. Share-Based Payments
Employee Stock Purchase Plan
The 1999 Employee Stock Purchase Plan authorizes the issuance of 1,400,000 common shares, allowing eligible employees to purchase our common shares through payroll withholding at a discount of up to 15% off the market price at the end of each six-month purchase period. Employee withholding amounts may not be less than $10 or more than $2,000 per month, subject to certain limitations, as described in the plan. A plan participant may cease making payroll deductions at any time. A participant may not purchase more than 2,000 shares in a given six month purchase period under the plan and may not purchase more than $25,000 (fair market value) of common shares under the plan and all other purchase plans (if any) in a calendar year. A participant may withdraw from the plan at any time and elect to receive the balance of their contributions to the plan that have not yet been used to purchase shares. Shares purchased under the plan are automatically enrolled in the Company's dividend reinvestment plan. Shares purchased under the plan may not be assigned, transferred, pledged, or otherwise disposed, except for certain situations allowed by the plan, such as upon death, for a period of 18 months after purchase. At our discretion, shares purchased under the plan can be either new issue shares or shares purchased in the open market. The plan shall automatically terminate when all of the shares authorized under the plan have been issued.
We recognize the 15% discount to the fair market value of the purchased shares as stock-based compensation expense, which amounted to $0.3 million, $0.3 million and $0.2 million for the years ended December 31, 2023, 2022 and 2021. For the years ended December 31, 2023, 2022 and 2021 the amount of shares issued under the plan amounted to 26,348, 26,420 and 27,975 shares. As of December 31, 2023, there were 237,367 shares available for purchase under the plan.
Share-Based Compensation Plan
The 2023 Stock Incentive Plan, which was approved by our shareholders in April 2023, authorizes the issuance of 979,891 common shares, including 500,000 newly requested common shares, for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalents, performance awards and other stock-based awards. In addition, common shares subject to any outstanding awards under our prior stock incentive plans that are forfeited, canceled or reacquired by the Company will become available for re-issuance under the 2023 Stock Incentive Plan. As of December 31, 2023, 943,192 shares were available for issuance under the plan. The plan terminates on April 17, 2033.
We grant restricted stock awards to our employees and members of our Board of Directors and stock performance awards to our executive officers and certain other key employees as part of our long-term compensation and retention program. Stock-based compensation cost, recognized within operating expenses in the consolidated statements of income, amounted to $7.4 million, $6.6 million and $6.7 million for the years ended December 31, 2023, 2022 and 2021. The related income tax benefit recognized for these periods amounted to $1.6 million, $1.7 million and $1.8 million.
Restricted Stock Awards. Restricted stock awards are granted to executive officers and other key employees and members of the Company's Board of Directors. The awards vest, depending on award recipient, either ratably over a period of three to four years or cliff vest after four years. Vesting is accelerated in certain circumstances, including upon retirement. Awards granted to members of the Board of Directors are issued and outstanding upon grant and carry the same voting and dividend rights of unrestricted outstanding common stock. Awards granted to executive officers and other key employees are eligible to receive dividend equivalent payments during the vesting period, subject to forfeiture under the terms of the agreement, but such awards are not issued or outstanding upon grant and do not provide for voting rights.
The grant-date fair value of each restricted stock award is determined based on the market price of the Company's common stock on the date of grant adjusted to exclude the value of dividends for those awards that do not receive dividend or dividend equivalent payments during the vesting period.
The following is a summary of restricted stock award activity for the year ended December 31, 2023:
Shares Weighted-Average
Grant-Date
Fair Value
Nonvested, Beginning of Year 141,551 $ 49.83
Granted 55,205 68.03
Vested (45,493) 50.02
Forfeited (2,350) 52.02
Nonvested, End of Year 148,913 $ 56.48
The weighted-average grant-date fair value of granted awards was $68.03, $59.95 and $43.55 during the years ended December 31, 2023, 2022 and 2021. The fair value of vested awards was $3.1 million, $3.0 million and $2.1 million during the years ended December 31, 2023, 2022 and 2021. As of December 31, 2023, there was $3.4 million of unrecognized compensation cost for unvested restricted stock awards to be recognized over a weighted-average period of 1.7 years.
Stock Performance Awards. Stock performance awards are granted to executive officers and certain other key employees. The awards vest at the end of a three-year performance period. The number of common shares awarded, if any, at the end of the performance period ranges from zero to 150% of the target amount based on two performance measures: i) total shareholder return relative to a peer group (TSR component) and ii) return on equity (ROE component). The awards have no voting or dividend rights during the vesting period. Vesting of the awards is accelerated in certain circumstances, including upon retirement. The amount of common shares awarded on an accelerated vesting is based on actual performance at the end of the performance period.
The grant-date fair value of the ROE component of the stock performance awards granted during the years ended December 31, 2023, 2022 and 2021 was determined using the grant date stock price and a discounted cash flow analysis to adjust for expected unearned dividends during the vesting period. The grant-date fair value of the TSR component of the stock performance awards granted during the years ended December 31, 2023, 2022 and 2021 was determined using a Monte Carlo fair value simulation model incorporating the following assumptions:
2023 2022 2021
Risk-free interest rate 4.15 % 1.52 % 0.18 %
Expected term (in years) 3.00 3.00 3.00
Expected volatility 34.00 % 32.00 % 32.00 %
Dividend yield 2.50 % 2.90 % 3.60 %
The risk-free interest rate was derived from yields on U.S. government bonds of a similar term. The expected term of the award is equal to the three-year performance period. Expected volatility was estimated based on actual historical volatility of our common stock over a five-year period. Dividend yield was estimated based on historic and future yield estimates.
The following is a summary of stock performance award activity for the year ended December 31, 2023 (share amounts reflect awards at target):
Shares Weighted-Average
Grant-Date
Fair Value
Nonvested, Beginning of Year 189,800 $ 45.95
Granted 59,400 61.97
Vested (55,000) 47.79
Forfeited - -
Nonvested, End of Year 194,200 $ 50.33
The weighted-average grant-date fair value of granted awards was $61.97, $54.91 and $38.34 during the years ended December 31, 2023, 2022 and 2021. The fair value of vested awards was $5.3 million, $5.1 million and $2.5 million during the years ended December 31, 2023, 2022 and
2021. As of December 31, 2023, there was $0.4 million of unrecognized compensation cost of unvested stock performance awards to be recognized over a weighted-average period of 0.67 years.
17. Earnings Per Share
The numerator used in the calculation of both basic and diluted earnings per share is net income. The denominator used in the calculation of basic earnings per share is the weighted-average number of shares outstanding during the period. The denominator used in the calculation of diluted earnings per share is derived by adjusting basic shares outstanding for the dilutive effect of potential shares outstanding, which consist of shares associated with time and performance based stock awards and our employee stock purchase plan.
The following includes the computation of the denominator for basic and diluted weighted-average shares outstanding for the years ended December 31, 2023, 2022 and 2021:
(in thousands) 2023 2022 2021
Weighted Average Common Shares Outstanding - Basic 41,668 41,586 41,491
Effect of Dilutive Securities:
Stock Performance Awards 269 248 226
Restricted Stock Awards 100 95 87
Employee Stock Purchase Plan Shares and Other 2 2 14
Dilutive Effect of Potential Common Shares 371 345 327
Weighted Average Common Shares Outstanding - Diluted 42,039 41,931 41,818
The amount of shares excluded from diluted weighted-average common shares outstanding because such shares were anti-dilutive was not material for the years ended December 31, 2023, 2022 and 2021.
18. Derivative Instruments
OTP enters into derivative instruments to manage its exposure to future commodity price variability, specifically future wholesale energy and natural gas prices, and reduce volatility in prices for our retail electric customers. These derivative instruments are not designated as qualifying hedging transactions but provide for an economic hedge against future price variability. The instruments are recorded at fair value on the consolidated balance sheets, with changes in fair value recorded in the consolidated statements of income. However, in accordance with rate-making and cost recovery processes, we recognize a regulatory asset or liability to defer losses or gains from derivative activity until settlement of the associated derivative instrument.
As of December 31, 2023 and 2022 OTP had outstanding pay-fixed, receive-variable swap agreements with an aggregate notional amount of 187,400 and 295,000 megawatt-hours of electricity. The contracts outstanding as of December 31, 2023 had various settlement dates throughout 2024. As of December 31, 2023 and 2022, the fair value of these derivative instruments was $4.2 million and $7.1 million, which are included in other current liabilities on the consolidated balance sheets. During the years ended December 31, 2023 and 2022, contracts matured and were settled in an aggregate amount of a $16.5 million loss and a $1.0 million gain, respectively. Gains and losses recognized on the settlement of derivative instruments are returned to, or recovered from, our electric customers through fuel recovery mechanisms in each state. When recognized in the statement of income, these gains or losses are included in electric purchased power.
19. Fair Value Measurements
The following tables present our assets measured at fair value on a recurring basis as of December 31, 2023 and 2022 classified by the input method used to measure fair value:
Level 1 Level 2 Level 3
December 31, 2023
Assets
Investments:
Money Market Funds $ 3,125 $ - $ -
Mutual Funds 7,771 - -
Corporate Debt Securities - 1,579 -
Government Debt Securities
- 7,724 -
Total Assets 10,896 9,303 -
Liabilities
Derivative Instruments - 4,210 -
Total Liabilities $ - $ 4,210 $ -
December 31, 2022
Assets
Investments:
Money Market Funds $ 1,560 $ - $ -
Mutual Funds 5,503 - -
Corporate Debt Securities - 1,434 -
Government Debt Securities
- 7,327 -
Total Assets $ 7,063 $ 8,761 $ -
Liabilities
Derivative Instruments - 7,130 -
Total Liabilities
$ - $ 7,130 $ -
The level 2 fair value measurements for government and corporate debt securities are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
The level 2 fair value measurements for derivative instruments are determined by using inputs such as forward electric commodity prices, adjusted for location differences. These inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.
In addition to assets recorded at fair value on a recurring basis, we also hold financial instruments that are not recorded at fair value in the consolidated balance sheets but for which disclosure of the fair value of these financial instruments is provided. The following reflects the carrying value and estimated fair value of these assets and liabilities as of December 31, 2023 and 2022:
December 31, 2023 December 31, 2022
(in thousands) Carrying
Amount Fair Value Carrying
Amount Fair Value
Assets:
Cash and Cash Equivalents $ 230,373 $ 230,373 $ 118,996 $ 118,996
Total 230,373 230,373 118,996 118,996
Liabilities:
Short-Term Debt 81,422 81,422 8,204 8,204
Long-Term Debt 824,059 710,839 823,821 681,615
Total $ 905,481 $ 792,261 $ 832,025 $ 689,819
The following methods and assumptions were used to estimate the fair value of each class of financial instruments:
Cash Equivalents: The carrying amount approximates fair value because of the short-term maturity of these instruments.
Short-Term Debt: The carrying amount approximates fair value because the debt obligations are short-term in nature and balances outstanding are subject to variable rates of interest which reset frequently, a Level 2 fair value input.
Long-Term Debt: The fair value of long-term debt is estimated based on current market indications for borrowings of similar maturities with similar terms, a Level 2 fair value input.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosures Controls and Procedures. Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of December 31, 2023, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023.
Changes in Internal Control over Financial Reporting. There were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) during the fourth quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report Regarding Internal Control Over Financial Reporting. Management is responsible for the preparation and integrity of the consolidated financial statements and representations in this report on Form 10-K. The consolidated financial statements of the Company have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and include some amounts that are based on informed judgments and best estimates and assumptions of management.
In order to assure the consolidated financial statements are prepared in conformance with generally accepted accounting principles, management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). These internal controls are designed only to provide reasonable assurance, on a cost-effective basis, that transactions are carried out in accordance with management’s authorizations and assets are safeguarded against loss from unauthorized use or disposition.
Management has completed its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013) to conduct the required assessment of the effectiveness of the Company’s internal control over financial reporting. Based on this assessment, management concluded that, as of December 31, 2023, the Company’s internal control over financial reporting was effective based on those criteria. The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has audited the Company’s consolidated financial statements included in this report on Form 10-K and issued an attestation report on the Company’s internal control over financial reporting.
Attestation Report of Independent Registered Public Accounting Firm. The attestation report of Deloitte & Touche LLP, the Company’s independent registered public accounting firm, regarding the Company’s internal control over financial reporting is provided in Item 8 of this report on Form 10-K.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item regarding Directors is incorporated by reference to the information under “Election of Directors” in the Company's definitive Proxy Statement for the 2024 Annual Meeting. The information regarding executive officers and family relationships is set forth in Item 3A of this report on Form 10-K. The information required by this Item regarding the Company’s procedures for recommending nominees to the board of directors is incorporated by reference to the information under “Corporate Governance - Director Nomination Process” in the Company’s definitive Proxy Statement for the 2024 Annual Meeting. The information required by this Item regarding the Audit Committee and the Company’s Audit Committee financial experts is incorporated by reference to the information under “Committees of the Board of Directors - Audit Committee” in the Company’s definitive Proxy Statement for the 2024 Annual Meeting.
The Company has adopted a code of business ethics that applies to all of its directors, officers (including its principal executive officer, principal financial officer, and its principal accounting officer or controller or person performing similar functions) and employees. The Company’s code of business ethics is available on its website at www.ottertail.com. The Company intends to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of its code of business ethics by posting such information on its website at the address specified above. Information on the Company’s website is not deemed to be incorporated by reference into this report on Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information under “Compensation Discussion and Analysis”, “Report of Compensation and Human Capital Management Committee”, “Executive Compensation”, “Pay Ratio Disclosure” and “Director Compensation” in the Company's definitive Proxy Statement for the 2024 Annual Meeting.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item regarding security ownership is incorporated by reference to the information under “Security Ownership of Certain Beneficial Owners” in the Company’s definitive Proxy Statement for the 2024 Annual Meeting.
The following table sets forth information as of December 31, 2023 about the Company’s common stock that may be issued under all its equity compensation plans:
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights Weighted average
exercise price of
outstanding
options, warrants
and rights Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected in
column (a))
Plan Category (a) (b) (c)
Equity compensation plans approved by security holders:
2023 Stock Incentive Plan
409,880 (1) N/A
943,192 (2)
1999 Employee Stock Purchase Plan - N/A 237,367 (3)
Equity compensation plans not approved by security holders - - -
Total 409,880 - 1,180,559
(1)Includes 89,100, 83,700 and 118,500 performance-based share awards, assuming a maximum payout, granted in 2023, 2022 and 2021, respectively, and 118,580 restricted stock units outstanding as of December 31, 2023.
(2)The 2023 Stock Incentive Plan provides for the issuance of any shares available under the plan in the form of restricted stock, restricted stock units, performance awards and other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights.
(3)Shares to be issued based on employee’s election to participate in the plan.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the information under “Policy and Procedures Regarding Transactions with Related Persons”, “Election of Directors” and “Committees of the Board of Directors” in the Company’s definitive Proxy Statement for the 2024 Annual Meeting.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the information under “Ratification of Independent Registered Public Accounting Firm - Fees” and “Ratification of Independent Registered Public Accounting Firm - Pre-Approval of Audit/Non-Audit Services Policy” in the Company’s definitive Proxy Statement for the 2024 Annual Meeting.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
1. Financial Statements
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
Schedule I - Condensed Financial Information of Registrant
Schedule II - Valuation and Qualifying Accounts and Reserves
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED BALANCE SHEETS
December 31,
(in thousands) 2023 2022
Assets
Current Assets
Cash and Cash Equivalents $ 228,137 $ 119,246
Accounts Receivable from Subsidiaries 2,555 3,278
Interest Receivable from Subsidiaries 117 117
Other 977 1,045
Total Current Assets 231,786 123,686
Investments in Subsidiaries 1,725,584 1,463,998
Notes Receivable from Subsidiaries 78,900 78,900
Deferred Income Taxes 65,244 64,802
Other Assets 50,795 43,779
Total Assets $ 2,152,309 $ 1,775,165
Liabilities and Stockholders' Equity
Current Liabilities
Accounts Payable to Subsidiaries $ 7 $ 7
Notes Payable to Subsidiaries 568,672 420,363
Other 15,320 15,994
Total Current Liabilities 583,999 436,364
Other Noncurrent Liabilities 45,455 41,686
Commitments and Contingencies
Capitalization
Long-Term Debt
79,849 79,798
Common Stockholders' Equity 1,443,006 1,217,317
Total Capitalization 1,522,855 1,297,115
Total Liabilities and Stockholders' Equity $ 2,152,309 $ 1,775,165
See accompanying notes to condensed financial statements.
OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF INCOME
Years Ended December 31,
(in thousands) 2023 2022 2021
Income
Equity Income in Earnings of Subsidiaries $ 294,467 $ 296,833 $ 188,375
Interest Income from Subsidiaries 2,898 3,382 2,826
Other Income 10,496 466 1,290
Total Income 307,861 300,681 192,491
Expense
Nonelectric Selling, General, and Administrative Expenses 12,816 17,269 14,825
Interest Expense
3,813 4,066 4,727
Interest Expense from Subsidiaries
6 5 3
Nonservice Cost Components of Postretirement Benefits 1,063 1,023 1,097
Total Expense 17,698 22,363 20,652
Income Before Income Taxes 290,163 278,318 171,839
Income Tax Benefit 4,028 5,866 4,930
Net Income $ 294,191 $ 284,184 $ 176,769
See accompanying notes to condensed financial statements.
OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOWS
Years Ended December 31,
(in thousands) 2023 2022 2021
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities $ 77,139 $ 28,807 $ 60,695
Cash Flows from Investing Activities
Investment in Subsidiaries (40,000) (50,000) -
Debt Repaid by Subsidiaries - - 169
Other, net (68) (1,695) (884)
Net Cash Used in Investing Activities (40,068) (51,695) (715)
Cash Flows from Financing Activities
Net (Repayments) Borrowings on Short-Term Debt - (22,637) (42,529)
Borrowings from Subsidiaries 148,308 236,926 49,085
Proceeds from Issuance of Common Stock - - 696
Payments for Shares Withheld for Employee Tax Obligations (3,088) (2,942) (1,507)
Payments for Retirement of Long-Term Debt - - (169)
Dividends Paid (73,061) (68,755) (64,864)
Other, net (339) (461) (689)
Net Cash Provided by (Used in) Financing Activities 71,820 142,131 (59,977)
Net Change in Cash and Cash Equivalents 108,891 119,243 3
Cash and Cash Equivalents at Beginning of Period 119,246 3 -
Cash and Cash Equivalents at End of Period $ 228,137 $ 119,246 $ 3
See accompanying notes to condensed financial statements.
OTTER TAIL CORPORATION (PARENT COMPANY)
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by Reference
OTC’s consolidated statements of comprehensive income and common shareholders’ equity in Part II, Item 8 are incorporated by reference.
Basis of Presentation
The condensed financial information of OTC is presented to comply with Rule 12-04 of Regulation S-X. The unconsolidated condensed financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance with generally accepted accounting principles. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included in this report on Form 10-K.
OTC’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity income in earnings of subsidiaries.
Related Party Transactions
Outstanding receivables from and payables to OTC's subsidiaries as of December 31, 2023 and 2022 are as follows:
(in thousands) Accounts
Receivable Interest
Receivable Long-Term
Notes
Receivable Accounts
Payable Current
Notes
Payable
December 31, 2023
Otter Tail Power Company $ 2,415 $ - $ - $ 7 $ -
Northern Pipe Products, Inc. - 7 5,000 - 56,917
Vinyltech Corporation 14 17 11,500 - 98,016
BTD Manufacturing, Inc. - 78 52,000 - 6,291
T.O. Plastics, Inc. 36 15 10,400 - 980
Varistar Corporation - - - - 406,468
Otter Tail Assurance Limited 90 - - - -
$ 2,555 $ 117 $ 78,900 $ 7 $ 568,672
December 31, 2022
Otter Tail Power Company $ 3,016 $ - $ - $ 7 $ -
Northern Pipe Products, Inc. - 7 5,000 - 77,182
Vinyltech Corporation - 18 11,500 - 90,425
BTD Manufacturing, Inc. - 77 52,000 - 693
T.O. Plastics, Inc. 20 15 10,400 - 5,855
Varistar Corporation - - - - 246,208
Otter Tail Assurance Limited 242 - - - -
$ 3,278 $ 117 $ 78,900 $ 7 $ 420,363
Dividends
Dividends paid to OTC (the Parent) from its subsidiaries were as follows:
(in thousands) 2023 2022 2021
Cash Dividends Paid to Parent by Subsidiaries $ 72,982 $ 68,680 $ 64,790
See OTC’s notes to consolidated financial statements in Part II, Item 8 for other disclosures.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
OTTER TAIL CORPORATION
Below is a summary of activity within valuation and qualifying accounts for the years ended December 31, 2023, 2022 and 2021:
(in thousands) Balance, January 1 Charged to Cost and Expenses Deductions 1, 2
Balance, December 31
Allowance for Credit Losses
2023 $ 1,648 $ 2,014 $ (1,140) $ 2,522
2022 1,836 909 (1,097) 1,648
2021 3,215 93 (1,472) 1,836
Deferred Tax Asset Valuation Allowance
2023 $ - $ - $ - $ -
2022 - - - -
2021 800 - (800) -
1Amounts under Allowance for Credit Losses reflect deductions to the allowance for amounts written-off, net of recoveries.
2Amounts under Deferred Tax Asset Valuation Allowance reflect a release of a valuation allowance based on current expectations of the realizability of the associated deferred tax asset.
3. Exhibits
The following Exhibits are filed as part of, or incorporated by reference into, this report.
No. Description
3.1 Third Restated Articles of Incorporation, dated April 12, 2021.
3.2 Restated Bylaws, dated April 12, 2021.
4.1 Description of Securities
10.1.0 Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein.
10.1.1 First Amendment, dated as of December 14, 2007, to Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein.
10.1.2 Second Amendment, dated as of September 11, 2008, to Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein.
10.1.3 Third Amendment, dated as of June 26, 2009, to Note Purchase Agreement dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein.
10.2 Note Purchase Agreement dated as of August 14, 2013 between Otter Tail Power Company and the Purchasers named therein.
10.3 Note Purchase Agreement dated as of September 23, 2016 between Otter Tail Corporation and the Purchasers named therein.
10.4 Note Purchase Agreement dated as of November 14, 2017 between Otter Tail Power Company and the Purchasers named therein.
10.5 Note Purchase Agreement dated as of September 12, 2019 between Otter Tail Power Company and the Purchasers named therein.
10.6 Note Purchase Agreement dated as of June 10, 2021 between Otter Tail Power Company and the Purchasers named therein.
10.7 Fifth Amended and Restated Credit Agreement, dated as of October 31, 2022, by and between Otter Tail Corporation, as Borrower, and the banks named therein, with U.S. Bank National Association, as Administrative Agent.
10.8 Fourth Amended and Restated Credit Agreement, dated as of October 31, 2022, by and between Otter Tail Power Company, as Borrower, and the banks named therein, with U.S. Bank Nation Association, as Administration Agent.
10.9.0 Agreement for Sharing Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and Northwestern Public Service Company (dated as of January 7, 1970). Previously filed as Exhibit 10-F in Form 10-K for the year ended December 31, 1989.
10.9.1 Letter of Intent for purchase of share of Big Stone Plant from Northwestern Public Service Company (dated as of May 8, 1984). Previously filed as Exhibit 10-F-1 in Form 10-K for the year ended December 31, 1989.
10.9.2 Supplemental Agreement No. 1 to Agreement for Sharing Ownership of Big Stone Plant (dated as of July 1, 1983). Previously filed as Exhibit 10-F-2 in Form 10-K for the year ended December 31, 1991.
10.9.3 Supplemental Agreement No. 2 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 1, 1985). Previously filed as Exhibit 10-F-3 in Form 10-K for the year ended December 31, 1991.
10.9.4 Supplemental Agreement No. 3 to Agreement for Sharing Ownership of Big Stone Plant (dated as of March 31, 1986). Previously filed as Exhibit 10-F-4 in Form 10-K for the year ended December 31, 1991.
10.9.5 Supplemental Agreement No. 4 to Agreement for Sharing Ownership of Big Stone Plant (dated as of April 24, 2003).
10.9.6 Amendment I to Letter of Intent dated May 8, 1984, for purchase of share of Big Stone Plant. Previously filed as Exhibit 10-F-5 in Form 10-K for the year ended December 31, 1992.
10.10 Big Stone South-Ellendale Project Ownership Agreement dated as of June 12, 2015 between Otter Tail Power Company, a wholly owned subsidiary of Otter Tail Corporation, and Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.**
10.11.0 Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company and Minnesota Power & Light Company (dated as of July 1, 1977). Previously filed as Exhibit 5-H in filing 2-61043.
10.11.1 Supplemental Agreement No. One, dated as of November 30, 1978, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. Previously filed as Exhibit 10-H-1 in Form 10-K for the year ended December 31, 1989.
10.11.2 Supplemental Agreement No. Two, dated as of March 1, 1981, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 and Amendment No. 2 dated March 1, 1981, to Coyote Plant Coal Agreement. Previously filed as Exhibit 10-H-2 in Form 10-K for the year ended December 31, 1989.
10.11.3 Amendment, dated as of July 29, 1983, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1. Previously filed as Exhibit 10-H-3 in Form 10-K for the year ended December 31, 1989.
10.11.4 Agreement, dated as of September 5, 1985, containing Amendment No. 3 to Agreement for Sharing Ownership of Coyote Generating Unit No. 1, dated as of July 1, 1977, and Amendment No. 5 to Coyote Plant Coal Agreement, dated as of January 1, 1978. Previously filed as Exhibit 10-H-4 in Form 10-K for the year ended December 31, 1992.
10.11.5 Amendment, dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10.11.6 Amendment, dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10.12.0 Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., Northwestern Corporation, dated as of October 10, 2012.**
10.12.1 First Amendment to Lignite Sales Agreement dated as of January 30, 2014 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C.
10.12.2 Second Amendment to Lignite Sales Agreement dated as of March 16, 2015 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C.
10.13.0
Deferred Compensation Plan for Directors (2003 Restatement).*
No. Description
10.13.1
First Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as Amended.*
10.13.2
Second Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as Amended.*
10.14
Executive Survivor and Supplemental Retirement Plan (2020 Restatement).*
10.15
Nonqualified Retirement Plan (2021 Restatement).*
10.16
1999 Employee Stock Purchase Plan, As Amended (2016).
10.17
2014 Stock Incentive Plan
10.18
2023 Executive Annual Incentive Plan.*
10.19
Otter Tail Corporation Executive Restoration Plus Plan, 2020 Restatement.*
10.20
Summary of Non-Employee Director Compensation (2023).*
10.21
Change in Control Severance Agreement, Chuck MacFarlane, dated February 24, 2012.*
10.22
Change in Control Severance Agreement, Timothy Rogelstad, dated April 14, 2014.*
10.23
Change in Control Severance Agreement, Paul Knutson, dated December 17, 2012.*
10.24
Change in Control Severance Agreement, John Abbott, dated April 13, 2015.*
10.25
Change in Control Severance Agreement, Todd Wahlund, dated January 1, 2024.*
10.26
Change in Control Severance Agreement, Jennifer Smestad, dated January 1, 2018.*
10.27
Form of Change in Control Severance Agreement (2023)*
10.28
Otter Tail Corporation Executive Severance Plan (2024).*
10.29
Form of 2023 Restricted Stock Award Agreements for Directors
10.30
2023 Stock Incentive Plan
10.31
Form of 2023 Executive Performance Share Award Agreement (Executives)
10.32
Form of 2023 Restricted Stock Unit Award Agreement (Executives)
10.33
Consulting Agreement, Kevin G. Moug, dated January 8, 2024*
21 Subsidiaries of Registrant.
23 Consent of Deloitte & Touche LLP.
24 Power of Attorney.
31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Incentive Compensation Recovery Policy
101.SCH Inline XBRL Taxonomy Extension Schema Document.
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*Management contract, compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.
**Confidential information has been omitted from this Exhibit and filed separately with the Securities and Exchange Commission pursuant to a confidential treatment request under Rule 24b-2.
The Company hereby undertakes to furnish copies of any of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request.