EDGAR 10-K Filing

Company CIK: 1466593
Filing Year: 2021
Filename: 1466593_10-K_2021_0001466593-21-000011.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
Otter Tail Corporation 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 segments consistent with our business strategy and management. The following 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. OTP, our largest operating subsidiary and primary business since 1907, serves more than 133,000 customers in 422 communities across a predominantly rural and agricultural service territory.
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, 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 Otter Tail Corporation 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. This strategy and risk profile are designed to provide a more predictable earnings stream, maintain our credit quality and preserve our ability to fund our dividend. Our goal is to deliver annual growth in earnings per share between five and seven percent over the next several years, using 2020 diluted earnings per share as the base for measurement. We expect our earnings growth to come from rate base investments in our Electric segment and from planned earnings growth arising from existing capacities within our Manufacturing and Plastics segments.
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 growth opportunities in our electric utility. We will also evaluate opportunities to allocate capital to potential acquisitions within our Manufacturing and Plastics segments.
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.
Over time, we expect our Electric segment will provide approximately 75% of our overall earnings and our Manufacturing and Plastics segments will collectively provide approximately 25% of our overall earnings and continue to be a fundamental part of our strategy.
Our actual mix of earnings in 2020, 2019, 2018and the average for the five-year period ended December 31, 2020 is 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. Our human capital management efforts include monitoring various metrics and objectives associated with i) employee safety, ii) workforce stability, iii) management and workforce demographics, including gender, racial and ethnic diversity, iv) leadership development and succession planning, and v) productivity. We have established the following programs in furtherance of these efforts:
•Safety is one of our core values. We engage a third party to conduct conformity assessments annually. We continually monitor the Occupational Safety and Health Administration Total Recordable Incident Rate and Lost Time Incident Rate. New cases are reported and evaluated for corrective action during monthly safety calls attended by safety professionals at all locations.
•We extend leadership development into the organization 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 ensure we have a skilled and stable workforce.
•To enhance productivity and employee engagement, 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 future of our organization.
•We communicate annually to all employees on our Code of Conduct to help ensure understanding of the common principles that guide who we are and how we do business.
Across our operating companies and including our corporate team as of December 31, 2020, we employed 2,074 full-time employees:
Segment/Organization Employees
Electric Segment
OTP 647
Manufacturing Segment
BTD 1,047
T.O. Plastics 163
Segment Total 1,210
Plastics Segment
Northern Pipe 100
Vinyltech 79
Segment Total 179
Corporate 38
Total 2,074
At December 31, 2020, 372 employees of OTP are represented by local unions of the International Brotherhood of Electrical Workers under two separate collective bargaining agreements expiring on August 31, 2023 and October 31, 2023. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good.
ELECTRIC Contribution to Operating Revenues: 50% (2020), 50% (2019), 49% (2018)
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, industrial and commercial 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 one industrial customer accounting for 11% of segment operating revenues for the year ended December 31, 2020.
The following summarizes our retail electric revenues by state and by customer segment for the years ended December 31, 2020 and 2019:
In addition to retail revenue, our Electric segment also earns 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.
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; however, we believe OTP is well positioned to be successful in a competitive environment. A comparison of OTP's electric retail rates to the rates of other investor-owned utilities, cooperatives and municipals in the states OTP serves indicates OTP's rates are competitive.
Competition also arises from 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 are utility- or customer-owned resources on the distribution grid that can include combined heat and power, solar photovoltaic, wind, battery storage, thermal storage, and demand-response technologies.
Wholesale electricity markets are competitive under the FERC's open access transmission tariffs, which require utilities to provide nondiscriminatory access to all wholesale users. In addition, the FERC has established a competitive process for the construction and operation of certain new electric transmission facilities whereby electric transmission providers, including the Midcontinent Independent System Operator, Inc. (MISO), of which OTP is a member, are required to remove from their tariffs a federal right of first refusal to construct transmission facilities selected in a regional transmission plan for purposes of cost allocation.
Franchises
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 that OTP serves.
GENERATION AND PURCHASED POWER
OTP primarily relies on company-owned generation, supplemented by purchase power 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 as seasonal or other variations occur.
As of December 31, 2020, OTP’s wholly or jointly owned plants and facilities and their dependable kilowatt (kW) capacity was:
Capacity in kW
Baseload Plants
Big Stone Plant(1)
256,000
Coyote Station(2)
149,000
Hoot Lake Plant 143,100
Total Baseload Net Plant 548,100
Combustion Turbine and Small Diesel Units 107,900
Hydroelectric Facilities 2,500
Owned Wind Facilities (rated at nameplate)
Merricourt Wind Energy Center (75 turbines) 150,000
Luverne Wind Farm (33 turbines) 49,500
Ashtabula Wind Center (32 turbines) 48,000
Langdon Wind Center (27 turbines) 40,500
Total Owned Wind Facilities 288,000
Total 946,500
(1) Reflects OTP's 53.9% ownership percentage of jointly-owned facility
(2) Reflects OTP's 35.0% ownership percentage of jointly-owned facility
In addition to the owned facilities described above, OTP had the following purchased power agreements in place on December 31, 2020:
Purchased Power
in kW
Purchased Wind Power (rated at nameplate and greater than 2,000 kW)
Ashtabula Wind III 62,400
Edgeley 21,000
Langdon 19,500
Total Purchased Wind 102,900
Purchase of Capacity (in excess of 1 year and 500 kW)
Great River Energy (through May 2021)
50,000
The following summarizes the percentage of our generating capacity by source, including owned and jointly-owned facilities and through power and capacity purchase arrangements, as of December 31, 2020, and the percentage of retail kilowatt-hours (kwh) sold by source during the year ended December 31, 2020:
Under MISO requirements, OTP is required to have sufficient capacity through wholly or jointly-owned generating capacity or purchased power agreements to meet its monthly weather-normalized forecast demand, plus a reserve obligation. OTP met its obligation for the 2019-2020 planning year and anticipates meeting this obligation prospectively.
Capacity Retirements and Additions
Hoot Lake Plant, our 142-meagwatt coal-fired power plant in Fergus Falls, Minnesota is approved for retirement in mid-2021.
As part of our investment plan to meet our future energy needs, we have the following projects at various stages of planning and construction or have been recently completed:
Merricourt Wind Energy Center (Merricourt) is a 150-megawatt wind farm located in southeastern North Dakota. Construction of the wind farm commenced in 2019 and the facility was in commercial operation in December 2020 at a cost of approximately $260.0 million.
Astoria Station Natural Gas Plant (Astoria) is a 245-megawatt simple cycle natural gas combustion turbine generation facility near Astoria, South Dakota. Construction began in 2019 and we anticipate the facility will be substantially complete in the first quarter of 2021. We anticipate total project costs will be $152.5 million.
Hoot Lake Plant Solar (HLP Solar) is a 49-megawatt solar farm under development on land on and around our Hoot Lake Plant in Fergus Falls, Minnesota. The project will include up to 150,000 solar panels at an anticipated cost of $60.0 million. We anticipate, subject to permitting and regulatory approval, the facility will be in commercial operation no later than the end of 2023.
RESOURCE MATERIALS
Coal is the principal fuel burned at our Big Stone, Coyote and Hoot Lake generating plants. Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Hoot Lake Plant and Big Stone Plant burn 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 Hoot Lake Plant, Big Stone Plant and Coyote Station have expiration dates in 2023, 2022 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 of the coal supplier in the event of certain early termination events and at the expiration of the coal supply agreement in 2040. See Note 1 to our consolidated financial statements included in this report on Form 10-K for additional information.
Coal is transported to our non-mine-mouth facilities, Big Stone Plant and Hoot Lake Plant, by rail and is provided under a common carrier rate which includes a mileage-based fuel surcharge.
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, 2020, we were the whole or partial owner of over 8,900 miles of transmission and distribution lines.
Midcontinent Independent System Operator, Inc. (MISO)
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 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.
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 may 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 certain interstate operations. 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 ROE, capital structure and depreciation rates of our plant investments. Decisions by our regulators can 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 along with the percentage of electric revenue for the year ended December 31, 2020 covered by each regulatory agency:
Regulatory % of
Agency Revenue Areas of Regulation
Minnesota Public Utilities Commission
(MPUC)
47% 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) 34% 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 or more for wind generating facilities; 50,000 kW for non-wind generating facilities) and high voltage transmission lines (115 kV or more).
Review and approval of ten-year facility plan.
South Dakota Public Utilities Commission
(SDPUC) 9% 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) 10% Wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, hyrdoelectric licensing and accounting policies and practices.
Compliance with NERC reliability standards, including standards on cybersecurity and protection of critical infrastructure.
In addition to base rates, there are other mechanisms for recovery of plant investments, including a return on investment, and operating expenses. The following is a summary of 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 with over or under collections from the previous month applied to the next monthly billing. In Minnesota, fuel and purchased power costs are estimated on an annual basis and the accumulated difference between actual and estimated cost per kwh are refunded or recovered, subject to regulatory approval, in subsequent periods.
Transmission Cost Recovery Rider (TCR) MN, ND, SD Provides for recovery of costs outside of a general rate case for investments in new or modified electric transmission or distribution assets.
Environmental Cost Recovery Rider (ECR) MN, ND, SD Provides for recovery of costs outside of a general rate case for investments in certain environmental improvement projects.
Renewable Resource Rider (RRR) MN, ND Provides for recovery of costs outside of a general rate case for investments in certain new renewable energy 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.
Phase-In Rider (PIR) SD Provides for the recovery of costs outside of a general rate case for investments in new generation facilities.
Conservation Improvement Program (CIP) MN Under Minnesota law, OTP is required to invest at least 1.5% of its gross operating revenues on energy conservation improvements. Recovery of these costs outside of a general rate case occurs through the CIP.
Energy Efficiency Plan (EEP) SD Provides for the recovery of costs from energy efficiency investments.
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: 17% by 2016; 20% by 2020 and 25% by 2025. 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 electric sales by public utilities to be supplied by solar energy by 2020. 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 kWs or less. OTP has purchased sufficient solar renewable energy credits (SRECs) to meet 100% of its 2020 obligation and approximately 70% of its 2021 obligation.
Under certain circumstances and after consideration of costs and reliability issues, the MPUC may modify or delay implementation of the standards. We are evaluating potential options for maintaining compliance and meeting the solar energy standard beyond 2021.
Integrated Resource Plan (IRP)
Under Minnesota law, utilities are required to submit for approval by the MPUC a 15-year advance 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 evidence, subject to rebuttal, in future rate reviews and other proceedings. Typically, IRPs are submitted every two years.
On April 26, 2017 the MPUC approved OTP’s 2017-2031 IRP filing with modifications and setting requirements for the next IRP. The approved IRP with modifications included the following items:
•The addition of 200 MW of wind resources in the 2018 to 2020 timeframe.
•The addition of 30 MW of solar resources by 2020 to comply with Minnesota's Solar Energy Standard.
•The addition of up to 250 MW of peaking capacity in 2021.
•Average annual energy savings of 46.8 gigawatt-hours (1.6% of retail sales).
•The addition of 100 MW to 200 MW of wind resources in the 2022 to 2023 timeframe.
The MPUC has granted us an extension for filing our next IRP to September 1, 2021. The extension provides additional time to assess the potential impact of two key Environmental Protection Agency (EPA) regulations: the federal Regional Haze Rule (RHR) and the Affordable Clean Energy (ACE) Rule. In connection with the extension, OTP made a supplemental filing on December 31, 2020 summarizing the results of scenario modeling evaluating RHR compliance cost options and a Coyote Station 2028 retirement scenario. The filing indicated, when modeled with externalities, that capital investments in additional environmental controls at Coyote Station does not result in the lowest-cost mix of resources for our customers. This IRP supplemental filing includes only a subset of our resource planning analysis and it is not conclusive. In addition, we cannot conclude how RHR will impact Coyote Station as key milestones remain in developing the state implementation plan in North Dakota. Finally, OTP is one of four partners in Coyote Station and cannot make a unilateral decision on its future. We expect to have more definitive information about the most cost-effective resource mix to meet customer needs when the next IRP is filed on September 1, 2021.
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. The MPUC approved OTP’s most recent capital structure petition on July 15, 2020, allowing for an equity-to-total-capitalization ratio between 47.5% and 58.1%, with total capitalization not to exceed $1.70 billion until the MPUC issues a new capital structure order for 2021.
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 granted by regulators in jurisdictions in which we operate; however, there can be no assurance that future costs will be granted recovery. Alternatively, additional pollution control equipment or other emission reduction measures may prove to be uneconomic with the potential to lead to an early closure of a facility.
For the five-year period ended December 31, 2020, OTP invested approximately $13.5 million, including $0.4 million in 2020, in environmental control facilities. Our 2021 and 2022 construction budgets include approximately $1.4 million and $1.2 million for such expenditures. The timing and amount of our expenditures may change as the regulatory environment changes.
Among current regulatory requirements, the Regional Haze Rule (RHR) could have the most significant impact on our operating results, financial condition and cash flows.
The EPA adopted the RHR in 1999 as an effort to improve visibility in national parks and wilderness areas. The RHR requires states, in coordination with the EPA and other governmental agencies, to develop and implement plans to work towards achieving natural visibility conditions by the year 2064. The second RHR implementation period covers the years 2018-2028, with state implementation plans to be submitted to the EPA by July 31, 2021. States are required to assess reasonable progress with the RHR and determine what additional emission reductions are appropriate, if any. Coyote Station, OTP's co-owned coal-fired power plant in North Dakota is subject to assessment in the second implementation period under the North Dakota state implementation plan. See Note 13 to our consolidated financial statements included in the report on Form 10-K for additional information.
Climate Change and Greenhouse Gas Regulation
Present and future federal, state, regional and international environmental regulations to address global climate change and reduce greenhouse gas (GHG) emissions may have a significant impact on our utility business. 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.
Regulatory measures to address climate change continue to evolve. In January 2021, the EPA's Affordable Clean Energy Rule (ACE Rule) was vacated by the U.S. Court of Appeals for the District of Columbia Circuit and remanded to the EPA for further consideration. Future federal regulatory measures, including in response to the vacated rule ACE Rule, will be impacted by the Biden administration's priorities and objectives. While the eventual outcome of GHG regulation is unknown, we are taking steps to reduce our carbon footprint and mitigate CO2 emission levels in the process of generating electricity for our customers. Our initiatives include increasing the efficiency of our plants, adding renewable energy to our resource mix, and sponsoring energy conservation programs.
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 cash flows unless such costs could be recovered through related rates and/or future market prices for energy.
MANUFACTURING Contribution to Operating Revenues: 27% (2020), 30% (2019), 29% (2018)
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 headquarters located in Detroit Lakes, Minnesota, provides metal fabrication services for custom machine parts and metal components through metal stamping, tool and die, machining, tube bending, welding and assembly in its facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia.
T.O. Plastics, Inc. (T.O. Plastics), with facilities in Otsego and Clearwater, Minnesota, manufactures extruded and thermoformed plastic products, including custom parts for customers in several industries and its own line of horticulture containers. Examples of products produced include clamshell packing, blister packs, returnable pallets and handling trays for shipping and storing odd-shaped or difficult-to-handle parts.
CUSTOMERS
Our metal fabrication business primarily serves Midwestern and Southeastern U.S. manufacturers in the recreational vehicle, agricultural, oil and gas, lawn and garden, industrial and energy equipment end markets. Our plastic products business serves primarily U.S. customers in the medical and life sciences, industrial, recreational and electronics industries. The principal method of production distribution is by direct shipment to our customers through common carrier ground transportation.
No single customer or product of our manufacturing businesses accounted for 10% or more of our consolidated operating revenue in 2020. However, the top three customers combined to account for 46% of our 2020 Manufacturing segment operating revenue.
COMPETITIVE CONDITIONS
The various markets in which we compete are characterized by intense competition from both foreign and domestic manufacturers. These markets have many established manufacturers with broader product lines, greater distribution capabilities, greater capital resources, excess capacity, labor advantages and larger marketing, research and development staffs and facilities than our own.
We believe the principal competitive factors in our Manufacturing segment are product performance, quality, price, technical innovation, cost effectiveness, customer service and breadth of product line. We intend to continue to compete based on high-performance products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.
RESOURCE MATERIALS
We use raw materials in the products we manufacture, including 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 on 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 cost 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: 23% (2020), 20% (2019), 22% (2018)
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 a process known as extrusion. During this process, PVC compound (a dry powder-like substance) is introduced into an extrusion machine, where it is heated to a molten state and then forced through a sizing apparatus to produce the pipe. 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. Together our Plastic segment businesses have the current capacity to produce approximately 300 million pounds of PVC pipe annually.
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 2020. However, two customers combined to account for 45% of our 2020 Plastics segment operating revenue.
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, 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.
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. Two vendors provided over 99% of total resin purchases in 2020. 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 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 the Plastics segment 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.

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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, financial condition, operating results and cash flows. Additional risks and uncertainties we are not presently aware of or that we currently consider immaterial may also affect our business, financial condition, operating results and cash flows.
Oversight of Risk and Related Processes
A key accountability of the Board of Directors is the oversight of material risk. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of top risks. Management identifies and analyzes risks to determine the impact and other attributes such as timing, likelihood and management control. Identification and analysis occur formally through a top risk assessment conducted by senior management, the financial disclosure process, and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. We promote a culture of compliance, including tone at the top. The process for risk mitigation includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management to mitigate the risks inherent in the implementation of strategy. We manage and further mitigate risks through formal risk management structures, including a management executive risk committee and services such as internal audit/business risk management and legal. Management communicates regularly with our Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to our Board of Directors which provides information on the risks management believes are material, including the earnings impact, timing, likelihood and management control. The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of Otter Tail Corporation. The Board of Directors regularly reviews management’s top risk assessment and analyzes areas of existing and future risks and opportunities. Finally, the Board of Directors conducts an annual strategy session where our future plans and initiatives are reviewed.
OPERATIONAL RISKS
The economic effects of the COVID-19 pandemic and measures taken to arrest its spread, as well as any emergency measures we take in response, could adversely impact our business, including our operating results, financial condition and liquidity.
The outbreak and global spread of COVID-19, which has been declared a pandemic by the World Health Organization, has adversely impacted economic activity and conditions worldwide and is currently impacting our business operations. The extent to which COVID-19 will continue to impact our business is highly uncertain and will depend on future developments, including the efficacy and availability of vaccines, the spread of COVID-19 variants and the extent of federal, state and local government responses affecting the economy. In particular, the COVID-19 pandemic could, among other things:
•reduce customer demand in our Manufacturing segment, where we experienced a significant but temporary decline in orders in 2020 as many of our customers temporarily closed their plants, which led to actions to reduce our operations, including furloughing of employees and eliminating positions;
•reduce customer demand in our Electric segment, including demand from commercial and industrial customers;
•reduce customer demand in our Plastics segment;
•result in lower PVC pipe sales due to potential delays or cancellation of public water and wastewater infrastructure projects caused by funding shortfalls;
•lead to disruptions of our workforce;
•force us to temporarily close certain plants or construction sites if precautions to prevent the spread of the virus at those locations are not effective;
•increase our bad debt expenses, particularly in our Electric segment;
•increase our future pension benefit cost and funding requirements;
•increase health insurance premiums;
•disrupt the supply chains, delivery systems or construction workforce related to our Electric segment maintenance requirements and capital expenditure plans, resulting in further delays and increased costs;
•disrupt global financial markets, reducing our ability to access capital necessary to finance such expenditures, and which could in the future negatively affect our liquidity; and
•result in a recession or market correction that could materially affect our business and the value of our common stock.
We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and take steps to mitigate against additional impacts, but given the unprecedented and evolving nature of these circumstances, we cannot predict the full extent of the impact that COVID-19 will have on our operating results, financial condition and liquidity.
Our strategy includes large capital investments, which are subject to risks.
Our business strategy includes major capital investments at our existing companies. Our capital investment program planned for the next five years includes investments in renewable generation, transmission asset additions and upgrades, and technology and infrastructure projects. These capital projects are planned years in advance of their in-service dates and are subject to various risks including: obtaining necessary permits, licenses and approvals in a timely manner; adverse changes in regulatory treatment or public policy; changes in commodity pricing, equipment and construction costs; technology changes; delivery delays of critical materials and components; delays caused by construction accidents, injuries or public health crises; adverse weather conditions; unforeseen product defects; limited access to capital; and other adverse conditions. Capital investments in our Electric segment are subject to regulatory approval and are at risk of not being granted timely or full recovery of our investments. The inability to complete capital projects on budget and in a timely manner could adversely impact our financial condition and operating results.
Our acquisition or disposition strategies are subject to risk and may 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 dispositions. 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.
The sale of any of our businesses may result in the recognition of a loss, if the business is sold for less than its book value and may expose us to risk arising from indemnification obligations that arose out of the conduct of the business prior to the sale. These obligations may include such things as warranty and environmental obligations or the recoverability of certain assets sold as part of the transaction. Unforeseen costs related to these obligations could impact our operating results.
Weather impacts, including normal seasonal fluctuation and extreme weather events could adversely affect our operating results.
Our Electric segment business is seasonal and weather patterns can have a material impact on our financial performance. 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. In addition, our Plastics segment businesses are affected by weather’s impact on contractors whose work can be delayed and therefore reduce the need for PVC pipe during winter weather and extreme wet conditions.
Our businesses are located in areas that could be subject to natural disasters such as severe snow and ice storms, tornadoes, flooding and fires. These factors could result in interruption of our business and damage to our facilities. An extreme weather event within our utility service areas could directly affect our capital assets, causing disruption in service to customers and result in repair or replacement costs, due to downed wires and poles or damage to other operating equipment.
In addition to variations in seasonal weather patterns, more widespread climate change may also create physical and financial risk to our businesses. Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other phenomena, could affect some or all of our operations. Severe weather or other natural disasters related to climate change could be destructive and result in increased costs and disruptions in our operations. Extreme weather conditions, such as uncommonly long periods of high or low ambient temperature, in general require more utility system backup, adding to costs and contributing to increased system stress on our utility infrastructure, which could cause service interruptions.
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 provides more than 10% of our consolidated operating revenue, each of our segments have customers which account for over 10% of the segment’s operating revenues. In 2020, one customer accounted for 11% of Electric segment revenue, three customers combined to account for 46% of Manufacturing segment operating revenue and two customers combined to account for 45% of Plastics segment operating revenue. 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 position and operating results, and could have a significant negative impact on the Company’s consolidated financial position and operating results.
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 commercial and industrial customers operate. Increased customer delinquencies and bad debts could adversely impact our operating results and liquidity.
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 function of our computer hardware and software systems. Furthermore, all our businesses require us to collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss. We also use third-party vendors 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. We may also be impacted by attacks and data security breaches of financial institutions, merchants or third-party processors. While we 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 data protection laws. These laws are subject to change and expansion and may require additional operational changes 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 and regulators. 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 heavily depends on the leadership of our executive officers and key employees to implement our strategy. In addition, all of our businesses rely on technical employees who possess certain specialized knowledge. The inability to attract and maintain a skilled and stable workforce may negatively affect our ability to service our customers, manufacture products, or successfully manage our business and achieve our objectives. Competition for skilled workers is high and can lead to increased labor expenses, decreased productivity and potentially lost business opportunities. Our ability to maintain productivity, relationships with customers, competitive costs, and quality services is limited by the ability to employ the necessary skilled personnel and could negatively affect our operating results, financial position and cash flows.
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.
A decrease in our credit rating 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 for 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 financial position, operating results and cash flows 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 position 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. 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 may impact the economics of constructing certain electric generation resources, which may adversely impact our planned investments.
A significant impairment of our goodwill would negatively impact our financial position and operating results.
As of December 31, 2020, we had $37.6 million of goodwill recorded on our consolidated balance sheet. We have recorded goodwill for businesses in our Manufacturing and Plastics segments. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. The goodwill impairment test requires us to estimate the fair value of the businesses being tested. Estimating the fair value of a business unit requires significant judgments and estimates, including estimates of future operating results and cash flows, among others. These estimates can be affected by numerous factors, including changes in economic, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions or material differences between actual and forecasted financial performance could affect our fair value estimates and lead to a goodwill impairment charge that could adversely affect our financial position and operating results, as well as impact compliance with financing agreement covenants.
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.
We are subject to federal and state legislation, government regulations and regulatory actions that may have a negative impact on our business and results of operations. The electric rates OTP is allowed to charge for its electric services are one of the most important items influencing our financial position, operating results and liquidity. The rates OTP charges its electric customers are subject to review and determination by state and federal regulators. Our ability to obtain rate adjustments to maintain reasonable rates of return depends on regulatory action under applicable statutes and regulations and we cannot provide assurance that rate adjustments will be obtained or reasonable rates of return on capital will be authorized. There is no assurance the applicable regulatory authority will judge all our costs to have been prudently incurred or that rates will produce full recovery of such costs. In addition, there could be changes in the regulatory environment that would impair the ability of OTP to recover costs historically collected from their customers. OTP will file rate cases with, or seek cost recovery authorization from, federal and state regulatory authorities. An adverse decision by one or more regulatory authorities concerning the level or method of determining electric utility rates, the authorized returns on equity, recoverability of fuel, purchase power and other costs, approval of depreciation rates, implementation of enforceable federal reliability standards or other regulatory matters, permitted business activities (such as ownership or operation of nonelectric businesses) or any prolonged delay in rendering a decision in a rate or other proceeding (including with respect to the recovery of capital expenditures in rates) could adversely impact our operating results.
Federal and state environmental regulation could require us to incur substantial capital expenditures and 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 requires 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.
Existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us. 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 operating results and make it no longer economically viable to operate some of our facilities.
Legislation, regulation or other actions related to climate change, greenhouse gas emissions, and other air pollutants could materially impact us.
Current and future federal, state, regional and international regulations to address global climate change and reduce greenhouse gas GHG emissions and other air pollutants, 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 new costs, which could negatively impact our financial position, operating results and cash flows if such costs cannot be recovered through rates granted by ratemaking authorities or through increased market prices for electricity. Future federal regulatory rulemaking will be impacted by the Biden administration's priorities and objectives, which may include more stringent requirements for reducing GHG emissions and other air pollutants from existing fossil fuel-fired power plants, and other objectives that may impact our operating results, financial position or cash flows.
State implementation plans for compliance with the second implementation period of the RHR are due in mid-2021. Coyote Station, OTP's jointly-owned coal-fired power plant, is subject to assessment under the RHR as part of the state of North Dakota's state implementation plan. We cannot predict the impact the state implementation plan have on us until the plan is finalized and adopted. However, significant emission control investments could be required, or in light of the costs for such emission control equipment, there are scenarios where it may not be economically feasible to invest in such equipment and an early retirement of, or the sale of our interest in, Coyote Station would be necessary. The costs of such a retirement or sale would be material, a significant asset impairment charge could be required and OTP would be subject to state commission approval to recover such costs from customers. In addition, it may be necessary to pursue replacement electric generation facilities as an alternative, which may require incurring significant investment in new facilities that would be subject to regulatory permits and approvals.
In addition to complying with legislation and regulation, we could be subject to litigation related to climate change. 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 operating results and cash flows if the costs are not recoverable in rates or covered by insurance.
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.
Violations of extensive legal and regulatory compliance requirements may 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 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 did 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 results of operations.
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 stays abreast of best practices within 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 or 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 results of operations.
Our generating facilities are subject to operational risks that could result in unscheduled plant outages and increased costs.
The operation of electric generating facilities involves many risks, including facility shutdowns due to equipment or process failures; labor disputes; operator error; catastrophic events such as fires, explosions, and floods; the dependence on a specific fuel source; and the risk of performance below expected levels of output or efficiency. We could be subject to costs associated with any unexpected failure to produce or deliver power, including failures caused by a breakdown or forced outage, as well as repairing damages to facilities.
We rely on a limited number of suppliers to provide coal and coal transportation to our facilities. A failure to perform by any of these counterparties 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, which could lead to increased costs adversely impacting our operating results.
Our generating facilities are subject to operational risks that could result in early closure or a sale of our interest.
Early closure of, or the sale of our interest in, a generating facility due to operational or economic factors, environmental regulation or risks of litigation could have a material adverse impact on our operating results. In the event of an early closure, a significant asset impairment charge could be required and we would be obligated to pay for costs of closure of our share of the generating facility. We may not be able to recover our remaining investment and the costs associated with the early closure, include 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.
The loss of a major generating facility would require OTP to identify and receive approval for other sources of generation for its customers, if available, and expose it to higher purchased power costs. In addition, OTP may not be able to obtain timely regulatory approval for new generation resources to replace closed facilities.
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 liability for unfulfilled contractual obligations. Any significantly higher than expected energy or fuel costs would negatively affect our financial performance.
MANUFACTURING SEGMENT RISKS
Competition from foreign and domestic manufacturers, the price and availability of raw materials, trade policy and tariffs affecting prices and markets for raw material and manufactured products, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.
Our manufacturing businesses are subject to intense risks associated with competition from foreign and domestic 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 that may place downward pressure on margins and profitability. The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture, including steel, aluminum and polystyrene and other plastics resins. Costs for these items can fluctuate significantly. Federal trade policies, including imposed and proposed tariffs could significantly increase the prices and delivery of raw materials such as steel and aluminum that are critical to our manufacturing businesses. If our manufacturing businesses are not able to pass on cost increases to their customers, it could have a negative effect on profit margins in our Manufacturing segment. 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. Changes in macroeconomic conditions can negatively impact demand in the end-use markets for products and parts that we manufacture, resulting in reduced sales and profits. There is no assurance the initiatives underway to increase revenues and improve margins at our manufacturing businesses will be successful.
Economic conditions in the end markets in which our customers operate can have an adverse impact on our results of operations and cash flows.
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, horticultural and life science. Factors affecting any of these industries in general, or any of our customers in particular, could adversely affect us because our net sales growth largely depends on the continued 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, to gain or retain widespread commercial acceptance of their products or to 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; in particular, the United States, including recessionary periods such as a global economic downturn;
•our customers’ decision to insource the production of components that has 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 deteriorate, we may experience a material adverse effect on our business, operating results and financial condition.
Our business and operating results 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:
•hire, retain and expand our pool of qualified engineering and trade-skilled personnel;
•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 not be able 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 uncompetitive. We may have 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, effective training of new staff or technical difficulties with machinery. Failure to anticipate and adapt to customers’ changing technological needs and requirements, to hire and retain a sufficient number of engineers, and to maintain manufacturing, engineering and technological expertise may have a material adverse effect on our businesses and operating results.
Our manufacturing operations are subject to environmental, health and safety laws and regulations that could result in liabilities to us.
Our manufacturing operations, which include painting and coating processes, 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. We could incur material costs, including cleanup costs, civil and criminal fines, penalties and third-party claims for cost recovery, property damage or personal injury as a result of violations of or liabilities under such laws and regulations. The ultimate cost of remediating contaminated sites, if any, is difficult to accurately predict and could exceed estimates. In addition, as environmental, health and safety laws and regulations have tended to become stricter, we could incur additional costs complying with requirements that are promulgated in the future.
PLASTICS SEGMENT RISKS
Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of PVC resin.
We rely on a limited number of vendors to supply the PVC resin used in our plastics business. Two vendors provided over 99% of our total purchases of PVC resin in 2020. 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, which may increase the risk of a shortage of resin in the event of a hurricane or other natural disaster 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 are available.
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 business.
Changes in PVC resin prices can negatively affect our plastics business.
The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been 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.
External factors beyond our control can 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 raw material prices, demand for our products, prices of our product and volumes and deterioration in 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;
•funding shortages for municipal water and wastewater projects can also adversely impact demand for our products.
•pandemics and other public health threats.
GENERAL RISK FACTORS
Economic conditions could negatively impact our businesses.
Our businesses are affected by local, national and worldwide economic conditions. 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. Our businesses may also 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.
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 investment 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.

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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 Coyote Station, which commenced operation in 1981, is a 414,000 kW (nameplate rating) mine-mouth plant located in the lignite coal fields near Beulah, North Dakota and is jointly owned by OTP, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Public Service Company. OTP is the operating agent of the Coyote Station and owns 35% of the plant.
OTP, jointly with Northwestern Public Service Company and Montana-Dakota Utilities Co., owns the 414,000 kW (nameplate rating) Big Stone Plant in northeastern South Dakota which commenced operation in 1975. OTP is the operating agent of Big Stone Plant and owns 53.9% of the plant.
Located near Fergus Falls, Minnesota, the Hoot Lake Plant is comprised of two separate generating units: a unit built in 1959 (53,500 kW nameplate rating) and a unit added in 1964 (75,000 kW nameplate rating) and modified in 1988 to provide cycling capability, allowing this unit to be more efficiently brought online from a standby mode. These two generating units have a combined nameplate rating of 128,500 kW. Current plans are for both units to be retired from service in 2021.
OTP owns the 245,000 kW (nameplate rating) Astoria Station simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota, scheduled to begin commercial operation in March 2021.
OTP owns 27 wind turbines at the Langdon, North Dakota Wind Energy Center with a nameplate rating of 40,500 kW, 32 wind turbines at the Ashtabula Wind Energy Center located in Barnes County, North Dakota with a nameplate rating of 48,000 kW, 33 wind turbines at the Luverne Wind Farm located in Griggs and Steele Counties, North Dakota with a nameplate rating of 49,500 kW and 75 wind turbines at the Merricourt Wind Energy Center located in McIntosh and Dickey Counties, North Dakota with a name plate rating of 150,000 kW.
As of December 31, 2020, OTP’s transmission facilities, which are interconnected with lines of other public utilities, consisted of 780 miles of 345 kV lines, of which 731 miles are jointly owned; 495 miles of 230 kV lines, of which 70 miles are jointly owned; 917 miles of 115 kV lines; and 4,011 miles of lower voltage lines, principally 41.6 kV. OTP owns the uprated portion of 48 miles of the 345 kV lines, with Minnkota Power Cooperative retaining title to the original 230 kV construction, and OTP owns an undivided interest in the remaining 345 kV line miles. OTP is a joint owner, with other regional utilities, in transmission lines with the following ownership interests: 14.8% in the 70 mile Bemidji-Grand Rapids 230 kV line, approximately 14.2% of 242 miles of energized line in the Fargo-Monticello 345 kV project, approximately 4.8% of 255 miles of energized line in the Brookings to Southeast Twin Cities 345 kV project, 50.0% of 72 miles of energized line in the Big Stone South-Brookings 345 kV project, and 50.0% of 162 miles of energized line in the Big Stone South-Ellendale 345 kV project.
In addition to the properties described above, all of which are utilized by the Electric segment, the Company owns and has investments in offices and service buildings utilized by each of its manufacturing and plastic pipe companies. The Company’s subsidiaries own facilities and equipment used in the manufacture of PVC pipe, thermoformed products, heavy metal fabricated products, metal parts stamping, fabricating, painting and contract machining.
Management of the Company believes the facilities and equipment described above are adequate for the Company’s 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. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable, and an amount can be reasonably estimated. Material proceedings are described under Note 13, "Commitments and Contingencies" to the consolidated financial statements.
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 (56) 04/13/15 President and Chief Executive Officer
Kevin G. Moug (61) 04/09/01 Chief Financial Officer and Senior Vice President
Timothy J. Rogelstad (54) 04/14/14 Senior Vice President, Electric Platform
John Abbott (62) 02/11/15 Senior Vice President, Manufacturing Platform
Jennifer O. Smestad (50) 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.
Kevin Moug has served as Chief Financial Officer and Senior Vice President of the Company since April 9, 2001.
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 5, 2015.
Jennifer Smestad was appointed to the position of Vice President, General Counsel and Corporate Secretary of the Company, effective January 1, 2018. Ms. Smestad joined the Company on May 14, 2001 as an Associate General Counsel and has served in various legal capacities of increasing responsibility at the Company and at OTP. She most recently served as General Counsel for OTP from March 1, 2013 to the present.
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, 2020, there were approximately 12,344 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 year ended December 31, 2020.
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, 2015, and reinvestment of all dividends).
2015 2016 2017 2018 2019 2020
OTTR $ 100.00 $ 159.07 $ 178.72 $ 205.42 $ 218.12 $ 187.64
EEI $ 100.00 $ 117.44 $ 131.19 $ 136.02 $ 171.09 $ 169.10
Nasdaq $ 100.00 $ 113.01 $ 137.17 $ 129.71 $ 170.14 $ 206.32

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ITEM 6. SELECTED FINANCIAL DATA

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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 organic growth opportunities in our Manufacturing and Plastics segments. Investments in our Electric segment will lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund our dividend. Organic growth in our Manufacturing and Plastics segments comes from market expansion, new products and services, increased efficiencies and targeted capital investments.
All of our businesses in 2020 were confronted with operational or financial challenges resulting from the coronavirus (COVID-19) pandemic. Throughout the pandemic, we focused on maintaining the health and safety of our employees, customers and communities and ensuring continued electrical reliability and continuous delivery of products to our customers.
We expect reliable utility performance along with rate base investment opportunities over the next five years will provide us with a strong and growing base of revenues, earnings and cash flows. We also look to our manufacturing and plastic pipe companies to provide organic growth as well. Organic, internal growth comes from new products and services, market and plant expansion and increased efficiencies. We expect much of our growth in these businesses in the next few years will come from utilizing expanded plant capacity from capital investments made in previous years. We will also evaluate opportunities to allocate capital to potential acquisitions across our reporting segments. We are a committed long-term owner and do not acquire companies in pursuit of short-term gains. However, we will divest operating companies that no longer fit into our strategy and risk profile over the long term.
Our Electric segment continued the construction of rate base investments, including our Merricourt wind farm and Astoria Station natural gas combustion turbine in 2020. Merricourt is a 150-megawatt wind farm in southeastern North Dakota. Construction commenced in 2019 and the project was substantially completed in December 2020. Astoria Station is a 245-megawatt simple cycle natural gas combustion turbine generation facility near Astoria, South Dakota. Construction began in 2019 and we anticipate the facility will be in commercial operation in the first quarter of 2021. These rate base investments contributed to our Electric segment earnings growth in 2020.
The operating results of our Manufacturing segment were most significantly impacted by the effects of COVID-19 with product demand significantly decreasing in the second quarter as our customers slowed or temporarily shutdown their plant operations. Demand rebounded in certain end markets in the third and fourth quarters of 2020. Our Manufacturing businesses effectively managed their operations to meet the level of demand in the marketplace.
Our Plastic segment businesses were able to capitalize on opportunities in the marketplace arising due to supply disruptions and increasing global demand for PVC resin. Our ability to meet this demand created opportunities for increased product sales volumes and gross profit margins and resulted in a 33% increase in operating income in 2020.
In 2020 we accessed the capital markets to finance our capital investments. We issued $75.0 million of debt during 2020 and issued 1.3 million shares of common stock for net proceeds of $49.7 million under our various equity programs. Finally, we paid an annual dividend of $1.48 per share, or $60.3 million, completing our 82nd consecutive year of dividend payments to our shareholders.
Our net income in 2020 was $95.9 million, or $2.34 per diluted share, an increase of 10.4% from 2019 of $86.8 million, or $2.17 per diluted share. Our financial results were primarily driven by earnings in our Electric segment from returns on our rate base investments and management of our operating and maintenance expenses, and earnings in our Plastics segments due to increased sales volumes and gross profit margins.
Our earnings mix in 2020 was 70% from our Electric segment and 30% from the combination of our Manufacturing and Plastics segments and unallocated corporate costs. Electric segment earnings as a percentage of our total earnings were less than our long-term estimate of 75% due to very strong Plastics segment earnings in 2020.
COVID-19
We continue to monitor the progression of the novel coronavirus (COVID-19) and its impact on our businesses, employees, customers, construction contractors and vendors. As this pandemic continues, we are following the directives and advice of government leaders and medical professionals and have adopted practices to help curtail the spread of the virus and mitigate its impact on our communities, employees, construction contractors, customers and business operations. Our Electric segment business provides a critical service to our customers and our manufacturing businesses provide products and support to critical infrastructure industries. We continue to operate our businesses in a manner that is safe for our employees and our customers.
COVID-19 and the resulting economic conditions have had a material negative impact on the results of operations in our Manufacturing segment, and, to a lesser extent, also impacted the results of operations of our Electric and Plastics segments, but have not had a material impact on our consolidated financial position or liquidity.
Customer demand in our Manufacturing segment declined significantly in the second quarter of 2020. Sales volumes strengthened in the third and fourth quarters of the year due to strong recreational vehicle and lawn and garden end-market demand. Within our Electric segment, we experienced reduced demand from commercial and industrial customers, increased costs for bad debts, and had to manage through COVID-19-related disruptions at our construction sites, including Merricourt and Astoria Station, which posed a risk of construction delays and increased project costs. In our Plastics segment, we experienced lower sales volumes in the second quarter of 2020 as distributors reduced inventory levels given the uncertainty over the impact of COVID-19. Sales volumes recovered and gross profit margins increased in the third and fourth quarters due to increasing demand and concerns of supply disruptions.
Beginning in April 2020, in response to the actual and anticipated impact of COVID-19 on our business operations, we implemented a variety of policies, including furloughs, shift and pay reductions, wage and hiring freezes, suspension of certain employee benefits, a workforce reduction and other cost reduction efforts to mitigate the negative impact to our financial results. We continued to monitor the impacts of the pandemic on our businesses throughout the remainder of 2020 and adjusted our response as circumstances evolved.
We expect COVID-19 and the resulting economic conditions will continue to impact demand from commercial and industrial customers within our Electric segment and could disrupt customer demand within our Manufacturing and Plastics segments as the pandemic evolves. We also expect bad debt costs within our Electric segment will remain elevated due to the economic disruption created by the pandemic. COVID-19 also could cause disruptions in our capital expenditure plans, including project delays and increased project costs.
We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and the financial effects on our business. However, due to the unprecedented and evolving nature of this pandemic, we cannot predict the full extent COVID-19 will have on our results of operations, financial condition and liquidity.
FINANCIAL AND OTHER METRICS
Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. 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.
Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (kwh) sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. 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, the rate base consists of the value of property used by the utility in providing service. Rate base can also include: cash, working capital, materials and supplies, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits, dependent on the method that is used in the calculation, which can vary from jurisdiction to jurisdiction. We present actual and forecasted levels of utility rate base in our outlook to provide an indication of expected investments on which we expect to earn future returns.
RESULTS OF OPERATIONS
For a comparison of fiscal year 2019 to 2018, 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, 2019, filed with the SEC on February 20, 2020 and incorporated by reference into this report on Form 10-K.
Provided below is a summary and discussion of our operating results on a consolidated basis followed by a discussion of the operating results of each of our segments, Electric, Manufacturing and Plastics. Intersegment transactions were not material in 2020 or 2019 and amounted to less than $0.1 million of operating revenues and operating expenses for each year. In addition to the segment results, we provide an overview of our Corporate costs. 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, 2020 and 2019:
(in thousands) 2020 2019 $ change % change
Operating Revenues $ 890,107 $ 919,503 $ (29,396) (3.2) %
Operating Expenses 742,221 784,623 (42,402) (5.4)
Operating Income 147,886 134,880 13,006 9.6
Interest Charges 34,447 31,411 3,036 9.7
Nonservice Cost Components of Postretirement Benefits 3,437 4,293 (856) (19.9)
Other Income 6,055 5,112 943 18.4
Income Before Income Taxes 116,057 104,288 11,769 11.3
Income Tax Expense 20,206 17,441 2,765 15.9
Net Income $ 95,851 $ 86,847 $ 9,004 10.4 %
Operating Revenues decreased $29.4 million primarily due to reduced demand in our Manufacturing segment as our customers were impacted by the economic effects of COVID-19. In addition, Electric segment operating revenues were impacted by lower recoveries of decreased fuel and purchased power costs and the impact of unfavorable weather, but partially offset by operating revenues earned on our rate base investments. Plastics segment revenue increased in 2020 due to favorable market conditions benefiting sales volumes and prices. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses decreased $42.4 million in 2020 primarily due to lower costs of products sold in our Manufacturing segment as a result of the reduced sales volumes and lower fuel and purchased power costs in our Electric segment. Partially offsetting these decreases were higher costs of products sold in our Plastics segment due to increased sales volumes in 2020 and an increase in committed contributions to our charitable foundations. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Charges increased $3.0 million in 2020 due to debt issuances in our Electric segment in the fourth quarter of 2019 and the first and third quarters of 2020, and increased outstanding borrowings under our short-term debt arrangements. The increase in our short and long-term debt borrowings were largely used to finance the rate base investments in our Electric segment.
Nonservice Cost Components of Postretirement Benefits decreased $0.9 million in 2020 mostly due to a decrease in pension plan nonservice costs, mainly actuarial loss amortization expenses, partially offset by interest cost increases on postretirement benefit plans.
Other Income increased $0.9 million in 2020 due to a $1.5 million increase in allowance for equity funds used during construction (AFUDC) on Electric segment construction work in progress, mainly for the Minnesota share of the Astoria Station project, partially offset by $0.6 million of decreases in the cash values of corporate-owned life insurance policies, interest income and other miscellaneous income.
Income Tax Expense increased $2.8 million in 2020 primarily due to increased income before income taxes along with reductions in certain permanent differences. These increases were partially offset by production tax credits generated in 2020 from our Merricourt wind farm placed in service in the fourth quarter of 2020. Our effective tax rate was 17.4% in 2020 and 16.7% in 2019. See Note 12 to our consolidated financial statements included in the report on Form 10-K for additional information regarding factors impacting our effective tax rate in 2020 and 2019.
ELECTRIC SEGMENT RESULTS
The following table summarizes the results of operations for our Electric segment for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019 $ change % change
Retail Sales Revenue $ 389,522 $ 406,478 $ (16,956) (4.2) %
Transmission Services Revenues 44,001 40,542 3,459 8.5
Wholesale Revenues 4,857 5,007 (150) (3.0)
Other Electric Revenues 7,750 7,070 680 9.6
Total Operating Revenue 446,130 459,097 (12,967) (2.8)
Production Fuel 46,296 59,256 (12,960) (21.9)
Purchased Power 61,698 72,066 (10,368) (14.4)
Operation and Maintenance Expenses 150,848 153,529 (2,681) (1.7)
Depreciation and Amortization 63,171 60,044 3,127 5.2
Property Taxes 17,034 15,785 1,249 7.9
Operating Income $ 107,083 $ 98,417 $ 8,666 8.8 %
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales 4,776,687 4,969,089 (192,402) (3.9) %
Wholesale kwh Sales - Company Generation 236,528 198,569 37,959 19.1
Heating Degree Days 6,174 7,240 (1,066) (14.7)
Cooling Degree Days 534 392 142 36.2
Results of operations for the Electric segment are impacted by fluctuations in weather conditions and the resulting demand for electricity for heating and cooling. The following table shows heating and cooling degree days as a percent of normal.
2020 2019
Heating Degree Days 97.2 % 115.6 %
Cooling Degree Days 116.3 % 85.0 %
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in 2020 and 2019, and between years.
2020 vs
Normal
2020 vs
2019 vs
Normal
Effect on Diluted Earnings Per Share $ - $ (0.08) $ 0.08
Retail Sales Revenue decreased $17.0 million driven by:
•A $25.6 million decrease in revenue related to the recovery of decreased fuel and purchased power costs to serve retail customers. Decreased demand caused by the milder winter weather and COVID-19-related impacts on our commercial and industrial customers contributed to a 19.0% decrease in kwhs generated for system use. Purchased power costs decreased, despite a 6.9% increase in kwhs purchased, due to a 19.9% decrease in purchased power prices resulting from a decrease in market demand between periods.
•A $4.4 million decrease in revenue related to decreased kwh consumption due to milder winter weather in 2020 compared with 2019, reflected in the 14.7% decrease in HDDs in 2020 compared with 2019. The decrease in consumption due to the decrease in HDDs was only partially offset by an increase in consumption related to a 36.2% increase in CDDs in the summer of 2020 compared with the summer of 2019.
•A $2.9 million decrease due to decreased kwh sales to commercial and industrial customers mainly due to COVID-19-related impacts in 2020.
These decreases in revenue were partially offset by:
•An $11.0 million increase in Minnesota and North Dakota Renewable Rider Adjustment revenues related to earning a return on funds invested in Merricourt while the project was under construction.
•A $3.1 million increase in revenues from the North Dakota Generation Rider which went into effect in July 2019 to provide a return on funds invested in Astoria Station while the generation project is under construction.
•A $1.0 million increase due to a positive price variance arising from variances in sales under different tariffs.
•An $0.8 million increase in Conservation Improvement Program (CIP) and transmission cost recovery revenues.
Transmission Services Revenues increased $3.5 million due to increases of $1.9 million in transmission tariff revenues and $1.6 million in revenues from the recovery of infrastructure investment costs from interconnected generators.
Other Electric Revenue increased $0.7 million, which includes $1.9 million from the recovery of infrastructure investment costs from a large commercial customer in 2020, partially offset by a $1.2 million decrease in revenue from steam sales to an ethanol producer driven by lower natural gas prices resulting in the producer switching to an alternative generation source to meet its steam requirements.
Production Fuel costs decreased $13.0 million mainly as a result of a 22.0% decrease in kwhs generated from our fuel-burning plants due to lower customer demand and a 6.9% increase in kwh purchases for system use. Decreased system demand and lower prices for alternative fuels and generation sources, which drove market prices for electricity down in 2020, contributed to decreases in generation of 37.7% at Big Stone Plant and 36.7% at Hoot Lake Plant. These decreases were partially offset by a 13.7% increase in generation at Coyote Station, which was offline for maintenance during the entire second quarter of 2019.
Purchased Power costs to serve retail customers decreased $10.4 million as a result of a 19.9% decrease in purchased power prices, partially offset by a 6.9% increase in kwhs purchased. The increase in kwhs purchased was mainly due to a decrease in market prices for electricity in 2020 driven by low prices for natural gas-fired generation in combination with lower demand in 2020 due to COVID-19-related declines in electricity use by commercial and industrial consumers.
Operating and Maintenance Expense decreased $2.7 million mainly due to:
•A $2.8 million decrease in contracted services and materials and supplies expenses, mainly related to the Coyote Station's extended maintenance outage and Hoot Lake Plant turbine repairs in the second quarter of 2019 with no comparable expenses in 2020.
•A $2.7 million decrease in transmission tariff expenses related to decreased rates.
•A $1.3 million decrease in travel, meals and employee education expenses due to COVID-19-related travel restrictions.
•A $0.8 million decrease in pollution control reagent costs due to a 22.4% decrease in kwhs generated at Otter Tail Power Company's coal- burning plants.
These decreases in expense were partially offset by:
•A $2.0 million increase in customer bad debt expense provisions, mainly due to adoption of COVID-19-related service suspension and debt collection policies and financial constraints on some customers due to COVID-19.
•A $1.0 million increase in contribution commitments to Otter Tail Power Company's charitable foundation.
•A $0.6 million increase in land easement payments related to Merricourt.
•A $0.6 million increase in CIP expenditures.
•A $0.5 million increase in labor and benefit costs.
Depreciation and Amortization expense increased $3.1 million mainly due to 2019 capital additions for generation and transmission plant, a new customer information system, and the inception of depreciation of Merricourt assets in the fourth quarter of 2020.
Property Taxes increased $1.2 million due to property additions and increased valuations on existing property.
MANUFACTURING SEGMENT RESULTS
The following table summarizes the results of operations for our Manufacturing segment for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019 $ change % change
Operating Revenues $ 238,769 $ 277,204 $ (38,435) (13.9) %
Cost of Products Sold 180,432 215,179 (34,747) (16.1)
Other Operating Expenses 27,301 29,895 (2,594) (8.7)
Depreciation and Amortization 14,933 14,261 672 4.7
Operating Income $ 16,103 $ 17,869 $ (1,766) (9.9) %
Operating Revenues decreased $38.4 million primarily due to the following:
•At BTD, revenues decreased $37.3 million. Parts revenue was down $37.5 million, mainly due to decreased sales volumes across all end markets served by BTD, in order of magnitude: construction, industrial and energy equipment, lawn and garden, recreational vehicle and agricultural end markets. The decreased sales mainly resulted from customers implementing temporary plant shutdowns due to the COVID-19 pandemic. Lower prices related to the pass through of lower material costs accounted for an $18.5 million decrease in parts revenue, partially offset by $1.7 million in revenue increases due to product mix exclusive of the pass through of material cost reductions.
•At T.O. Plastics, revenues decreased $1.1 million. A $1.3 million increase in horticultural product sales was more than offset by decreases of $1.7 million in life science product sales, $0.5 million in industrial sales and $0.2 million in extrusion sales. However, COVID-19 had a negative impact on life science product sales as elective and non-critical surgeries and medical procedures were cancelled or delayed. Industrial product sales decreased due to COVID-19-related impacts on customer’s sales and service activities.
Cost of Products Sold decreased $34.7 million due to the following:
•Cost of products sold at BTD decreased $34.2 million as a result of both the decreased sales volume and the $18.5 million in lower material costs passed through to customers, but also due to labor cost decreases due to second quarter 2020 workforce reductions.
•Cost of products sold at T.O. Plastics decreased $0.6 million due to a $2.1 million decrease in material costs related to the decrease in sales volume, mostly offset by increases in other indirect costs and an increase in rental costs for more warehouse space.
Other Operating Expenses decreased $2.6 million primarily due to a $2.1 million decrease in operating expenses at BTD, mainly due to reductions in travel and outside services expenditures related to initiatives taken at BTD to mitigate the negative impacts on sales related to COVID-19. Operating expenses at T.O. Plastics decreased $0.5 million, including a $0.3 million write off of the value of destroyed property in 2019 related to the March 2019 partial roof collapse. T.O. Plastics travel and other selling expenses decreased by $0.2 million due to restrictions on activity in response to COVID-19-related safety initiatives.
BTD incurred $1.0 million in termination costs in the second quarter of 2020, with $0.9 million charged to cost of products sold and $0.1 million charged to operating expense, related to headcount reductions across all its sites in response to the ongoing reduction in sales volume.
Depreciation and Amortization increased $0.7 million due to an increase of $0.4 million at BTD related to recent investments in equipment and tooling, and a $0.3 million increase at T.O. Plastics including several large tooling and equipment projects and the addition of a pelletizer room.
PLASTICS SEGMENT RESULTS
The following table summarizes the results of operations for our Plastics segment for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019 $ change % change
Operating Revenues $ 205,249 $ 183,257 $ 21,992 12.0 %
Cost of Products Sold 148,835 139,974 8,861 6.3
Other Operating Expenses 14,987 11,393 3,594 31.5
Depreciation and Amortization 3,604 3,451 153 4.4
Operating Income $ 37,823 $ 28,439 $ 9,384 33.0 %
Operating Revenues increased $22.0 million due to an 8.0% increase in pounds of PVC pipe sold in combination with a 3.7% increase in the price per pound sold. The sales volume increase resulted from improved market conditions during the third and fourth quarters of 2020 driven by strong construction markets and concerns over raw material supply and product availability due to two resin suppliers invoking force majeure, anticipated impacts from hurricanes, significant global demand for PVC resin and limited pipe inventory across the country.
Cost of Products Sold increased $8.9 million due to the increase in sales volume, partially offset by a 1.5% decrease in the cost per pound of PVC pipe sold primarily due to lower material input costs.
Other Operating Expenses increased $3.6 million including a $2.0 million contribution commitment to Otter Tail Corporation’s charitable foundation in 2020 and additional increases in other expenses, primarily performance-based compensation.
CORPORATE COSTS
The following table summarizes Corporate results of operations for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019 $ change % change
Other Operating Expenses $ 12,794 $ 9,515 $ 3,279 34.5 %
Depreciation and Amortization 329 330 (1) (0.3)
Operating Loss $ 13,123 $ 9,845 $ 3,278 33.3 %
Other Operating Expenses increased $3.3 million mainly as a result of a $2.5 million contribution commitment to Otter Tail Corporation’s charitable foundation in 2020 and a $1.5 million increase in labor and benefit expenses, partially offset by a $0.6 million decrease in corporate costs charged to subsidiaries.
REGULATORY RATE MATTERS
The following provides a summary of our current general rates and a summary of recent rate case filings and rate rider filings that have or are expected to have a material impact on our operating results, financial position or cash flows.
GENERAL RATES
The following includes a summary of electric base rates 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 06/01/19 $ 198.6 7.51 % 9.41 % 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 annual customer refunds of 50% of any weather-normalized revenue creating earnings in excess of the authorized ROE up to a maximum of 9.50% and 100% refunds revenue creating earnings above 9.50%.
Minnesota Rate Case: On November 2, 2020, OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of approximately $14.5 million, or 6.77%, based on an allowed rate of return on rate base of 7.59% and an allowed rate of return on equity of 10.20% on an equity ratio of 52.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost recovery, with some costs moving from riders into base rates and fuel, and purchased power and conservation program costs moving out of base rates and into riders. The filing also included a revenue decoupling mechanism proposal. Such mechanisms are designed to separate a utility's revenue from changes in energy sales. The decoupling mechanism uses a tracker balance in which authorized customer margins are subject to a true-up mechanism to maintain or cap a given level of revenues.
On December 3, 2020, the MPUC approved an interim annual rate increase of $6.9 million, or 3.2%, effective January 1, 2021. This approval was provided after an alternative recovery proposal was submitted by OTP, which, among other changes, requested the extension of depreciable lives of certain wind-related assets and deferred certain cost recovery decisions to the final rate determination. In the aggregate, this alternative recovery proposal reduced operating costs and delayed recovery of certain other costs by approximately $7.0 million to lessen the interim rate impact on customers.
RATE RIDERS
The following table includes a summary of pending and recently concluded rate rider proceedings:
Recovery Filing Amount Effective
Mechanism Jurisdiction Status Date (in millions) Date Notes
RRR - 2019 MN Approved 06/21/19 $ 12.5 01/01/20 Includes return on Merricourt construction costs.
TCR - 2018 MN Approved 05/07/20 10.3 01/21/20 See below for additional details.
RRR - 2020 ND Approved 03/18/20 5.8 04/01/20 Includes return on Merricourt construction costs.
GCR - 2020 ND Approved 06/10/20 6.2 07/01/20 Includes return on Astoria Station construction costs.
TCR - 2020 ND Approved 08/31/20 5.6 01/21/20 Includes recovery of new transmission assets.
TCR - 2020 SD Approved 01/29/20 2.3 03/02/20 Annual update to transmission cost recovery rider.
PIR - 2020 SD Approved 05/31/20 1.6 09/01/20 Includes return on Merricourt and Astoria Station construction costs.
TCR - 2021 ND Approved 11/18/20 5.6 01/01/21 Includes recovery of eight new transmission projects.
RRR - 2021 ND Requested 12/31/20 11.8 - Includes return on Merricourt construction costs.
TCR - 2021 SD Requested 10/30/20 2.2 - Includes recovery of two new transmission projects.
Minnesota TCR: On May 1, 2017, the MPUC ordered OTP to include in the TCR rider retail rate base the Minnesota jurisdictional share of OTP's investments in certain transmission assets and all revenues received from other utilities under MISO's tariffed rates as a credit in its TCR revenue requirement calculations. The order had the effect of diverting interstate wholesale revenues that have been approved by the FERC to offset the FERC-approved expenses, effectively reducing OTP's recovery of FERC-approved expense levels.
On August 18, 2017, OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC transmission projects in the TCR rider. On June 11, 2018, the Minnesota Court of Appeals reversed the MPUC's order. On July 11, 2018 the MPUC filed a petition for review of the decision to the Minnesota Supreme Court, which granted review of the appellate court decision. The Minnesota Supreme Court issued its opinion on April 22, 2020, concluding the MPUC lacked authority to amend an existing TCR rider approved under Minnesota state law to include the costs and revenues associated with these transmission projects and affirming the decision of the Minnesota Court of Appeals.
On October 22, 2020, the MPUC approved OTP's request for a Minnesota TCR rider update with the exclusion of these transmission projects. In addition, the MPUC approved the inclusion of three new projects previously requested in the Minnesota TCR rider eligibility petition. Updated rates went into effect in January 2021. With this decision, one-half of the projected TCR rider tracker balance at December 2020 of $13.4 million will be included in the 2021 TCR rider annual revenue requirement, with the remainder included in the next annual update. The annual updates provide for recovery of approximately $2.6 million in MISO revenues credits to Minnesota customers through the TCR rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of $2.6 million during the year ended December 31, 2020.
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 capital expenditures related to expansion of existing businesses and development of new projects. Our liquidity, including our operating cash flows and access to capital markets, can be impacted by macroeconomic factors outside of our control, such as those which may be caused by COVID-19. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of December 31, 2020, we were in compliance with all debt covenants (see the Financial Covenant section under Capital Resources below).
We continue to have sufficient liquidity under our credit facilities to support our business based on the current economic environment. We are closely monitoring our liquidity and capital market conditions given the uncertainty surrounding the impact of COVID-19, which could have an adverse effect on the availability and terms of future debt and equity financing.
The following table presents the status of our lines of credit as of December 31, 2020 and 2019:
2020 2019
(in thousands) Line Limit Amount Outstanding Letters
of Credit Amount Available Amount Available
Otter Tail Corporation Credit Agreement $ 170,000 $ 65,166 $ - $ 104,834 $ 164,000
OTP Credit Agreement 170,000 15,831 14,101 140,068 154,524
Total $ 340,000 $ 80,997 $ 14,101 $ 244,902 $ 318,524
We have an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the Otter Tail Corporation Credit Agreement. Should additional liquidity be needed, this agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.
CASH FLOWS
The following is a discussion of our cash flows for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019
Net Cash Provided by Operating Activities $ 211,921 $ 185,037
Net Cash Provided by Operating Activities increased $26.9 million primarily due to a $9.0 million increase in net income, a $11.3 million decrease in discretionary contributions to our funded pension plan and a $10.3 million reduction in working capital. Our working capital decrease was primarily the result of increased accounts payable due to increased construction program costs in our Electric segment. Our working capital level was also impacted by a decrease in inventories in our Manufacturing segment due to strong sales volumes in the fourth quarter of 2020 and increased outstanding receivables of $6.3 million primarily from our Manufacturing and Plastics segments due to strong sales volumes in the fourth quarter of 2020. Our average collection period on outstanding receivables on a consolidated basis increased from approximately 31 days in 2019 to approximately 34 days in 2020.
(in thousands) 2020 2019
Net Cash Used in Investing Activities $ 375,652 $ 209,472
Net Cash Used in Investment Activities increased $166.2 million driven by our Electric segment capital investment plan, including construction of our Merricourt and Astoria Station projects.
(in thousands) 2020 2019
Net Cash Provided by Financing Activities $ 143,695 $ 44,773
Net Cash Provided by Financing Activities increased $98.9 million as we issued debt and equity in 2020 and increased borrowings under our short-term debt agreements primarily to finance our Electric segment capital investments. We issued $75.0 million of long-term debt in 2020 and increased borrowings under our short-term debt arrangements by $75.0 million. In addition, we raised net proceeds of $49.7 million from issuances of common shares under our various equity programs, including our At-the-Market offering program and our Automatic Dividend Reinvestment and Share Purchase Plan. We also paid $60.3 million in common dividends in 2020. Financing activities in 2019 included the issuance of $100 million of long-term debt and the issuance of common shares generating net proceeds of $17.0 million. Proceeds from these debt and equity issuances were used to fund Electric segment construction costs and repay $12.6 million in short-term debt. We paid $55.7 million in common dividends in 2019.
CAPITAL REQUIREMENTS
CAPITAL EXPENDITURES
We have a capital expenditure program for expanding, upgrading and improving our plants and operating equipment. Typical uses of cash for capital expenditures are investments in electric generation facilities and environmental upgrades, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. The capital expenditure program is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our financial condition.
The following provides a summary of capital expenditures for the years ended December 31, 2020 and 2019 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2021 through 2025:
(in millions) 2019 2020 2021 2022 2023 2024 2025 Total
Electric Segment:
Renewables and Natural Gas Generation $ 31 $ 104 $ 3 $ 1 $ 1 $ 140
Technology and Infrastructure 6 25 32 28 18 109
Distribution Plant Replacements 24 27 30 30 27 138
Transmission (includes replacements) 23 25 31 30 29 138
Other 29 30 25 23 21 128
Total Electric Segment $ 187 $ 357 $ 113 $ 211 $ 121 $ 112 $ 96 $ 653
Manufacturing and Plastics Segments 20 15 20 20 36 15 18 109
Total Capital Expenditures $ 207 $ 372 $ 133 $ 231 $ 157 $ 127 $ 114 $ 762
Total Electric Utility Average Rate Base $ 1,170 $ 1,385 $ 1,585 $ 1,630 $ 1,720 $ 1,754 $ 1,769
Rate Base Growth 14.4 % 2.8 % 5.5 % 2.0 % 0.9 %
CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at December 31, 2020 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 $ 848 $ 221 $ 30 $ - $ 597
Coal Contracts 573 23 47 49 454
Interest on Debt Obligations 484 35 55 54 340
Other Purchase Obligations (including land easements) 77 33 4 4 36
Capacity and Energy Requirements 184 16 24 24 120
Postretirement Benefit Obligations 118 4 11 12 91
Operating Lease Obligations 22 5 8 6 3
Total Contractual Cash Obligations $ 2,306 $ 337 $ 179 $ 149 $ 1,641
Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company under the lignite sales agreement that ends in 2040. Postretirement benefit obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan, but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make a contribution to that plan.
COMMON STOCK DIVIDENDS
We paid dividends to our common stockholders totaling $60.3 million, or $1.48 per share, in 2020. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 14 to our consolidated financial statements included in this report on Form 10-K for additional information. The decision to declare a dividend is reviewed quarterly by our Board of Directors. On February 1, 2021 our Board of Directors increased the quarterly dividend from $0.37 to $0.39 per common share.
CAPITAL RESOURCES
Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings, and alternative financing arrangements such as leasing. Equity or debt financing will be required in the period 2021 through 2025 given the expansion plans related to our Electric segment to fund construction of new rate base and transmission investments, in the event we decide 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, 2018 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 through the expiration date of May 3, 2021.
On November 8, 2019 we entered into a Distribution Agreement with KeyBank under which we may offer and sell our common shares from time to time through KeyBank, as our distribution agent, up to an aggregate sales price of $75.0 million through an At-the-Market offering program. In 2020, we received proceeds of $37.0 million1, net of commissions paid to KeyBank of $0.5 million1 from the issuance of 868,4841 shares under this program. In total from the inception of the program through December 31, 2020, we have received proceeds under this program of $54.4 million.
On May 3, 2018 we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the Plan expires on May 3, 2021. In 2020, we issued 320,173 shares for proceeds of $13.4 million under the Plan. As of December 31, 2020, 899,859 shares remain available for purchase or issuance under the Plan.
We intend to file new shelf registration statements in 2021 following the expiration of our current registration statements on May 3, 2021.
SHORT-TERM DEBT
Otter Tail Corporation and Otter Tail Power Company are each party to a credit agreement (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. The agreements generally bear interest at LIBOR plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the issuer. The LIBOR credit spread for the OTC Credit Agreement and OTP Credit Agreement was 1.50% and 1.25%, respectively, at December 31, 2020.
The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2020:
(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 - 14,101
Amount Outstanding at Year-End 65,166 15,831
Average Amount Outstanding During Year 32,355 734
Maximum Amount Outstanding During the Year 65,166 15,831
Interest Rate at Year-End 1.6 % 1.4 %
Maturity Date October 31, 2024 October 31, 2024
1Each facility includes an accordion featuring allowing the borrower to increase the borrowing limit if certain terms and conditions are met.
LONG-TERM DEBT
At December 31, 2020, we had $767.2 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 2021 to 2050. One OTP debt instrument with a principal balance of $140.0 million matures in December 2021. We anticipate issuing long-term debt in 2021 with the proceeds used to satisfy this maturing instrument.
1In the fourth quarter of 2020, we received proceeds of $11.5 million, net of commission of $0.1 million, from the issuance of 280,400 shares.
Financial Covenants
Certain of our short- and long-debt agreements require Otter Tail Corporation and OTP to maintain certain financial covenants. As of December 31, 2020, we were in compliance with these financial covenants as further described below:
Otter Tail Corporation 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, 2020, our Interest-Bearing Debt to Total Capitalization was 0.49 to 1.00, our Interest and Dividend Coverage Ratio was 4.55 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, 2020, OTP's Interest-Bearing Debt to Total Capitalization was 0.46 to 1.00, its Interest and Dividend Coverage Ratio was 3.66 to 1.00 and it had no Priority Indebtedness outstanding.
None of our debt agreements include any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.
Credit Ratings
The credit ratings of Otter Tail Corporation and OTP as of December 31, 2020 are summarized below:
Otter Tail Corporation OTP
Moody's Fitch S&P Moody's Fitch S&P
Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB- BBB A3 BBB BBB+
Senior Unsecured Debt n/a BBB- n/a n/a BBB+ BBB+
Outlook Stable Stable Negative Stable Stable Stable
OFF-BALANCE-SHEET ARRANGEMENTS
As of December 31, 2020 we have outstanding letters of credit totaling $17.4 million, a portion of which reduces our borrowing capacity under our lines of credit. No outstanding letters of credit are reflected in outstanding short-term debt on our consolidated balance sheets. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
Financial statements prepared in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. While we believe the estimates and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates. 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 more 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 for 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 sheet and recognize in the consolidated statement of income as an expense or income item in the period in which this accounting treatment is no longer applicable.
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. Also, a reduction in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well below assumed rates of return or an increase in the anticipated life expectancy of plan participants could result in significant increases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.
The pension benefit cost for 2021 for our noncontributory funded pension plan is expected to be $8.4 million compared to $6.8 million in 2020, reflecting a decrease in the estimated discount rate used to determine annual benefit cost accruals from 3.47% in 2020 to 2.78% in 2021. The assumed rate of return on pension plan assets is 6.51% for 2021 compared with 6.88% for 2020. In selecting the discount rate, we consider the yields of fixed income debt securities, which have ratings of “Aa” published by recognized rating agencies, along with bond matching models specific to our plan’s cash flows as a basis to determine the rate.
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.
The following table summarizes the impact on 2020 pension and postretirement costs for a 0.25 increase or decrease, holding all other variables constant, on certain key assumptions:
(in thousands) +0.25 -0.25
Pension Plan:
Discount Rate $ (1,158) $ 1,160
Rate of Increase in Future Compensation 625 (610)
Long-Term Return on Plan Assets (800) 800
Other Postretirement Benefits:
Discount Rate (366) 302
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 includes fair value estimates using multiples derived from comparable enterprise values to EBITDA and revenue multiples, comparable price earnings ratios 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 2020 indicated no impairment was present for either reporting unit and the estimated fair value of each reporting unit substantially exceeded the respective carrying value. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on the best information available. However, these estimates and assumptions inherently include a degree of uncertainty. 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.
Interest Rate Risk
Our exposure to interest rate risk as of December 31, 2020 arises from outstanding short-term debt which is subject to variable rates of interest based on benchmark interest rates, primarily LIBOR. As of December 31, 2020 we had $81.0 million of short-term debt outstanding. Holding other variables constant, a one percentage point change in interest rates would have had an approximate $0.3 million impact to interest charges in 2020 based upon our average outstanding short-term debt during the year.
All of our outstanding long-term debt obligations on December 31, 2020 have fixed interest rates and thus are not subject to 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.
Commodity Price Risk
The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum, and polystyrene and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.
The companies in our Plastics segment are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.
We do not engage in any hedging activities to manage our commodity price risk.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, based on the 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 Controls 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 audit 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 Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and 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 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 rate regulation 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 assess 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 these incurred costs may have on customers.
Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, regulatory assets and liabilities, operating revenues and expenses, depreciation expense, income taxes and multiple disclosures in the notes to the financial statements. 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 assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital expenditures or operating costs that management believes were prudently incurred, and (3) a refund to customers. 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 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 property, plant, and equipment and deferred 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 property, plant, and equipment; regulatory assets or liabilities; and 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.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•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 inquired of management about property, plant, and equipment that may be abandoned. We inspected the capital-projects budget and construction-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management’s assertion regarding probability of an abandonment.
•We compared actual spend for projects that have been capitalized to property, plant, and equipment to budget. We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects.
•We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, 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.
Goodwill-Manufacturing Reporting Unit-Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
The Company’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its carrying value. The Company performs quantitative assessments of goodwill annually as of December 31 (the “measurement date”) and more frequently as events or circumstances require. The Company estimates the fair value of its Manufacturing reporting unit by primarily using the discounted cash flow model. The determination of the fair value using the discounted cash flow model requires management to make significant estimates and assumptions related to forecasts of future operating results and cash flows. The Manufacturing reporting unit’s operating results and cash flows are sensitive to changes in demand. The goodwill balance was $37.6 million as of December 31, 2020, of which $18.3 million was allocated to the Manufacturing
reporting unit. The fair value of the Manufacturing reporting unit exceeded its carrying value as of the measurement date and, therefore, no impairment was recognized.
We identified goodwill for the Manufacturing reporting unit as a critical audit matter because of the significant judgments made by management to estimate its fair value and the difference between its fair value and carrying value and the sensitivity of the Manufacturing reporting unit’s operations to changes in demand. This required a high degree of auditor judgment and an increased extent of effort when performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future operating results and cash flows.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to forecasts of future operating results and cash flows used by management to estimate the fair value of the Manufacturing reporting unit included the following, among others:
•We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair value of the Manufacturing reporting unit, such as controls related to forecasts of future operating results and cash flows.
•We evaluated management’s ability to accurately forecast future operating results and cash flows by comparing actual results to management’s historical forecasts.
•We evaluated the reasonableness of management’s operating results and cash flow forecasts by comparing the forecasts to:
-Historical operating results and cash flows.
-Internal communications to management and the Board of Directors.
-Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 19, 2021
We have served as the Company’s auditor since 1944.
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
(in thousands, except share data) 2020 2019
Assets
Current Assets
Cash and Cash Equivalents $ 1,163 $ 21,199
Receivables, net of allowance for credit losses 113,959 107,631
Inventories 92,165 97,851
Regulatory Assets 21,900 21,650
Other Current Assets 5,645 6,529
Total Current Assets 234,832 254,860
Noncurrent Assets
Investments 51,856 45,374
Property, Plant and Equipment, net of accumulated depreciation 2,049,273 1,753,794
Regulatory Assets 168,395 144,138
Intangible Assets, net of accumulated amortization 10,144 11,290
Goodwill 37,572 37,572
Other Noncurrent Assets 26,282 26,567
Total Noncurrent Assets 2,343,522 2,018,735
Total Assets $ 2,578,354 $ 2,273,595
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Debt $ 80,997 $ 6,000
Current Maturities of Long-Term Debt 140,087 183
Accounts Payable 130,805 120,775
Accrued Salaries and Wages 26,908 22,730
Accrued Taxes 18,831 17,525
Regulatory Liabilities 16,663 7,480
Other Current Liabilities 22,495 15,048
Total Current Liabilities 436,786 189,741
Noncurrent Liabilities and Deferred Credits
Pensions Benefit Liability 114,055 98,970
Other Postretirement Benefits Liability 67,359 71,437
Regulatory Liabilities 233,973 239,906
Deferred Income Taxes 153,376 131,941
Deferred Tax Credits 17,405 18,626
Other Noncurrent Liabilities 60,002 51,911
Total Noncurrent Liabilities and Deferred Credits 646,170 612,791
Commitments and Contingencies (Note 13)
Capitalization
Long-Term Debt, net of current maturities 624,432 689,581
Shareholders' Equity
Common Shares: 50,000,000 share authorized of $5 par value; 41,469,879 and 40,157,591 outstanding
at December 31, 2020 and 2019
207,349 200,788
Additional Paid-In Capital 414,246 364,790
Retained Earnings 257,878 222,341
Accumulated Other Comprehensive Loss (8,507) (6,437)
Total Shareholders' Equity 870,966 781,482
Total Capitalization 1,495,398 1,471,063
Total Liabilities and Shareholders' Equity $ 2,578,354 $ 2,273,595
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
(in thousands, except per-share amounts) 2020 2019 2018
Operating Revenues
Electric $ 446,088 $ 459,048 $ 450,198
Product Sales 444,019 460,455 466,249
Total Operating Revenues 890,107 919,503 916,447
Operating Expenses
Electric Production Fuel 46,296 59,256 66,815
Electric Purchased Power 61,698 72,066 68,355
Electric Operating and Maintenance Expenses 150,848 153,529 155,534
Cost of Products Sold (excluding depreciation) 329,257 355,119 354,559
Other Nonelectric Expenses 55,051 50,782 51,544
Depreciation and Amortization 82,037 78,086 74,666
Electric Property Taxes 17,034 15,785 15,585
Total Operating Expenses 742,221 784,623 787,058
Operating Income 147,886 134,880 129,389
Other Income and Expense
Interest Charges 34,447 31,411 30,408
Nonservice Cost Components of Postretirement Benefits 3,437 4,293 5,509
Other Income 6,055 5,112 3,461
Income Before Income Taxes 116,057 104,288 96,933
Income Tax Expense 20,206 17,441 14,588
Net Income $ 95,851 $ 86,847 $ 82,345
Weighted-Average Common Shares Outstanding:
Basic 40,710 39,721 39,600
Diluted 40,905 39,954 39,892
Earnings Per Share:
Basic $ 2.35 $ 2.19 $ 2.08
Diluted $ 2.34 $ 2.17 $ 2.06
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31,
(in thousands) 2020 2019 2018
Net Income $ 95,851 $ 86,847 $ 82,345
Other Comprehensive Income (Loss):
Unrealized Gain (Loss) on Available-for-Sale Securities:
Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income During Period 13 16 (105)
Unrealized Gains (Losses) Arising During Period 184 147 (61)
Income Tax (Expense) Benefit (42) (34) 35
Available-for-Sale Securities, net of tax 155 129 (131)
Pension and Postretirement Benefit Plans:
Actuarial (Losses) Gains net of Regulatory Allocation Adjustment (3,571) (2,779) 1,919
Amortization of Unrecognized Postretirement Benefit Losses and Costs 550 565 985
Income Tax Benefit (Expense) 796 576 (755)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act - - (531)
Pension and Postretirement Benefit Plan, net of tax (2,225) (1,638) 1,618
Total Other Comprehensive Income (Loss)
(2,070) (1,509) 1,487
Total Comprehensive Income $ 93,781 $ 85,338 $ 83,832
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands, except common shares outstanding) Common
Shares
Outstanding Par Value,
Common
Shares Additional Paid-In Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss)1
Total Shareholders' Equity
Balance, December 31, 2017 39,557,491 $ 197,787 $ 343,450 $ 161,286 $ (5,631) $ 696,892
Common Stock Issuances, Net of Expenses 178,601 893 (986) (93)
Common Stock Retirements and Forfeitures (71,208) (356) (2,655) (3,011)
Net Income 82,345 82,345
Other Comprehensive Income 1,487 1,487
Stock Compensation Expense 4,441 4,441
Common Dividends ($1.34 per share)
(53,198) (53,198)
Balance, December 31, 2018 39,664,884 $ 198,324 $ 344,250 $ 190,433 $ (4,144) $ 728,863
Common Stock Issuances, Net of Expenses 547,931 2,740 17,036 19,776
Common Stock Retirements and Forfeitures (55,224) (276) (2,454) (2,730)
Net Income 86,847 86,847
Other Comprehensive Loss (1,509) (1,509)
Stranded Tax Transfer 784 (784) -
Stock Compensation Expense 5,958 5,958
Common Dividends ($1.40 per share)
(55,723) (55,723)
Balance, December 31, 2019 40,157,591 $ 200,788 $ 364,790 $ 222,341 $ (6,437) $ 781,482
Common Stock Issuances, Net of Expenses 1,350,505 6,752 45,050 51,802
Common Stock Retirements and Forfeitures (38,217) (191) (1,878) (2,069)
Net Income 95,851 95,851
Other Comprehensive Loss (2,070) (2,070)
Stock Compensation Expense 6,284 6,284
Common Dividends ($1.48 per share)
(60,314) (60,314)
Balance, December 31, 2020 41,469,879 $ 207,349 $ 414,246 $ 257,878 $ (8,507) $ 870,966
1Accumulated Other Comprehensive Income (Loss) as of December 31 is comprised of the following:
(in thousands) 2020 2019 2018
Unrealized Gain (Loss) on Marketable Equity Securities:
Before Tax $ 265 $ 68 $ (95)
Tax Effect (56) (14) 20
Stranded Tax Effect - - (10)
Unrealized Gain (Loss) on Marketable Equity Securities, net of tax 209 54 (85)
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits:
Before Tax (11,793) (8,772) (6,558)
Tax Effect 3,077 2,281 1,705
Stranded Tax Effect - - 794
Unamortized Actuarial Losses and Prior Service Costs Related to Pension and Postretirement Benefits, net of tax (8,716) (6,491) (4,059)
Accumulated Other Comprehensive Loss:
Before Tax (11,528) (8,704) (6,653)
Tax Effect 3,021 2,267 1,725
Stranded Tax Effect - - 784
Net Accumulated Other Comprehensive Loss $ (8,507) $ (6,437) $ (4,144)
See accompanying notes to consolidated financial statements.
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
(in thousands) 2020 2019 2018
Operating Activities
Net Income $ 95,851 $ 86,847 $ 82,345
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization 82,037 78,086 74,666
Deferred Tax Credits (1,221) (1,348) (1,405)
Deferred Income Taxes 15,201 11,507 19,224
Change in Deferred Debits and Other Assets (26,130) (15,502) 941
Discretionary Contribution to Pension Plan (11,200) (22,500) (20,000)
Change in Noncurrent Liabilities and Deferred Credits 34,421 33,534 (2,414)
Allowance for Equity/Other Funds Used During Construction (4,063) (2,553) (2,194)
Stock Compensation Expense 6,284 5,958 4,441
Other-Net (463) 76 -
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables (6,328) (1,860) (8,559)
Change in Inventories 5,686 8,419 (18,236)
Change in Other Current Assets (573) 2,919 (754)
Change in Payables and Other Current Liabilities 19,744 (171) 14,997
Change in Interest Payable and Income Taxes Receivable 2,675 1,625 396
Net Cash Provided by Operating Activities 211,921 185,037 143,448
Investing Activities
Capital Expenditures (371,553) (207,365) (105,425)
Proceeds from Disposal of Noncurrent Assets 5,011 8,519 2,378
Cash Used for Investments and Other Assets (9,110) (10,626) (4,372)
Net Cash Used in Investing Activities (375,652) (209,472) (107,419)
Financing Activities
Change in Checks Written in Excess of Cash 4,849 (2,814) (345)
Net Short-Term Borrowings (Repayments) 74,997 (12,599) (93,772)
Proceeds from Issuance of Common Stock 52,432 20,338 -
Common Stock Issuance Expenses (648) (577) (108)
Payments for Shares Withheld for Employee Tax Obligations (2,069) (2,730) (3,011)
Proceeds from Issuance of Long-Term Debt 75,000 100,000 100,000
Short-Term and Long-Term Debt Issuance Expenses (370) (950) (761)
Payments for Retirement of Long-Term Debt (182) (172) (189)
Dividends Paid (60,314) (55,723) (53,198)
Net Cash Provided by Financing Activities
143,695 44,773 (51,384)
Net Change in Cash and Cash Equivalents (20,036) 20,338 (15,355)
Cash and Cash Equivalents at Beginning of Period 21,199 861 16,216
Cash and Cash Equivalents at End of Period $ 1,163 $ 21,199 $ 861
Supplemental Disclosures of Cash Flow Information
Cash Paid During the Year for:
Interest (net of amount capitalized) $ 33,199 $ 30,132 $ 28,109
Income Taxes $ 5,177 $ 4,797 $ 6,109
Supplemental Disclosure of Noncash Investing Activities
Transactions Related to Capital Additions Not Settled in Cash $ 34,265 $ 37,429 $ 13,757
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 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 complimented 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 Otter Tail Corporation and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation except 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 balance sheets to maintain consistency and comparability between periods presented. The reclassifications had no impact on previously reported current assets, total assets, current liabilities, noncurrent liabilities and deferred credits, or shareholders' equity.
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 Federal Energy Regulatory Commission (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 sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of this guidance ceases.
The accounting policies followed by OTP are subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our nonelectric businesses.
Cash Equivalents
We consider all highly liquid debt instruments purchased with maturity of 90 days or less to be cash equivalents.
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 terms 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 goods 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 kilowatt-hours (kwh) 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 to customers across several industries and certain businesses also earn revenue 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 FOB shipping point.
Plastics Segment Revenues. Our Plastics segment businesses earn revenue predominantly from the sale and delivery of standardized polyvinyl chloride (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 based on prices agreed to in a purchase order. For revenue recognized on shipped products, there is no further obligation to provide services related to such products. The shipping terms used in these instances 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 also 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 (ARPs) 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. Cost for fuel, material and supply inventories of our Electric segment are determined on an average cost basis. Cost 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, 2020 and 2019:
(in thousands) 2020 2019
Finished Goods $ 22,046 $ 31,863
Work in Process 16,210 16,508
Raw Material, Fuel and Supplies 53,909 49,480
Total Inventories $ 92,165 $ 97,851
Investments
Corporate-owned life insurance policies are recorded at cash surrender value. Debt, marketable equity securities, and money market funds 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 marketable equity securities and money market funds are recognized in earnings immediately.
The following is a summary of our investments at December 31, 2020 and 2019:
(in thousands) 2020 2019
Corporate-Owned Life Insurance Policies $ 36,825 $ 33,117
Debt Securities 9,260 8,184
Money Market Funds 4,075 2,363
Marketable Equity Securities 1,662 1,586
Other Investments 34 124
Total Investments $ 51,856 $ 45,374
The amount of unrealized gains and losses on debt securities as of December 31, 2020 and 2019 are 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, 2020 and 2019 are not material.
Property, Plant and Equipment, Retirements and Depreciation
Utility plant is stated at original cost. The cost of additions includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The amount of interest capitalized on electric utility plant was $2.1 million in 2020, $1.7 million in 2019 and $1.2 million in 2018. 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 of property are charged to operating expenses. 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 taken to the accumulated provision for depreciation reserve 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 2020, 2019 or 2018. 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 9 82
Transmission Plant 51 75
Distribution Plant 15 70
General Plant 5 55
Nonelectric Assets:
Equipment 2 12
Buildings and Leasehold Improvements 5 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 finance their own investment.
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 units 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 of the fair value being recognized as an impairment loss.
Intangible assets with finite lives, which primarily consist of customer relationships, are carried at cost less accumulated amortization. The cost of the intangible assets are amortized over their estimated useful lives, which generally range from 15 to 20 years.
Leases
We recognize right-of-use lease assets and a corresponding lease liability at the lease commencement date. The length of our lease agreements vary from less than one year 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.
We elected at the time of adopting the current leasing guidance on January 1, 2019 under an allowed practical expedient to continue with the historical accounting treatment for land easement arrangements in effect at the adoption date. Accordingly, we have not recognized any lease assets or liabilities for such arrangements.
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 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, where fair value is based on the discounted cash flows expected to be generated by 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), with accretion expense recognized in the consolidated statements of income. 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 takes 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 amortize investment tax credits and state wind energy credits over the estimated lives of the related property.
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 by 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.
Variable Interest Entity
In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), 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 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 a 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 exposure to additional costs, as a result of its involvement with CCMC, and potential impairment loss if recovery of those costs is denied by regulatory authorities, could be as high as $50.0 million, OTP’s 35% share of CCMC’s unrecovered costs as of December 31, 2020.
New Accounting Standards Adopted
Credit Losses. In June 2016 the Financial Accounting Standards Board (FASB) issued new authoritative guidance codified in Accounting Standards Codification (ASC) 326, Financial Instruments-Credit Losses, changing how entities account for credit losses on receivables and certain other assets effective for interim and annual periods beginning on or after December 31, 2019. The guidance requires the use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. We adopted this guidance on January 1, 2020. Adoption of the standard did not have a material impact on our consolidated financial statements and we did not record a cumulative effect adjustment to retained earnings on adoption as allowed for under the guidance.
Cloud Computing Costs. In August 2018 the FASB issued new authoritative guidance codified in ASC 350-40, Internal-Use Software, to address a customer's accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The amendment aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amendment also provides guidance for the presentation implementation costs in a cloud computing arrangement in the statement of financial position, the statement of income, and the statement of cash flows. The amendment was effective for interim and annual periods beginning on or after December 15, 2019, with early adoption permitted in any interim period. We adopted the amendment on January 1, 2020. There was no impact to our consolidated financial statements on adoption, but we began capitalizing implementation costs incurred in cloud computing arrangements post-adoption.
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 Midcontinent Independent System Operator, Inc. (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 and costs are not allocated to our operating segments. Corporate operating costs include items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance.
Corporate assets consist primarily of cash, prepaid expenses, investments 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, 2020, 2019 and 2018 are as follows:
(in thousands) 2020 2019 2018
Operating Revenue1
Electric $ 446,088 $ 459,048 $ 450,198
Manufacturing 238,770 277,204 268,409
Plastics 205,249 183,251 197,840
Total $ 890,107 $ 919,503 $ 916,447
Depreciation and Amortization
Electric $ 63,171 $ 60,044 $ 55,935
Manufacturing 14,933 14,261 14,794
Plastics 3,604 3,451 3,719
Corporate 329 330 218
Total $ 82,037 $ 78,086 $ 74,666
Operating Income (Loss)
Electric $ 107,083 $ 98,417 $ 88,031
Manufacturing 16,103 17,869 18,266
Plastics 37,823 28,439 32,917
Corporate (13,123) (9,845) (9,825)
Total $ 147,886 $ 134,880 $ 129,389
Interest Charges
Electric $ 29,848 $ 26,548 $ 26,365
Manufacturing 2,215 2,345 2,230
Plastics 644 718 609
Corporate 1,740 1,800 1,204
Total $ 34,447 $ 31,411 $ 30,408
Income Tax Expense (Benefit)
Electric $ 12,480 $ 12,867 $ 5,685
Manufacturing 2,939 2,784 3,393
Plastics 9,718 7,309 8,728
Corporate (4,931) (5,519) (3,218)
Total $ 20,206 $ 17,441 $ 14,588
Net Income (Loss)
Electric $ 66,778 $ 59,046 $ 54,431
Manufacturing 11,048 12,899 12,839
Plastics 27,582 20,572 23,819
Corporate (9,557) (5,670) (8,744)
Total $ 95,851 $ 86,847 $ 82,345
Capital Expenditures
Electric $ 356,581 $ 187,362 $ 87,287
Manufacturing 10,587 14,268 13,316
Plastics 4,322 5,452 4,199
Corporate 63 283 623
Total $ 371,553 $ 207,365 $ 105,425
1Amounts reflect operating revenues to external customers. Intersegment operating revenues are not material for any period presented.
The following provides the identifiable assets by segment and corporate assets as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Identifiable Assets
Electric $ 2,233,399 $ 1,931,525
Manufacturing 191,005 195,742
Plastics 99,767 92,049
Corporate 54,183 54,279
Total $ 2,578,354 $ 2,273,595
Entity-Wide Information
No single customer accounted for over 10% of our consolidated operating revenues for the years ended December 31, 2020, 2019 and 2018. All of our long-lived assets are located within the United States and substantially all of our operating revenues are to customers located within the United States.
3. Revenue
We present our operating revenues to 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, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Operating Revenues
Electric Segment
Retail: Residential $ 127,260 $ 131,988 $ 125,045
Retail: Commercial and Industrial 254,951 267,125 256,331
Retail: Other 7,311 7,365 6,875
Total Retail 389,522 406,478 388,251
Transmission 44,001 40,542 46,947
Wholesale 4,857 5,007 7,735
Other 7,708 7,021 7,265
Total Electric Segment 446,088 459,048 450,198
Manufacturing Segment
Metal Parts and Tooling 199,463 236,032 223,765
Plastic Products and Tooling 34,055 35,173 35,836
Other 5,252 5,999 8,808
Total Manufacturing Segment 238,770 277,204 268,409
Plastics Segment
PVC Pipe 205,249 183,251 197,840
Total Operating Revenue 890,107 919,503 916,447
Less: Noncontract Revenues Included Above - -
Electric Segment - Alternative Revenue Program Revenues 6,936 1,032 (439)
Total Operating Revenues from Contracts with Customers $ 883,171 $ 918,471 $ 916,886
4. Receivables
Receivables as of December 31, 2020 and 2019 are as follows:
(in thousands) 2020 2019
Receivables
Trade $ 87,048 $ 79,286
Other 8,939 8,773
Unbilled Receivables 21,187 20,911
Total Receivables 117,174 108,970
Less Allowance for Credit Losses 3,215 1,339
Receivables, net of allowance for credit losses $ 113,959 $ 107,631
The following is a summary of activity in the allowance for credit losses for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019
Beginning Balance $ 1,339 $ 1,407
Additions Charged to Expense 3,138 986
Reductions for Amounts Written-Off, Net of Recoveries (1,262) (1,054)
Ending Balance $ 3,215 $ 1,339
5. Regulatory Matters
Regulatory Assets and Liabilities
The following presents our current and long-term regulatory assets and liabilities as of December 31, 2020 and 2019 and the period we expect to recover or refund such amounts:
Period of 2020 2019
(in thousands) Recovery/Refund Current Long-Term Current Long Term
Regulatory Assets
Pension and Other Postretirement Benefit Plans1
See below $ 11,037 $ 146,071 $ 9,090 $ 130,783
Alternative Revenue Program Riders2
Up to 3 years
8,871 9,373 8,464 2,844
Asset Retirement Obligations1
Asset lives - 8,462 - 7,772
ISO Cost Recovery Trackers1
Up to 2 years
1,079 867 2,033 1,170
Unrecovered Project Costs1
Up to 3 years
361 2,989 859 478
Deferred Rate Case Expenses1
Various 360 230 260 489
Debt Reacquisition Premiums1
Up to 30 years
192 341 201 548
Other1
Various - 62 743 54
Total Regulatory Assets $ 21,900 $ 168,395 $ 21,650 $ 144,138
Regulatory Liabilities
Deferred Income Taxes Asset lives $ - $ 134,719 $ - $ 141,707
Plant Removal Obligations Asset lives - 98,707 - 97,726
Fuel Clause Adjustment Up to 1 year
10,947 - 3,982 -
Alternative Revenue Program Riders Up to 1 year
3,581 470 2,857 -
Pension and Other Postretirement Benefit Plans Up to 1 year
1,959 - 471 -
Deferred Rate Case Expenses Various - - - 401
ISO Cost Recovery Trackers Up to 2 years
- 10 - -
Other Various 176 67 170 72
Total Regulatory Liabilities $ 16,663 $ 233,973 $ 7,480 $ 239,906
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 revenue 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.
Asset Retirement Obligations represent the difference in timing of recognition of expense arising from these obligations and the amount recovered from customers.
ISO Cost Recovery Trackers represents costs incurred to serve Minnesota customers or the under collection of revenue based on expected versus actual construction costs on eligible projects.
Unrecovered Project Costs reflect costs incurred for abandoned generation and transmission assets and accelerated depreciation expense on a to-be-retired generation asset expected to be recovered from customers.
Deferred Rate Case Expenses relate to costs incurred in conjunction with recent rate cases that are currently or are expected to be recovered from customers.
Debt Reacquisition Premiums represent costs to retire debt which are being recovered from customers over the remaining original lives of the reacquired debt.
Deferred Income Taxes represents income tax benefits, arising primarily from property-related timing differences, that will be refunded to customers as these timing differences reverse.
Plant Removal Obligations represent amounts collected from customers to be used to cover actual removal costs as incurred.
Fuel Clause Adjustments represent the over-collection of fuel costs to be returned to customers.
Regulatory Matters
Minnesota TCR. On October 22, 2020, the MPUC approved OTP's request for a Minnesota TCR rider update. This rider update request followed a Minnesota Supreme Court opinion issued on April 22, 2020, concluding the MPUC lacked the authority to amend an existing TCR rider approved under Minnesota state law to include the costs and revenues associated with certain OTP transmission assets. Accordingly, the rider update excluded the costs and revenues associated with these assets, which had the effect of allowing OTP to recover the appropriate return on these assets from Minnesota customers dating back to the last TCR rider update in September 2016. As a result, OTP recognized additional rider revenue of $2.6 million during the year ended December 31, 2020.
Depreciable Lives. On July 30, 2020 the MPUC ordered a reduction in the remaining depreciable lives of Hoot Lake Plant and seven hydroelectric plants. The MPUC stipulated recoverability of the resulting increase in depreciation expense would be determined in OTP's next rate case. Based on the relevant facts and circumstances, we concluded the additional depreciation expense is probable of recovery and we have recognized a regulatory asset for the amount of incremental expense in 2020, which amounted to $2.8 million.
6. Property, Plant and Equipment
Major classes of property, plant and equipment as of December 31, 2020 and 2019 include:
(in thousands) 2020 2019
Electric Plant in Service
Production $ 1,172,362 $ 915,996
Transmission 690,647 647,474
Distribution 545,221 526,146
General 123,122 123,268
Electric Plant in Service 2,531,352 2,212,884
Construction Work in Progress 203,078 177,584
Total Gross Electric Plant 2,734,430 2,390,468
Less Accumulated Depreciation and Amortization 778,988 731,110
Net Electric Plant $ 1,955,442 $ 1,659,358
Nonelectric Property, Plant and Equipment
Equipment $ 197,389 $ 187,904
Buildings and Leasehold Improvements 55,441 53,412
Land 5,900 6,040
Nonelectric Property, Plant and Equipment 258,730 247,356
Construction Work in Progress 9,290 7,654
Total Gross Nonelectric Property, Plant and Equipment 268,020 255,010
Less Accumulated Depreciation and Amortization 174,189 160,574
Net Nonelectric Property, Plant and Equipment 93,831 94,436
Net Property, Plant and Equipment $ 2,049,273 $ 1,753,794
Depreciation expense for the years ended December 31, 2020, 2019 and 2018 totaled $78.6 million, $71.9 million and $69.7 million.
The following table provides OTP’s ownership percentages and amounts included in the December 31, 2020 and 2019 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, 2020
Big Stone Plant 53.9 % $ 332,611 $ 2,552 $ (103,504) $ 231,659
Coyote Station 35.0 % 180,991 732 (108,603) 73,120
Big Stone South-Ellendale 345 kV line 50.0 % 106,353 - (2,433) 103,920
Fargo-Monticello 345 kV line 14.2 % 78,184 - (8,029) 70,155
Big Stone South-Brookings 345 kV line 50.0 % 53,036 - (2,822) 50,214
Brookings-Southeast Twin Cities 345 kV line 4.8 % 26,291 - (2,468) 23,823
Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 - (2,670) 13,661
December 31, 2019
Big Stone Plant 53.9 % $ 337,197 $ 384 $ (98,654) $ 238,927
Coyote Station 35.0 % 184,493 83 (108,248) 76,328
Big Stone South-Ellendale 345 kV line1
50.0 % 106,343 - (819) 105,524
Fargo-Monticello 345 kV line 14.2 % 78,184 - (7,011) 71,173
Big Stone South-Brookings 345 kV line 50.0 % 53,036 - (2,016) 51,020
Brookings-Southeast Twin Cities 345 kV line 4.8 % 26,286 - (2,086) 24,200
Bemidji-Grand Rapids 230 kV line 14.8 % 16,331 - (233) 16,098
7. Intangible Assets
The following tables summarizes our goodwill by segment as of December 31, 2020 and 2019:
(in thousands) 2020 2019
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 2020 and 2019, indicated no impairment existed as of the test date.
The following table summarizes the components of our intangible assets at December 31, 2020 and 2019:
(in thousands) Gross
Amount Accumulated
Amortization Net Carrying
Amount
December 31, 2020
Customer Relationships $ 22,491 $ 12,370 $ 10,121
Other 26 3 23
Total $ 22,517 $ 12,373 $ 10,144
December 31, 2019
Customer Relationships $ 22,491 $ 11,259 $ 11,232
Other 179 121 58
Total $ 22,670 $ 11,380 $ 11,290
Amortization expense for these intangible assets was as follows for the years ended December 31, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Amortization Expense $ 1,146 $ 1,186 $ 1,315
Estimated annual amortization expense for these intangible assets for the next five years is:
(in thousands) 2021 2022 2023 2024 2025
Estimated Amortization Expense $ 1,100 $ 1,100 $ 1,100 $ 1,100 $ 1,092
8. Leases
We lease coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling 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, 2020 and 2019 are as follows:
(in thousands) 2020 2019
Lease Cost
Operating Lease Cost $ 5,837 $ 5,371
Variable Lease Cost 1,166 1,068
Total Lease Cost $ 7,003 $ 6,439
Lease Cash Flows
Operating Cash Flows from Operating Leases $ 5,431 $ 4,893
A summary of operating lease right-of-use lease assets and lease liabilities as of December 31, 2020 and 2019 is as follows:
(in thousands) 2020 2019
Right of Use Lease Assets1
$ 19,114 $ 21,851
Lease Liabilities
Current2
4,479 4,136
Long-Term3
15,314 18,193
Total Lease Liabilities $ 19,793 $ 22,329
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 $1.4 million and $6.3 million for the years ended December 31, 2020 and 2019.
Maturities of lease liabilities as of December 31, 2020 for each of the next five years and in the aggregate thereafter are as follows:
(in thousands) Operating Leases
2021 $ 5,387
2022 4,282
2023 3,905
2024 3,376
2025 2,545
Thereafter 3,301
Total Lease Payments $ 22,796
Less: Interest 3,003
Present Value of Lease Liabilities $ 19,793
The weighted-average remaining lease term and the weighted-average discount rate as of December 31, 2020 and 2019 are as follows:
2020 2019
Weighted-Average Remaining Lease Term (in years) 5.3 6.0
Weighted-Average Discount Rate 5.45 % 5.30 %
Prior to adopting new lease accounting guidance on January 1, 2019, we accounted for operating leases by recognizing lease cost on a straight-line basis over the lease term. Lease expense for the year ended December 31, 2018 was $6.3 million.
9. Short-Term and Long-Term Borrowings
The following is a summary of our outstanding short and long-term borrowings by borrower, Otter Tail Corporation (OTC) or Otter Tail Power Company (OTP), as of December 31, 2020 and 2019:
2020 2019
(in thousands) OTC OTP Total OTC OTP Total
Short-Term Debt $ 65,166 $ 15,831 $ 80,997 $ 6,000 $ - $ 6,000
Current Maturities of Long-Term Debt 169 139,918 140,087 183 - 183
Long-Term Debt, net of current maturities 79,695 544,737 624,432 79,812 609,769 689,581
Total $ 145,030 $ 700,486 $ 845,516 $ 85,995 $ 609,769 $ 695,764
Short-Term Debt
The following is a summary of our lines of credit as of December 31, 2020 and 2019:
2020 2019
(in thousands) Line Limit Amount Outstanding Letters
of Credit Amount Available Amount Available
OTC Credit Agreement $ 170,000 $ 65,166 $ - $ 104,834 $ 164,000
OTP Credit Agreement 170,000 15,831 14,101 140,068 154,524
Total $ 340,000 $ 80,997 $ 14,101 $ 244,902 $ 318,524
Otter Tail Corporation is party to a Third Amended and Restated Credit Agreement (the OTC Credit Agreement) and OTP is party to a Second Amended and Restated Credit Agreement (the OTP Credit Agreement) both of which provide for revolving lines of credit to support operations. Borrowings may be used for working capital needs and other capital requirements, to refinance certain indebtedness and for the issuance of letters of credit in an aggregate not to exceed $40 million for the OTC Credit Agreement and $50 million for the OTP Credit Agreement. Each credit facility includes an accordion provision allowing the borrower to increase the available borrowing capacity, subject to certain terms and conditions. The borrowing capacity can be increased to $290 million for the OTC Credit Agreement and to $250 million for the OTP Credit Agreement. Each credit facility charges a variable rate of interest on outstanding balances and applies a commitment fee 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 the Prime Rate, the Federal Funds Rate or LIBOR, as selected by the borrower at the time of an advance, 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 borrower. As of December 31, 2020, the LIBOR based credit spread was 1.50% and 1.25% under the OTC Credit Agreement and OTP Credit Agreement, respectively. The weighted-average interest rate on outstanding borrowings as of December 31, 2020 and 2019 was 1.61% and 3.20%.
Each credit facility contains a number of restrictions on the borrower, including restrictions on its 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. Each credit facility also contains customary affirmative covenants, including financial covenants as further described below, and certain events of default. Each credit facility expires on October 31, 2024.
Both the OTC Credit Agreement and the OTP Credit Agreement include LIBOR as a benchmark interest rate in determining the applicable rate of interest to charge on outstanding borrowings. LIBOR is currently expected to be eliminated by January 1, 2022. Both credit agreements contain a provision to determine how interest rates will be established in the event a replacement for LIBOR has not been identified before the agreement expires. The agreements require the parties to jointly agree on an alternate rate of interest, such as the Secured Overnight Financing Rate, that gives due consideration to prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time. The parties will enter into amendments to these agreements to reflect any alternate rate of interest and other related changes to the agreements as may be applicable. If for any reason an agreement cannot be reached on an alternate rate of interest, then any borrowings under the agreements will be determined using the Prime Rate plus a margin based on the borrower's long-term debt ratings at the time of borrowing.
Long-Term Debt
The following is a summary of outstanding long-term debt by borrower as of December 31, 2020 and 2019:
(in thousands)
Entity Debt Instrument Rate Maturity 2020 2019
OTC Guaranteed Senior Notes 3.55% 12/15/26 $ 80,000 $ 80,000
OTP Series 2011A Senior Unsecured Notes 4.63% 12/01/21 140,000 140,000
OTP Series 2007B Senior Unsecured Notes 6.15% 08/20/22 30,000 30,000
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 -
OTP Series 2020B Senior Unsecured Notes 3.22% 08/20/30 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 -
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 -
OTC PACE Note 2.54% 03/18/21 169 351
Total $ 767,169 $ 692,351
Less: Current Maturities Net of Unamortized Debt Issuance Costs 140,087 183
Unamortized Long-Term Debt Issuance Costs 2,650 2,587
Total Long-Term Debt Net of Unamortized Debt Issuance Costs $ 624,432 $ 689,581
During the year ended December 31, 2020, OTP issued in a private placement pursuant to our 2019 Note Purchase Agreement, its Series 2020A, Series 2020B, Series 2020C and Series 2020D notes for aggregate proceeds of $75.0 million.
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 repayment at 100% of the principal amount so repaid, together with unpaid accrued interest and a make-whole amount, as defined. These notes also include restrictions on the borrowers, 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, 2020 for each of the next five years are as follows:
(in thousands) 2021 2022 2023 2024 2025
Debt Maturities $ 140,169 $ 30,000 $ - $ - $ -
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, 2020, OTC and OTP were in compliance with these financial covenants.
10. Pension Plan and Other Postretirement Benefits
Pension Plan
We sponsor a noncontributory funded pension plan which covers substantially all corporate employees and OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior to November 1, 2013, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under the plan. The plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced compensation in cases of retirement prior to age 62. We reserve the right to discontinue the plan, but no change or discontinuance may affect the pensions theretofore vested.
The pension plan has a trustee who is responsible for pension payments to retirees and a separate pension fund manager responsible for managing the plan's assets. An independent actuary assists us in performing the necessary actuarial valuations for the plan.
The plan assets consist of common stock and bonds of public companies, U.S. government securities, cash and cash equivalents and alternative investments. None of the plan assets are invested in common stock or debt securities of the Company.
The following table lists components of net periodic pension benefit cost for the years ended December 31, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Service Cost-Benefit Earned During the Period $ 6,621 $ 5,491 $ 6,459
Interest Cost on Projected Benefit Obligation 13,053 14,412 13,452
Expected Return on Assets (22,021) (21,297) (21,199)
Amortization of Prior Service Cost:
From Regulatory Asset - 5 16
From Other Comprehensive Income1
- 9 -
Amortization of Net Actuarial Loss:
From Regulatory Asset 8,924 4,642 7,135
From Other Comprehensive Income1
220 114 183
Net Periodic Pension Cost2
$ 6,797 $ 3,376 $ 6,046
1Corporate cost included in nonservice cost components of postretirement benefits.
2Allocation of costs:
2020 2019 2018
Service costs included in OTP capital expenditures
$ 1,842 $ 1,365 $ 1,542
Service costs included in electric operation and maintenance expenses 4,621 3,994 4,756
Service costs included in other nonelectric expenses 159 132 161
Nonservice costs capitalized 48 (526) (99)
Nonservice costs included in nonservice cost components of postretirement benefits 127 (1,589) (314)
Weighted average assumptions used to determine net periodic pension cost for the years ended December 31, 2020, 2019 and 2018:
2020 2019 2018
Discount Rate 3.47 % 4.50 % 3.90 %
Long-Term Rate of Return on Plan Assets 6.88 % 7.25 % 7.50 %
Rate of Increase in Future Compensation Level:
Participants to Age 39 4.50 % 4.50 % 4.50 %
Participants Age 40 to Age 49 3.50 % 3.50 % 3.50 %
Participants Age 50 and Older 2.75 % 2.75 % 2.75 %
The following table presents amounts recognized in the consolidated balance sheets as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Regulatory Assets:
Unrecognized Prior Service Cost $ - $ -
Unrecognized Actuarial Loss 137,500 120,592
Total Regulatory Assets $ 137,500 $ 120,592
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost $ - $ -
Unrecognized Actuarial (Gain) Loss 128 (82)
Total Accumulated Other Comprehensive Loss $ 128 $ (82)
Noncurrent Liability $ 67,718 $ 55,004
Funded status as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Accumulated Benefit Obligation $ (385,302) $ (346,723)
Projected Benefit Obligation $ (428,396) $ (384,785)
Fair Value of Plan Assets 360,678 329,781
Funded Status $ (67,718) $ (55,004)
The following table provides a reconciliation of the changes in the fair value of plan assets and the plan’s benefit obligations for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1 $ 329,781 $ 269,783
Actual Return on Plan Assets 35,474 52,640
Discretionary Company Contributions 11,200 22,500
Benefit Payments (15,777) (15,142)
Fair Value of Plan Assets at December 31 $ 360,678 $ 329,781
Estimated Asset Return 10.7 % 19.3 %
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1 $ 384,785 $ 328,442
Service Cost 6,621 5,491
Interest Cost 13,053 14,412
Benefit Payments (15,777) (15,142)
Actuarial Loss 39,714 51,582
Projected Benefit Obligation at December 31 $ 428,396 $ 384,785
Weighted average assumptions used to determine benefit obligations at December 31, 2020 and 2019:
2020 2019
Discount Rate 2.78 % 3.47 %
Rate of Increase in Future Compensation Level:
Participants to Age 39 4.50 % 4.50 %
Participants Age 40 to Age 49 3.50 % 3.50 %
Participants Age 50 and Older 2.75 % 2.75 %
The assumed long-term rate of return on plan assets is 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. We review our rate of return on plan asset assumptions annually. The assumptions are largely based on the asset category rate-of-return assumptions developed annually with our pension plan investment advisors, as well as input from actuaries who work with the pension plan and benchmarking to peer companies with similar asset allocation strategies.
Market-related value of plan assets. Our expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets.
We base actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a five-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.
Measurement Dates: 2020 2019
Net Periodic Pension Cost 2020-01-01 2019-01-01
End of Year Benefit Obligations January 1, 2020 projected to December 31, 2020 January 1, 2019 projected to December 31, 2019
Market Value of Assets 2020-12-31 2019-12-31
Cash flows. We had no minimum funding requirement as of December 31, 2020 but made discretionary plan contributions of $10.0 million in January 2021.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid out from plan assets:
(in thousands) 2021 2022 2023 2024 2025 Years 2026-2030
Benefit Payments $ 16,536 $ 17,050 $ 17,694 $ 18,298 $ 18,856 $ 100,797
The following objectives guide the investment strategy of our pension plan (the Plan):
•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 (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 Plan must be in the best interest of plan participants and their beneficiaries.
•The primary objective of the Plan is to provide a source of retirement income for its participants and beneficiaries.
•The near-term primary financial objective of the Plan is to improve the funded status of the Plan.
•A secondary financial objective is to minimize pension funding and expense volatility where possible.
The asset allocation strategy developed by the Company’s Retirement Plans Administration Committee (the Committee) is based on the current needs of the Plan and the objectives listed above. An asset/liability review is conducted annually or as often as necessary to assess the impact of various asset allocations on funded status and other financial variables. The current needs of the Plan, the overall investment objectives above, the investment preferences and risk tolerance of the Committee and the desired degree of diversification suggest the need for an investment allocation including multiple asset classes.
The asset allocation in the table below contains guideline percentages, at market value, of the total Plan invested in various asset classes. The Permitted Range is a guide and will at times not reflect the actual asset allocation as this will be dictated by market conditions, the independent actions of the Committee and/or Investment Managers and required cash flows to and from the Plan. The Permitted Range anticipates this fluctuation and provides flexibility for the Investment Managers’ portfolios to vary around the target without the need for immediate rebalancing. The Investment Manager will proactively monitor the asset allocation and will direct the purchases and sales to remain within the stated ranges.
The policy of the Plan is to invest assets in accordance with the allocations shown below:
Permitted Range
Asset Class / PBO Funded Status < 85% PBO >=85% PBO >=90% PBO >=95% PBO >=100% PBO
Equity 39% - 59% 34% - 54% 24% - 44% 14% - 34% 0% - 20%
Investment Grade Fixed Income 22% - 42% 30% - 50% 40% - 60% 53% - 73% 70% - 100%
Below Investment Grade Fixed Income1
0% - 15% 0% - 15% 0% - 15% 0% - 10% 0% - 10%
Other2
5% - 20% 5% - 20% 5% - 20% 0% - 15% 0% - 15%
1Includes (but not limited to) High Yield Bond Fund and Emerging Markets Debt funds.
2Other category may include cash, alternatives, and/or other investment strategies that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund or the SEI Energy Debt Collective Fund.
Pension plan asset allocations at December 31, 2020 and 2019, by asset category are as follows:
Asset Allocation 2020 2019
Global MGD Volatility Fund (mixed equities fund)
19.3 % 20.4 %
Large Capitalization Equity Securities 11.8 11.3
International Equity Securities 9.9 9.3
Emerging Markets Equity Fund 4.5 4.2
Small and Mid-Capitalization Equity Securities 4.5 4.1
SEI Dynamic Asset Allocation Fund 3.2 3.1
Equity Securities 53.2 52.4
Fixed-Income Securities and Cash 44.2 44.7
Other - SEI Energy Debt Collective Fund 2.6 2.9
100.0 % 100.0 %
The following table presents the pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy and assets measured using the NAV practical expedient to fair valuation as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Assets in Level 1 of the Fair Value Hierarchy $ 351,458 $ 320,241
SEI Energy Debt Collective Fund at NAV 9,220 9,540
Total Assets $ 360,678 $ 329,781
Fair Value Measurements of Pension Fund Assets: The following table presents the Company’s pension fund assets measured at fair value and included in Level 1 of the fair value hierarchy as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Global MGD Volatility Fund (mixed equities fund)
$ 69,607 $ 67,184
Large Capitalization Equity Securities Mutual Fund 42,697 37,357
International Equity Securities Mutual Funds 35,607 30,653
Small and Mid-Capitalization Equity Securities Mutual Fund 16,111 13,447
SEI Dynamic Asset Allocation Mutual Fund 11,729 10,168
Emerging Markets Equity Fund 16,146 13,792
Fixed Income Securities Mutual Funds 159,192 147,639
Cash Management - Money Market Fund 369 1
Total Assets $ 351,458 $ 320,241
The investments held by the SEI Energy Debt Collective Fund on December 31, 2020 and 2019 consist mainly of below investment grade high yielding 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). The fund’s assets are valued as of the close of business on the last business day of each calendar month and are available 30 days after the end of a calendar quarter. 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, as determined by the investment manager in its sole discretion. We review and verify the reasonableness of the year-end valuations.
Executive Survivor and Supplemental Retirement Plan (ESSRP)
The ESSRP is an unfunded nonqualified benefit plan for certain executive officers and key management employees that provides for defined benefit payments to these employees on their retirement for life or to their beneficiaries on their death. In addition, the ESSRP provides for survivor benefit payments to beneficiaries of the plan participants. On December 26, 2019, the Company’s Board of Directors amended and restated the ESSRP to provide for (i) the freezing of participation in the restoration retirement benefit component of the ESSRP and (ii) the freezing of benefit accruals under the restoration retirement benefit component of the ESSRP for all participants, except those designated as a grandfathered participant, effective December 31, 2019.
The following table lists components of net periodic pension benefit cost for the years ended December 31, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Service Cost-Benefit Earned During the Period $ 179 $ 418 $ 408
Interest Cost on Projected Benefit Obligation 1,449 1,735 1,589
Amortization of Prior Service Cost:
From Regulatory Asset - 5 20
From Other Comprehensive Income1
- 17 34
Amortization of Net Actuarial Loss:
From Regulatory Asset 93 124 206
From Other Comprehensive Income1
341 348 722
Net Periodic Pension Cost2
$ 2,062 $ 2,647 $ 2,979
1Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income.
2Allocation of costs:
2020 2019 2018
Service costs included in electric operation and maintenance expenses $ - $ 104 $ 99
Service costs included in other nonelectric expenses 179 314 309
Nonservice costs included in nonservice cost components of postretirement benefits 1,883 2,229 2,571
Weighted average assumptions used to determine net periodic pension cost for the years ended December 31, 2020, 2019 and 2018:
2020 2019 2018
Discount Rate 3.36 % 4.46 % 3.85 %
Rate of Increase in Future Compensation Level 3.50 % 3.40 % 2.92 %
The following table presents amounts recognized in the consolidated balance sheets as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Regulatory Assets:
Unrecognized Prior Service Cost $ - $ -
Unrecognized Actuarial Loss 2,681 2,170
Total Regulatory Assets $ 2,681 $ 2,170
Projected Benefit Obligation Liability - Net Amount Recognized $ (47,894) $ (43,966)
Accumulated Other Comprehensive Loss:
Unrecognized Prior Service Cost $ 1 $ 1
Unrecognized Actuarial Loss 12,030 9,170
Total Accumulated Other Comprehensive Loss $ 12,031 $ 9,171
The following table provides a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations for the years ended December 31, 2020 and 2019 and a statement of the funded status as of December 31 of both years:
(in thousands) 2020 2019
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1 $ - $ -
Actual Return on Plan Assets - -
Employer Contributions 1,505 1,475
Benefit Payments (1,505) (1,475)
Fair Value of Plan Assets at December 31 $ - $ -
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1 43,966 39,699
Service Cost 179 418
Interest Cost 1,449 1,735
Benefit Payments (1,505) (1,475)
Curtailments - (1,671)
Actuarial Loss 3,805 5,260
Projected Benefit Obligation at December 31 $ 47,894 $ 43,966
Weighted average assumptions used to determine benefit obligations at December 31, 2020 and 2019:
2020 2019
Discount Rate 2.61 % 3.36 %
Rate of Increase in Future Compensation Level: 3.00 % 3.50 %
Cash flows: The ESSRP is unfunded and has no assets; contributions are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate, are expected to be paid:
(in thousands) 2021 2022 2023 2024 2025 Years 2026-2030
Benefit Payments $ 1,575 $ 2,049 $ 2,723 $ 2,707 $ 2,645 $ 14,348
Other Postretirement Benefits
We provide a portion of health insurance benefits for retired OTP and corporate employees. The retiree health insurance benefits will be available for all corporate employees and OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior to November 1, 2010, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under the plan. To be eligible for retiree health insurance benefits the employee must be 55 years of age with a minimum of 10 years of service. There are no plan assets.
We elected to obtain post-65 prescription drug subsidies for our non-union plan participants beginning in 2020 and for our union plan participants beginning in 2021 from an employer group waiver plan. As a result, we will no longer apply for prescription drug subsidies for these participants. The net effect of these plan amendments reduced the projected benefit obligation for the plan by $20.9 million as of December 31, 2019 and $3.9 million as of December 31, 2020, respectively. The net savings from these changes will be recognized as reduction to expense over the expected remaining service period to retirement-age eligibility for active participants.
The following table lists components of net periodic postretirement benefit cost for the years ended December 31, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Service Cost-Benefit Earned During the Period $ 1,847 $ 1,286 $ 1,526
Interest Cost on Projected Benefit Obligation 2,393 3,083 2,583
Amortization of Prior Service Cost
From Regulatory Asset (4,677) - -
From Other Comprehensive Income1
(115) - -
Amortization of Net Actuarial Loss
From Regulatory Asset 4,206 1,571 1,648
From Other Comprehensive Income1
104 38 42
Net Periodic Postretirement Benefit Cost2
$ 3,758 $ 5,978 $ 5,799
Effect of Medicare Part D Subsidy $ 1,123 $ (179) $ (470)
1Corporate cost included in nonservice cost components of postretirement benefits.
2Allocation of costs:
2020 2019 2018
Service costs included in OTP capital expenditures $ 514 $ 320 $ 364
Service costs included in electric operation and maintenance expenses 1,289 935 1,124
Service costs included in other nonelectric expenses 44 31 38
Nonservice costs capitalized 532 1,167 1,020
Nonservice costs included in nonservice cost components of postretirement benefits 1,379 3,525 3,253
Weighted average assumptions used to determine net periodic postretirement benefit cost for the years ended December 31, 2020, 2019 and 2018:
2020 2019 2018
Discount Rate 3.43 % 4.44 % 3.81 %
The following table presents amounts recognized in the consolidated balance sheets as of December 31, 2020 and 2019:
(in thousands) 2020 2019
Regulatory Asset:
Unrecognized Prior Service Credit $ (19,579) (20,363)
Unrecognized Net Actuarial Loss (Gain) 32,238 $ 35,322
Net Regulatory Asset $ 12,659 $ 14,959
Projected Benefit Obligation Liability - Net Amount Recognized $ (70,185) $ (71,437)
Accumulated Other Comprehensive (Income) Loss:
Unrecognized Prior Service Credit $ (386) (501)
Unrecognized Net Actuarial Loss (Gain) 21 184
Accumulated Other Comprehensive (Income) Loss: $ (365) $ (317)
The following table provides a reconciliation of the changes in the fair value of plan assets and the plan’s projected benefit obligations and accrued postretirement benefit cost for the years ended December 31, 2020 and 2019:
(in thousands) 2020 2019
Reconciliation of Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1 $ - $ -
Actual Return on Plan Assets - -
Company Contributions 2,662 2,757
Benefit Payments (Net of Medicare Part D Subsidy) (6,694) (7,164)
Participant Premium Payments 4,032 4,407
Fair Value of Plan Assets at December 31 $ - $ -
Reconciliation of Projected Benefit Obligation:
Projected Benefit Obligation at January 1 $ 71,437 $ 71,561
Service Cost (Net of Medicare Part D Subsidy) 1,847 1,286
Interest Cost (Net of Medicare Part D Subsidy) 2,393 3,083
Benefit Payments (Net of Medicare Part D Subsidy) (6,694) (7,164)
Participant Premium Payments 4,032 4,407
Plan Amendments (3,891) (20,864)
Actuarial Loss 1,061 19,128
Projected Benefit Obligation at December 31 $ 70,185 $ 71,437
Reconciliation of Accrued Postretirement Cost:
Accrued Postretirement Cost at January 1 $ (56,795) $ (53,574)
Expense (3,758) (5,978)
Net Company Contribution 2,662 2,757
Accrued Postretirement Cost at December 31 $ (57,891) $ (56,795)
Weighted average assumptions used to determine benefit obligations at December 31, 2020 and 2019:
2020 2019
Discount Rate 2.75 % 3.43 %
Assumed healthcare cost-trend rates as of December 31, 2020 and 2019:
2020 2019
Healthcare Cost-Trend Rate Assumed for Next Year 6.44 % 6.72 %
Rate to Which the Cost-Trend Rate is Assumed to Decline 4.50 % 4.50 %
Year the Rate Reaches the Ultimate Trend Rate 2038 2038
Measurement Dates: 2020 2019
Net Periodic Postretirement Benefit Cost 2020-01-01 2019-01-01
End of Year Benefit Obligations January 1, 2020 projected to December 31, 2020 January 1, 2019 projected to December 31, 2019
Cash flows: The following benefit payments, which reflect expected future service, as appropriate, net of participant premium payments, are expected to be paid:
(in thousands) 2021 2022 2023 2024 2025 Years 2026-2030
Benefit Payments $ 2,825 $ 2,955 $ 3,079 $ 3,199 $ 3,295 $ 16,893
401K Plan
We sponsor a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans totaled $5.3 million for 2020, $5.3 million for 2019 and $4.5 million for 2018.
11. Asset Retirement Obligations (AROs)
We have recognized ARO's related to our coal-fired generation plants, natural gas combustion turbine 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.
A reconciliation of the carrying amounts of AROs for the years ended December 31, 2020 and 2019 is as follows:
(in thousands) 2020 2019
Beginning Balance $ 12,656 $ 9,117
New Obligations Recognized 8,062 -
Adjustments Due to Revisions in Cash Flow Estimates 3,110 3,099
Accrued Accretion 570 440
Settlements (577) -
Ending Balance $ 23,821 $ 12,656
The new AROs recognized during the year ended December 31, 2020 arise from obligations associated with our Merricourt wind farm and Astoria Station natural gas plant.
12. Income Taxes
Income before income taxes for the years ended December 31, 2020, 2019 and 2018 arose in its entirety from domestic earnings. The provision for income taxes charged to income for the years ended December 31, 2020, 2019 and 2018 consisted of the following:
(in thousands) 2020 2019 2018
Current
Federal Income Taxes $ 4,881 $ 5,156 $ 4,960
State Income Taxes 2,415 1,333 1,395
Deferred
Federal Income Taxes 11,450 8,859 8,065
State Income Taxes 3,751 3,167 4,410
Tax Credits
Production Tax Credits (1,250) - (3,111)
North Dakota Wind Tax Credit Amortization, Net of Federal Taxes (1,033) (1,033) (1,033)
Investment Tax Credit Amortization (8) (41) (98)
Total $ 20,206 $ 17,441 $ 14,588
The reconciliation of the statutory federal income tax rate to our effective tax rate for each of the years ended December 31, 2020, 2019 and 2018 is as follows:
2020 2019 2018
Federal Statutory Rate 21.0 % 21.0 % 21.0 %
Increases (Decreases) in Tax from:
State Taxes on Income, Net of Federal Tax 4.0 3.4 5.3
Differences Reversing in Excess of Federal Rates (3.6) (3.2) (3.6)
Production Tax Credits (PTCs) (1.1) - (3.2)
North Dakota Wind Tax Credit Amortization, Net of Federal Taxes (0.9) (1.0) (1.1)
Allowance for Equity Funds Used During Construction (0.7) (0.5) (0.4)
Corporate-Owned Life Insurance (0.6) (0.7) -
Excess Tax Deduction on Stock Awards (0.4) (0.7) (0.7)
Other, Net (0.3) (1.6) (2.3)
Effective Tax Rate 17.4 % 16.7 % 15.0 %
The eligibility period to earn federal PTCs expired for certain of our wind farms in 2018. In 2020, we began to generate PTCs from our Merricourt wind farm placed in service in the fourth quarter of the year.
Deferred tax assets and liabilities were composed of the following on December 31, 2020 and 2019:
(in thousands) 2020 2019
Deferred Tax Assets
Benefit Liabilities $ 41,292 $ 38,130
Retirement Benefits Liabilities 40,650 36,206
Tax Credit Carryforward 35,132 48,910
Regulatory Tax Liability 33,124 35,700
Cost of Removal 25,920 25,604
Differences Related to Property 7,486 6,979
Net Operating Loss Carryforward 1,379 1,475
Other 3,423 6,077
Valuation Allowance (800) (800)
Total Deferred Tax Assets $ 187,606 $ 198,281
Deferred Tax Liabilities
Differences Related to Property $ (271,064) $ (268,495)
Retirement Benefits Regulatory Asset (40,650) (36,206)
Excess Tax Over Book Pension (18,696) (17,556)
Other (10,572) (7,965)
Total Deferred Tax Liabilities $ (340,982) $ (330,222)
Deferred Income Taxes $ (153,376) $ (131,941)
Schedule of expiration of tax credits and tax net operating losses available as of December 31, 2020:
(in thousands) Amount 2022-2032 2033-2038 2039-2043
Federal Tax Credits $ 10,440 $ - $ 7,896 $ 2,544
State Net Operating Losses 1,729 1,729 - -
State Tax Credits 30,509 - 1,002 29,507
The following table summarizes the activity for unrecognized tax benefits for the years ended December 31, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Balance on January 1 $ 1,488 $ 1,282 $ 684
Increases (decreases) for tax positions taken during a prior period (178) 37 6
Increases for tax positions taken during the current period 175 339 778
Decreases due to settlements with taxing authorities (575) - -
Decreases as a result of a lapse of applicable statutes of limitations (139) (170) (186)
Balance on December 31 $ 771 $ 1,488 $ 1,282
The balance of unrecognized tax benefits as of December 31, 2020 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2020 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. There was no amount accrued for interest on tax uncertainties as of December 31, 2020.
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2020, with limited exceptions, we are no longer subject to examinations by taxing authorities for tax years prior to 2017 for federal and North Dakota income taxes and prior to 2015 for Minnesota state income taxes.
13. Commitments and Contingencies
Commitments
Construction and Other Purchase Commitments: At December 31, 2020 OTP had commitments under contracts, including its share of construction program and other commitments, extending into 2022 of approximately $40 million. OTP’s other commitments charged to rent expense totaled $0.1 million, $0.3 million and $0.3 million in 2020, 2019 and 2018, respectively.
On October 1, 2019 T.O. Plastics entered into a six-year resin supply agreement that commenced on January 1, 2020. Under this resin supply agreement, there are no specified delivery volumes, rather, T.O. Plastics is required to purchase all of a specified class of regrind resin delivered by the supplier at a periodically negotiated price per pound. Based on current forecasted production levels, T.O. Plastics anticipates the quantity of resin delivered under the supply agreement will not exceed its requirements over the six-year term of the supply agreement or exceed the market cost of alternative sources of the resin. T.O. Plastics estimates it will pay the supplier approximately $1.9 million annually under this agreement.
Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts: OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2044. OTP also has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP’s current coal purchase agreements for Big Stone Plant expire at the end of 2022. OTP has an agreement with Peabody COALSALES, LLC for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2022. There is no fixed minimum purchase requirement under this agreement but all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement. OTP has an all-requirements agreement with Navajo Transitional Energy Co. for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023. There are no fixed minimum purchase requirements under this agreement.
OTP Land Easements: OTP has commitments to make future payments for land easements not classified as leases, extending into 2050 of approximately $36.7 million. Land easement payments charged to rent expense totaled $1.3 million, $0.6 million and $0.6 million in 2020, 2019 and 2018, respectively.
Our construction program and other commitments and commitments under capacity and energy agreements, coal purchase and coal delivery contracts and land easements as of December 31, 2020, are as follows:
(in thousands) Construction Program
and Other Commitments Capacity and Energy
Requirements Coal Purchase
Commitments Land
Easement
Payments
2021 $ 31,195 $ 16,280 $ 22,935 $ 1,900
2022 957 11,854 22,793 1,361
2023 233 11,854 23,955 1,386
2024 240 11,828 24,369 1,410
2025 247 11,784 25,103 1,436
Beyond 2025 6,951 120,756 454,020 29,202
Total $ 39,823 $ 184,356 $ 573,175 $ 36,695
Contingencies
FERC ROE: In November 2013 and February 2015, customers filed complaints with 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. The November 2020 opinion is subject to judicial review. We have deferred recognition and recorded a refund liability of $3.4 million as of December 31, 2020. This refund liability reflects our best estimate of required refunds to customers once all regulatory and judicial proceedings are finalized.
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 of 2018 and 2028, with state implementation plans to be submitted to the EPA by July 31, 2021.
Coyote Station, OTP's jointly-owned coal-fired power plant, is subject to assessment under the North Dakota state implementation plan of the second assessment period of the RHR. We cannot predict with certainty the impact the state implementation plan may have on our business until the plan is finalized and adopted. 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 a required early retirement of, or the sale of our interest in, Coyote Station. We cannot estimate the 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 from customers would be subject to regulatory approval.
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, 2020, other than those relating to the RHR, will not be material.
14. Stockholders' Equity
Capital Structure
In addition to authorized and outstanding common shares, the Company has 1.5 million authorized no par value cumulated preferred shares and 1.0 million authorized no par value cumulative preference shares. No cumulative preferred or cumulative preference shares were outstanding at December 31, 2020 or 2019.
Shelf Registrations
On May 3, 2018 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company 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, which expires on May 3, 2021.
On November 8, 2019, we entered into a Distribution Agreement with KeyBanc Capital Markets Inc.(KeyBanc). Pursuant to the terms of the Distribution Agreement, we may offer and sell our common shares from time to time under an At-the-Market offering program through KeyBanc, as the distribution agent, for the offer and sale of the shares up to an aggregate sales price of $75.0 million. In 2020, we received net proceeds of $37.0 million, net of commissions paid to KeyBank of $0.5 million from the issuance of 868,484 shares under this program. In total from inception of the program through December 31, 2020, we have received proceeds of $54.4 million from the issuance of shares under this program.
On May 3, 2018, we filed a second shelf 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 (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the Plan expires on May 3, 2021. In 2020, we received proceeds of $13.4 million from the sale of 320,173 shares under this program. As of December 31, 2020, 899,859 shares remain available for purchase or issuance under the Plan.
Dividend Restrictions
Otter Tail Corporation 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 dividends paid or distributions made by our subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. 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, 2020, 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 or 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 the Company by requiring an equity-to-total-capitalization ratio between 47.5% and 58.1% based on OTP’s 2020 capital structure petition effective by order of the MPUC on July 15, 2020. As of December 31, 2020, OTP’s equity-to-total-capitalization ratio including short-term debt was 53.7% and its net assets restricted from distribution totaled approximately $634 million. Under the 2020 capital structure petition, total capitalization for OTP cannot exceed $1.7 billion.
15. 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. For purchase periods between January 1, 2018 and June 30, 2019, the purchase price was 100% of the market price at the end of each six-month purchase period. For purchase periods beginning after June 30, 2019, the purchase price is 85% of the market price at the end of each six-month purchase period. At our discretion, shares purchased under the plan can be either new issue shares or shares purchased in the open market. As of December 31, 2020, 318,101 shares were available for purchase under the plan.
We recognize the 15% discount to the fair market value of the purchased shares as stock-based compensation expense, which amounted to $0.2 million and $0.1 million for the years ended December 31, 2020 and 2019. No expense was recognized during the year ended December 31, 2018.
Share-Based Compensation Plan
The 2014 Stock Incentive Plan, which was approved by our shareholders in April 2014, authorizes the issuance of 1,900,000 common shares for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, and other stock and stock-based awards. As of December 31, 2020, 897,798 shares were available for issuance under the plan. The plan terminates on December 31, 2023.
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 $6.1 million, $5.9 million and $4.4 million for the years ended December 31, 2020, 2019 and 2018. The related income tax benefit recognized for these periods amounted to $2.1 million, $2.3 million and $1.9 million.
Restricted Stock Awards. Restricted stock awards are granted to 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 deemed 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 deemed 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, 2020:
Shares Weighted Average
Grant-Date
Fair Value
Nonvested, Beginning of Year 133,847 $ 39.70
Granted 56,500 45.97
Vested (57,773) 35.49
Forfeited (3,910) 41.12
Nonvested, End of Year 128,664 $ 44.30
The weighted-average grant date fair value of granted awards was $45.97, $48.18 and $41.39 during the years ended December 31, 2020, 2019 and 2018. The fair value of vested awards was $2.8 million, $2.4 million and $2.2 million during the years ended December 31, 2020, 2019 and 2018. As of December 31, 2020, there was $2.4 million of unrecognized compensation costs for nonvested restricted stock awards to be recognized over a weighted-average period of 1.81 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 and ii) return on equity. The awards have no voting or dividend rights during the vesting period. Vesting of the awards is accelerated in certain circumstances, including on retirement. The amount of common shares awarded on an accelerated vesting is based either on actual performance at the end of the performance period or the amount of common shares earned at target.
The grant date fair value of stock performance awards granted during the years ended December 31, 2020, 2019 and 2018 was determined using a Monte Carlo fair value simulation model incorporating the following assumptions:
2020 2019 2018
Risk-free interest rate 1.42 % 2.52 % 2.23 %
Expected term (in years) 3.00 3.00 3.00
Expected volatility 19.00 % 21.00 % 22.00 %
Dividend yield 2.80 % 3.00 % 3.20 %
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 three-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, 2020 (share amounts reflect awards at target):
Shares Weighted Average
Grant-Date
Fair Value
Nonvested, Beginning of Year 161,000 $ 36.57
Granted 55,000 47.79
Vested (52,000) 30.25
Forfeited - -
Nonvested, End of Year 164,000 $ 42.32
The weighted-average grant date fair value of granted awards was $47.79, $42.87 and $35.73 during the years ended December 31, 2020, 2019 and 2018. The fair value of vested awards was $3.4 million, $6.1 million and $4.7 million during the years ended December 31, 2020, 2019 and 2018. As of December 31, 2020, there was $0.8 million of unrecognized compensation costs of nonvested stock performance awards to be recognized over a weighted-average period of 0.57 years.
16. Earnings Per Share
The numerator used in the calculation of both basic and diluted earnings per common share is net income. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the dilutive effect of potential common shares outstanding, which consist of time and performance based stock awards and employee stock purchase plan shares.
The following includes the computation of the denominator for basic and diluted weighted-average shares outstanding for the years ended December 31, 2020, 2019 and 2018:
(in thousands) 2020 2019 2018
Weighted Average Common Shares Outstanding - Basic 40,710 39,721 39,600
Effect of Dilutive Securities:
Stock Performance Awards 116 147 212
Restricted Stock Awards 63 81 78
Employee Stock Purchase Plan Shares and Other 16 5 2
Dilutive Effect of Potential Common Shares 195 233 292
Weighted Average Common Shares Outstanding - Diluted 40,905 39,954 39,892
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, 2020, 2019 and 2018.
17. Fair Value Measurements
The following tables present our assets measured at fair value on a recurring basis as of December 31, 2020 and 2019 classified by the input method used to measure fair value:
(in thousands) Level 1 Level 2 Level 3
December 31, 2020
Investments:
Money Market Funds $ 4,075 $ - $ -
Marketable Equity Securities 1,662 - -
Corporate Debt Securities - 2,627 -
Government-Backed and Government-Sponsored Enterprises’ Debt Securities - 6,633 -
Total Assets $ 5,737 $ 9,260 $ -
December 31, 2019
Investments:
Money Market Funds $ 2,363 $ - $ -
Marketable Equity Securities 1,586 - -
Corporate Debt Securities - 2,124 -
Government-Backed and Government-Sponsored Enterprises’ Debt Securities - 6,060 -
Total Assets $ 3,949 $ 8,184 $ -
The level 2 fair value measurements for Government-Backed and Government-Sponsored Enterprises’ 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.
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, 2020 and 2019:
December 31, 2020 December 31, 2019
(in thousands) Carrying
Amount Fair Value Carrying
Amount Fair Value
Cash and Cash Equivalents $ 1,163 $ 1,163 $ 21,199 $ 21,199
Short-Term Debt (80,997) (80,997) (6,000) (6,000)
Long-Term Debt (764,519) (858,455) (689,764) (742,279)
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash Equivalents: The carrying amount approximates fair value because of the short-term maturity of those instruments.
Short-Term Debt: The carrying amount approximates fair value because the debt obligations are short-term and the 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, 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, 2020, 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, 2020.
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, 2020 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, 2020. 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, 2020, 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 Form 10-K.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.
PART III

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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 2021 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 2021 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 2021 Annual Meeting.
The Company has adopted a code of conduct 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 conduct 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 conduct 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 Committee,” “Executive Compensation,” “Pay Ratio Disclosure” and “Director Compensation” in the Company's definitive Proxy Statement for the 2021 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 2021 Annual Meeting.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information as of December 31, 2020 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:
2014 Stock Incentive Plan 314,151 (1) $ 0.00 897,798 (2)
1999 Stock Incentive Plan 541 (3) $ 0.00 - (4)
1999 Employee Stock Purchase Plan N/A 318,101 (5)
Equity compensation plans not approved by security holders - - -
Total 314,692 $ 0.00 1,215,899
(1)Includes 82,500, 83,400, and 59,477 performance-based share awards granted in 2020, 2019 and 2018, respectively, 90,885 restricted stock units outstanding as of December 31, 2020, and 718 stock units as part of the director deferred compensation program and excludes 37,776 shares of restricted stock issued under the 2014 Stock Incentive Plan.
(2)The 2014 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)Director deferred compensation program stock units under the 1999 Stock Incentive Plan.
(4)The 1999 Stock Incentive Plan provided 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. The 1999 Stock Incentive Plan expired by its terms on December 13, 2013 and no more awards may be granted thereunder.
(5)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 2021 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 2021 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) 2020 2019
Assets
Current Assets
Cash and Cash Equivalents $ - $ 4,959
Accounts Receivable 148 -
Accounts Receivable from Subsidiaries 2,734 2,144
Interest Receivable from Subsidiaries 117 117
Other 1,063 2,537
Total Current Assets 4,062 9,757
Investments in Subsidiaries 1,061,009 860,646
Notes Receivable from Subsidiaries 79,069 79,251
Deferred Income Taxes 28,793 25,505
Other Assets 40,848 36,140
Total Assets $ 1,213,781 $ 1,011,299
Liabilities and Stockholders' Equity
Current Liabilities
Short-Term Debt $ 65,166 $ 6,000
Current Maturities of Long-Term Debt 169 183
Accounts Payable to Subsidiaries 7 7
Notes Payable to Subsidiaries 134,352 89,611
Other 12,931 9,629
Total Current Liabilities 212,625 105,430
Other Noncurrent Liabilities 50,495 44,575
Commitments and Contingencies
Capitalization
Long-Term Debt, Net of Current Maturities 79,695 79,812
Common Shareholder Equity 870,966 781,482
Total Capitalization 950,661 861,294
Total Liabilities and Stockholders' Equity $ 1,213,781 $ 1,011,299
See accompanying notes to condensed financial statements.
OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF INCOME
Years Ended December 31,
(in thousands) 2020 2019 2018
Income
Equity Income in Earnings of Subsidiaries $ 106,379 $ 93,731 $ 91,446
Interest Income from Subsidiaries 2,859 3,063 2,839
Other Income 1,317 1,566 550
Total Income 110,555 98,360 94,835
Expense
Operating Expenses 14,007 10,529 9,916
Interest Charges 4,599 4,863 4,043
Interest Charges from Subsidiaries 136 306 387
Nonservice Cost Components of Postretirement Benefits 1,150 1,297 1,422
Total Expense 19,892 16,995 15,768
Income Before Income Taxes 90,663 81,365 79,067
Income Tax (Benefit) Expense (5,188) (5,482) (3,278)
Net Income $ 95,851 $ 86,847 $ 82,345
See accompanying notes to condensed financial statements.
OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOWS
Years Ended December 31,
(in thousands) 2020 2019 2018
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities $ 54,027 $ 52,263 $ 56,947
Cash Flows from Investing Activities
Investment in Subsidiaries (150,000) (34,990) (24,764)
Debt Repaid by Subsidiaries 182 1,338 774
Cash Used in Investing Activities (2,419) (257) (623)
Net Cash (Used in) Provided by Investing Activities (152,237) (33,909) (24,613)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash 125 (31) 31
Net Short-Term (Repayments) Borrowings 59,166 (3,215) 9,215
Borrowings from (Repayments to) Subsidiaries 44,741 28,985 (1,281)
Proceeds from Issuance of Common Stock 52,432 20,338 -
Common Stock Issuance Expenses (648) (577) (108)
Payments for Retirement of Capital Stock (2,069) (2,730) (3,011)
Short-Term and Long-Term Debt Issuance Expenses - (270) (164)
Payments for Retirement of Long-Term Debt (182) (172) (189)
Dividends Paid (60,314) (55,723) (53,198)
Net Cash Used in Financing Activities 93,251 (13,395) (48,705)
Net Change in Cash and Cash Equivalents (4,959) 4,959 (16,371)
Cash and Cash Equivalents at Beginning of Period 4,959 - 16,371
Cash and Cash Equivalents at End of Period $ - $ 4,959 $ -
See accompanying notes to condensed financial statements.
Otter Tail Corporation (Parent Company)
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by Reference
Otter Tail Corporation’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 Otter Tail Corporation 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 GAAP. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included in this report on Form 10-K.
Otter Tail Corporation’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 our subsidiaries as of December 31, 2020 and 2019 are as follows:
(in thousands) Accounts
Receivable Interest
Receivable Current
Notes
Receivable Long-Term
Notes
Receivable Accounts
Payable Current
Notes
Payable
December 31, 2020
Otter Tail Power Company $ 2,698 $ - $ - $ - $ 7 $ -
Northern Pipe Products, Inc. - 8 - 5,169 - 9,103
Vinyltech Corporation - 17 - 11,500 - 18,004
BTD Manufacturing, Inc. - 77 - 52,000 - 30,344
T.O. Plastics, Inc. - 15 - 10,400 - 3,101
Varistar Corporation - - - - - 73,800
Otter Tail Assurance Limited 36 - - - - -
$ 2,734 $ 117 $ - $ 79,069 $ 7 $ 134,352
December 31, 2019
Otter Tail Power Company $ 2,056 $ - $ - $ - $ 7 $ -
Northern Pipe Products, Inc. - 8 - 5,351 - 3,056
Vinyltech Corporation 4 17 - 11,500 - 15,099
BTD Manufacturing, Inc. - 77 - 52,000 - 18,474
T.O. Plastics, Inc. - 15 - 10,400 - 3,099
Varistar Corporation - - - - - 49,883
Otter Tail Assurance Limited 84 - - - - -
$ 2,144 $ 117 $ - $ 79,251 $ 7 $ 89,611
Dividends
Dividends paid to Otter Tail Corporation (the Parent) from its subsidiaries were as follows:
(in thousands) 2020 2019 2018
Cash Dividends Paid to Parent by Subsidiaries $ 55,614 $ 55,660 $ 53,134
See Otter Tail Corporation’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, 2020, 2019 and 2018:
(in thousands) Balance, January 1 Charged to Cost and Expenses Deductions1
Balance, December 31
Allowance for Credit Losses
2020 $ 1,339 $ 3,138 $ (1,262) $ 3,215
2019 1,407 986 (1,054) 1,339
2018 1,094 1,353 (1,040) 1,407
Deferred Tax Asset Valuation Allowance
2020 $ 800 $ - $ - $ 800
2019 600 200 - 800
2018 - 600 - 600
1Amounts under Allowance for Credit Losses reflect deductions to the allowance for amounts written-off, net of recoveries.
3. Exhibits
The following Exhibits are filed as part of, or incorporated by reference into, this report.
No. Description
2-A -Asset Purchase Agreement, dated as of November 16, 2016, among Otter Tail Power Company, EDF Renewable Development, Inc., Power Partners Midwest, LLC, EDF-RE US Development, LLC and Merricourt Power Partners, LLC.**/***
2-B -Turnkey Engineering, Procurement and Construction Services Agreement, dated as of November 16, 2016, between Otter Tail Power Company and EDF-RE US Development, LLC.**/***
2-C -First Amendment to Asset Purchase Agreement and Turnkey Engineering, Procurement and Construction Services Agreement dated June 11, 2019, with EDF Renewables Development, Inc., f/k/a, EDF Renewable Development, Inc., Power Partners Midwest, LLC, EDF-RE US Development, LLC and Merricourt Power Partners, LLC.***
3-A -Restated Articles of Incorporation.
3-B -Restated Bylaws.
4-A -Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein.
4-A-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.
4-A-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.
4-A-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.
4-B -Third Amended and Restated Credit Agreement dated as of October 29, 2012 among Otter Tail Corporation, the Banks named therein, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, KeyBank National Association, as Documentation Agent, U.S. Bank National Association, as administration agent for the Banks and U.S. Bank National Association, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Runners.
4-B-1 -First Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West and Union Bank, N.A., as Banks.
4-B-2 -Second Amendment to Third Amended and Restated Credit Agreement, dated as of November 3, 2014, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-B-3 -Third Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-B-4 -Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-B-5 -Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2017, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-B-6 -Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2018, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank.
4-B-7 -Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2019, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Wells Fargo Bank, National Association, as a Bank.
4-C -Second Amended and Restated Credit Agreement dated as of October 29, 2012 among Otter Tail Power Company, the Banks named therein, JPMorgan Chase Bank, N.A. and Bank of America, N.A., as Co-Syndication Agents, KeyBank National Association and CoBank, ACB, as Co-Documentation Agents, U.S. Bank National Association, as administrative agent for the Banks, and U.S. Bank National Association, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers and Joint Book Runners.
4-C-1 -First Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2013, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association and Union Bank, N.A., as Banks.
4-C-2 -Second Amendment to Second Amended and Restated Credit Agreement, dated as of November 3, 2014, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-C-3 -Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
No. Description
4-C-4 -Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2016, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-C-5 -Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2017, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-C-6 -Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2018, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank.
4-C-7 -Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2019, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association, as a Bank.
4-D -Note Purchase Agreement, dated as of July 29, 2011, between Otter Tail Power Company and the Purchasers named therein.
4-E -Note Purchase Agreement dated as of August 14, 2013 between Otter Tail Power Company and the Purchasers named therein.
4-F -Note Purchase Agreement dated as of September 23, 2016 between Otter Tail Corporation and the Purchasers named therein.
4-G -Note Purchase Agreement dated as of November 14, 2017 between Otter Tail Power Company and the Purchasers named therein.
4-H -Note Purchase Agreement dated as of September 12, 2019 between Otter Tail Power Company and the Purchasers named therein.
4-I -Description of Securities
10-A -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-A-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-A-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-A-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-A-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-A-5 -Supplemental Agreement No. 4 to Agreement for Sharing Ownership of Big Stone Plant (dated as of April 24, 2003).
10-A-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-B -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-C -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-C-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-C-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-C-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-C-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-C-5 -Amendment, dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-C-6 -Amendment, dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1.
10-D -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-D-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-D-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-E -Wind Energy Purchase Agreement dated May 9, 2013 between Otter Tail Power Company and Ashtabula Wind III, LLC.**
10-F-1 -Deferred Compensation Plan for Directors, as amended.*
No. Description
10-F-1a -First Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*
10-F-1b -Second Amendment of Deferred Compensation Plan for Directors (2003 Restatement), as amended.*
10-F-2 -Executive Survivor and Supplemental Retirement Plan (2020 Restatement).*
10-F-3 -Nonqualified Retirement Plan (2011 Restatement).*
10-F-4 -1999 Employee Stock Purchase Plan, As Amended (2016).
10-F-5 -1999 Stock Incentive Plan, As Amended (2006).*
10-F-6 -2014 Executive Annual Incentive Plan.*
10-F-7 -Otter Tail Corporation 2014 Stock Incentive Plan.*
10-F-8 -Summary of Non-Employee Director Compensation (2016).*
10-F-9 -Form of Restricted Stock Unit Award Agreement (Executives).*
10-F-10 -Form of Restricted Stock Unit Award Agreement (Legacy).*
10-F-11 -Form of Restricted Stock Award Agreement for Directors.*
10-F-12 -Otter Tail Corporation Executive Restoration Plus Plan, as Amended and Restated.*
10-F-12a -First Amendment of Otter Tail Corporation Executive Restoration Plus Plan.*
10-F-12b -Second Amendment of Otter Tail Corporation Executive Restoration Plus Plan.*
10-F-13 -Summary of Non-Employee Director Compensation (2018).*
10-F-14 -Form of 2018 Performance Award Agreement (Executives).*
10-F-15 -Form of 2018 Performance Award Agreement (Legacy).*
10-F-16 -Form of 2018 Restricted Stock Award Agreement for Directors.*
10-F-17 -Summary of Non-Employee Director Compensation (2019).*
10-G -Distribution Agreement dated November 8, 2019, between Otter Tail Corporation and KeyBanc Capital Markets Inc.
10-H -Executive Employment Agreement, Kevin Moug.*
10-I-1 -Change in Control Severance Agreement, Kevin G. Moug.*
10-I-2 -Change in Control Severance Agreement, Chuck MacFarlane.*
10-I-3 -Change in Control Severance Agreement, Timothy Rogelstad.*
10-I-4 -Change in Control Severance Agreement, Paul Knutson.*
10-I-5 -Change in Control Severance Agreement, John Abbott.*
10-I-6 -Change in Control Severance Agreement, Jennifer Smestad.*
10-J -Otter Tail Corporation Executive Severance Plan.*
21-A -Subsidiaries of Registrant.
23-A -Consent of Deloitte & Touche LLP.
24-A -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.
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.
***Certain information has been omitted pursuant to Item 601(b)(2) of Regulation S-K. 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.